Sempra (SRE) 10-K 27 Feb 18 2017 FY Annual report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 22, 2018	Jun. 30, 2017
Document And Entity Information [Line Items]
Entity Registrant Name	Sempra Energy
Entity Central Index Key	1,032,208
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Filer Category	Large Accelerated Filer
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		255,324,212
Entity Public Float			$ 28,300
Trading Symbol	SRE
San Diego Gas and Electric Company [Member]
Document And Entity Information [Line Items]
Entity Public Float			0
Southern California Gas Company [Member]
Document And Entity Information [Line Items]
Entity Public Float			$ 0

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets, Current [Abstract]
Cash and cash equivalents	$ 288	$ 349	[1]
Restricted cash	62	66	[1]
Accounts receivable – trade, net	1,307	1,390	[1]
Accounts receivable – other, net	277	164	[1]
Due from unconsolidated affiliates	37	26	[1]
Income taxes receivable	110	43	[1]
Inventories	307	258	[1]
Regulatory assets	325	348	[1]
Fixed-price contracts and other derivatives	66	83	[1]
Greenhouse gas allowances	299	40	[1]
Assets held for sale	127	201	[1]
Other	136	142	[1]
Total current assets	3,341	3,110	[1]
Other Assets [Abstract]
Restricted cash	14	10	[1]
Due from unconsolidated affiliates	598	201	[1]
Regulatory assets	1,517	3,414	[1]
Nuclear decommissioning trusts	1,033	1,026	[1]
Investments	2,527	2,097	[1]
Goodwill	2,397	2,364	[1]
Other intangible assets	596	548	[1]
Dedicated assets in support of certain benefit plans	455	430	[1]
Insurance receivable for Aliso Canyon costs	418	606	[1]
Deferred income taxes	170	234	[1]
Greenhouse gas allowances	93	295	[1]
Sundry	792	520	[1]
Total other assets	10,610	11,745	[1]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment	48,108	43,624	[1]
Less accumulated depreciation and amortization	(11,605)	(10,693)	[1]
Property, plant and equipment, net	36,503	32,931	[1]
Total assets	50,454	47,786	[1]
Liabilities, Current [Abstract]
Short-term debt	1,540	1,779	[1]
Accounts payable – trade	1,350	1,346	[1]
Accounts payable – other	173	130	[1]
Due to unconsolidated affiliates	7	11	[1]
Dividends and interest payable	342	319	[1]
Accrued compensation and benefits	439	409	[1]
Regulatory liabilities	109	122	[1]
Current portion of long-term debt	1,427	913	[1]
Fixed-price contracts and other derivatives	109	83	[1]
Customer deposits	162	158	[1]
Reserve for Aliso Canyon costs	84	53	[1]
Greenhouse gas obligations	299	40	[1]
Liabilities held for sale	49	47	[1]
Other	545	517	[1]
Total current liabilities	6,635	5,927	[1]
Long-term debt	16,445	14,429	[1]
Deferred Credits and Other Liabilities [Abstract]
Customer advances for construction	150	152	[1]
Due to unconsolidated affiliates	35	0	[1]
Pension and other postretirement benefit plan obligations, net of plan assets	1,148	1,208	[1]
Deferred income taxes	2,767	3,745	[1]
Deferred investment tax credits	28	28	[1]
Regulatory liabilities	3,922	2,876	[1]
Asset retirement obligations	2,732	2,431	[1]
Fixed-price contracts and other derivatives	316	405	[1]
Greenhouse gas obligations	0	171	[1]
Deferred credits and other	1,136	1,173	[1]
Total deferred credits and other liabilities	12,234	12,189	[1]
Commitments and contingencies (Note 15)			[1]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Preferred stock	0	0	[1]
Common stock	3,149	2,982	[1]
Retained earnings	10,147	10,717	[1]
Accumulated other comprehensive income (loss)	(626)	(748)	[1]
Total shareholders’ equity	12,670	12,951	[1]
Preferred stock of subsidiary	20	20	[1]
Other noncontrolling interests	2,450	2,270	[1]
Total equity	15,140	15,241	[1]
Total liabilities and equity	50,454	47,786	[1]
San Diego Gas and Electric Company [Member]
Assets, Current [Abstract]
Cash and cash equivalents	12	8	[1]
Restricted cash	6	11	[1]
Accounts receivable – trade, net	362	354	[1]
Accounts receivable – other, net	79	17	[1]
Due from unconsolidated affiliates	0	4	[1]
Income taxes receivable	0	122	[1]
Inventories	105	80	[1]
Regulatory assets	316	340	[1]
Prepaid expenses	58	59	[1]
Fixed-price contracts and other derivatives	42	58	[1]
Greenhouse gas allowances	116	16	[1]
Other	4	3	[1]
Total current assets	1,100	1,072	[1]
Other Assets [Abstract]
Restricted cash	11	1	[1]
Regulatory assets	451	2,012	[1]
Nuclear decommissioning trusts	1,033	1,026	[1]
Greenhouse gas allowances	83	182	[1]
Sundry	328	176	[1]
Total other assets	1,906	3,397	[1]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment	19,787	17,844	[1]
Less accumulated depreciation and amortization	(4,949)	(4,594)	[1]
Property, plant and equipment, net	14,838	13,250	[1]
Total assets	17,844	17,719	[1]
Liabilities, Current [Abstract]
Short-term debt	253	0	[1]
Accounts payable – trade	501	460	[1]
Due to unconsolidated affiliates	40	15	[1]
Interest payable	41	40	[1]
Accrued compensation and benefits	122	121	[1]
Regulatory liabilities	18	0	[1]
Accrued franchise fees	59	43	[1]
Current portion of long-term debt	220	191	[1]
Fixed-price contracts and other derivatives	60	61	[1]
Asset retirement obligations	77	79	[1]
Customer deposits	69	76	[1]
Greenhouse gas obligations	116	16	[1]
Other	46	66	[1]
Total current liabilities	1,622	1,168	[1]
Long-term debt	5,335	4,658	[1]
Deferred Credits and Other Liabilities [Abstract]
Customer advances for construction	57	52	[1]
Pension and other postretirement benefit plan obligations, net of plan assets	182	232	[1]
Deferred income taxes	1,530	2,829	[1]
Deferred investment tax credits	18	16	[1]
Regulatory liabilities	2,225	1,725	[1]
Asset retirement obligations	762	751	[1]
Fixed-price contracts and other derivatives	153	189	[1]
Greenhouse gas obligations	0	72	[1]
Deferred credits and other	334	349	[1]
Total deferred credits and other liabilities	5,261	6,215	[1]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Preferred stock	0	0	[1]
Common stock	1,338	1,338	[1]
Retained earnings	4,268	4,311	[1]
Accumulated other comprehensive income (loss)	(8)	(8)	[1]
Total shareholders’ equity	5,598	5,641	[1]
Other noncontrolling interests	28	37	[1]
Total equity	5,626	5,678	[1]
Total liabilities and equity	17,844	17,719	[1]
Southern California Gas Company [Member]
Assets, Current [Abstract]
Cash and cash equivalents	8	12	[1]
Accounts receivable – trade, net	517	608	[1]
Accounts receivable – other, net	90	77	[1]
Due from unconsolidated affiliates	4	8	[1]
Income taxes receivable	10	2	[1]
Inventories	124	58	[1]
Regulatory assets	9	8	[1]
Greenhouse gas allowances	179	24	[1]
Other	38	39	[1]
Total current assets	979	836	[1]
Other Assets [Abstract]
Regulatory assets	983	1,331	[1]
Insurance receivable for Aliso Canyon costs	418	606	[1]
Greenhouse gas allowances	9	109	[1]
Sundry	364	290	[1]
Total other assets	1,774	2,336	[1]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment	16,772	15,344	[1]
Less accumulated depreciation and amortization	(5,366)	(5,092)	[1]
Property, plant and equipment, net	11,406	10,252	[1]
Total assets	14,159	13,424	[1]
Liabilities, Current [Abstract]
Short-term debt	116	62	[1]
Accounts payable – trade	502	481	[1]
Accounts payable – other	93	74	[1]
Due to unconsolidated affiliates	35	28	[1]
Accrued compensation and benefits	151	150	[1]
Regulatory liabilities	91	122	[1]
Current portion of long-term debt	501	0	[1]
Customer deposits	89	76	[1]
Reserve for Aliso Canyon costs	84	53	[1]
Greenhouse gas obligations	179	24	[1]
Other	205	171	[1]
Total current liabilities	2,046	1,241	[1]
Long-term debt	2,485	2,982	[1]
Deferred Credits and Other Liabilities [Abstract]
Customer advances for construction	92	99	[1]
Pension obligation, net of plan assets	789	762	[1]
Deferred income taxes	995	1,709	[1]
Deferred investment tax credits	10	12	[1]
Regulatory liabilities	1,697	1,151	[1]
Asset retirement obligations	1,885	1,616	[1]
Greenhouse gas obligations	0	96	[1]
Deferred credits and other	253	246	[1]
Total deferred credits and other liabilities	5,721	5,691	[1]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Preferred stock	22	22	[1]
Common stock	866	866	[1]
Retained earnings	3,040	2,644	[1]
Accumulated other comprehensive income (loss)	(21)	(22)	[1]
Total shareholders’ equity	3,907	3,510	[1]
Total equity	3,907	3,510
Total liabilities and equity	$ 14,159	$ 13,424	[1]
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parentheticals) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, plant and equipment, net related to VIE	$ 321	$ 354
Long term debt related to VIE	$ 284	$ 293
Stockholders' Equity Attributable to Parent [Abstract]
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, shares authorized	750,000,000	750,000,000
Common stock, shares outstanding	251,358,977	250,152,514
Common stock par value (in dollars per share)	$ 0	$ 0
San Diego Gas and Electric Company [Member]
Property, plant and equipment, net related to VIE	$ 321	$ 354
Long term debt related to VIE	$ 284	$ 293
Stockholders' Equity Attributable to Parent [Abstract]
Preferred stock, shares authorized	45,000,000	45,000,000
Preferred stock, shares outstanding	0
Preferred stock, shares issued	0	0
Common stock, shares authorized	255,000,000	255,000,000
Common stock, shares outstanding	117,000,000	117,000,000
Common stock par value (in dollars per share)	$ 0	$ 0
Southern California Gas Company [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Preferred stock, shares authorized	11,000,000	11,000,000
Preferred stock, shares outstanding	1,000,000	1,000,000
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares outstanding	91,000,000	91,000,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Regulated and Unregulated Operating Revenue [Abstract]
Utilities	$ 9,776	$ 9,261		$ 9,254
Energy-related businesses	1,431	922		977
Total revenues	11,207	10,183		10,231
Utilities [Abstract]
Cost of electric fuel and purchased power	(2,281)	(2,188)		(2,136)
Cost of natural gas	(1,190)	(1,067)		(1,134)
Energy-related businesses [Abstract]
Cost of natural gas, electric fuel and purchased power	(339)	(277)		(335)
Other cost of sales	(24)	(322)		(148)
Operation and maintenance	(3,117)	(2,970)		(2,886)
Depreciation and amortization	(1,490)	(1,312)	[1]	(1,250)	[1]
Franchise fees and other taxes	(436)	(426)		(423)
Write-off of wildfire regulatory asset	(351)	0	[1]	0	[1]
Impairment losses	(72)	(153)	[1]	(9)	[1]
Plant closure adjustment	0	0		26
Gain on sale of assets	3	134		70
Operating expenses
Impairment losses	72	153	[1]	9	[1]
Write-off of wildfire regulatory asset	351	0	[1]	0	[1]
Equity earnings, before income tax	34	6		104
Remeasurement of equity method investment	0	617		0
Other income, net	254	132		126
Interest income	46	26		29
Interest expense	(659)	(553)		(561)
Income before income taxes	1,585	1,830		1,704
Income tax (expense) benefit	(1,276)	(389)		(341)
Equity earnings, net of income tax	42	78		85
Net income	351	1,519	[1]	1,448	[1]
(Earnings) losses attributable to noncontrolling interest	(94)	(148)		(98)
Preferred dividends of subsidiary	(1)	(1)		(1)
Net income/Earnings	$ 256	$ 1,370		$ 1,349
Earnings Per Share, Basic [Abstract]
Basic earnings per common share (in dollars per share)	$ 1.02	$ 5.48		$ 5.43
Weighted-average number of shares outstanding, basic	251,545	250,217		248,249
Earnings Per Share, Diluted [Abstract]
Diluted earnings per common share (in dollars per share)	$ 1.01	$ 5.46		$ 5.37
Weighted-average number of shares outstanding, diluted	252,300	251,155		250,923
San Diego Gas and Electric Company [Member]
Operating revenues
Electric	$ 3,935	$ 3,754		$ 3,719
Natural gas	541	499		500
Total operating revenues	4,476	4,253		4,219
Energy-related businesses [Abstract]
Write-off of wildfire regulatory asset	(351)	0	[1]	0	[1]
Operating expenses
Cost of electric fuel and purchased power	1,293	1,187		1,151
Cost of natural gas	164	127		153
Operation and maintenance	1,020	1,048		1,017
Depreciation and amortization	670	646	[1]	604	[1]
Franchise fees and other taxes	265	255		262
Write-off of wildfire regulatory asset	351	0	[1]	0	[1]
Plant closure adjustment	0	0	[1]	(26)	[1]
Total operating expenses	3,763	3,263		3,161
Operating income	713	990		1,058
Other income, net	66	50		36
Interest expense	(203)	(195)		(204)
Income before income taxes	576	845		890
Income tax (expense) benefit	(155)	(280)		(284)
Net income	421	565	[1]	606	[1]
(Earnings) losses attributable to noncontrolling interest	(14)	5		(19)
Earnings attributable to common shares	407	570		587
Southern California Gas Company [Member]
Operating revenues
Total operating revenues	3,785	3,471		3,489
Energy-related businesses [Abstract]
Impairment losses	0	(22)		(9)
Operating expenses
Cost of natural gas	1,025	891		921
Operation and maintenance	1,479	1,385		1,361
Depreciation and amortization	515	476		461
Franchise fees and other taxes	144	140		129
Impairment losses	0	22		9
Total operating expenses	3,163	2,914		2,881
Operating income	622	557		608
Other income, net	36	32		30
Interest income	1	1		4
Interest expense	(102)	(97)		(84)
Income before income taxes	557	493		558
Income tax (expense) benefit	(160)	(143)		(138)
Net income	397	350		420
Preferred dividend requirements	(1)	(1)		(1)
Earnings attributable to common shares	$ 396	$ 349		$ 419
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Net income	$ 351	$ 1,519	[1]	$ 1,448	[1]
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Total other comprehensive income (loss)	142	52		(334)
Preferred dividends of subsidiary	(1)	(1)		(1)
Pretax amount [Member]
Net income	1,533	1,760		1,691
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustments	107	42		(260)
Financial instruments	2	(6)		(80)
Pension and other postretirement benefits	20	(13)		(3)
Total other comprehensive income (loss)	129	23		(343)
Comprehensive income	1,662	1,783		1,348
Preferred dividends of subsidiary	(1)	(1)		(1)
Total comprehensive income, after preferred dividends of subsidiaries	1,661	1,782		1,347
Income tax (expense) benefit [Member]
Net income	(1,276)	(389)		(341)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustments	0	0		0
Financial instruments	1	11		33
Pension and other postretirement benefits	(8)	4		1
Total other comprehensive income (loss)	(7)	15		34
Comprehensive income	(1,283)	(374)		(307)
Preferred dividends of subsidiary	0	0		0
Total comprehensive income, after preferred dividends of subsidiaries	(1,283)	(374)		(307)
Net-of-tax amount [Member]
Net income	257	1,371		1,350
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustments	107	42		(260)
Financial instruments	3	5		(47)
Pension and other postretirement benefits	12	(9)		(2)
Total other comprehensive income (loss)	122	38		(309)
Comprehensive income	379	1,409		1,041
Preferred dividends of subsidiary	(1)	(1)		(1)
Total comprehensive income, after preferred dividends of subsidiaries	378	1,408		1,040
Noncontrolling interests (after-tax) [Member]
Net income	94	148		98
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustments	8	(3)		(30)
Financial instruments	12	17		5
Pension and other postretirement benefits	0	0		0
Total other comprehensive income (loss)	20	14		(25)
Comprehensive income	114	162		73
Preferred dividends of subsidiary	0	0		0
Total comprehensive income, after preferred dividends of subsidiaries	114	162		73
Total [Member]
Net income	351	1,519		1,448
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustments	115	39		(290)
Financial instruments	15	22		(42)
Pension and other postretirement benefits	12	(9)		(2)
Total other comprehensive income (loss)	142	52		(334)
Comprehensive income	493	1,571		1,114
Preferred dividends of subsidiary	(1)	(1)		(1)
Total comprehensive income, after preferred dividends of subsidiaries	492	1,570		1,113
San Diego Gas and Electric Company [Member]
Net income	421	565	[1]	606	[1]
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Total other comprehensive income (loss)	11	10		10
San Diego Gas and Electric Company [Member] | Pretax amount [Member]
Net income	562	850		871
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments	0	0		0
Pension and other postretirement benefits	(1)			7
Total other comprehensive income (loss)	(1)	0		7
Comprehensive income	561	850		878
San Diego Gas and Electric Company [Member] | Income tax (expense) benefit [Member]
Net income	(155)	(280)		(284)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments	0	0		0
Pension and other postretirement benefits	1			(3)
Total other comprehensive income (loss)	1	0		(3)
Comprehensive income	(154)	(280)		(287)
San Diego Gas and Electric Company [Member] | Net-of-tax amount [Member]
Net income	407	570		587
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments	0	0		0
Pension and other postretirement benefits	0			4
Total other comprehensive income (loss)	0	0		4
Comprehensive income	407	570		591
San Diego Gas and Electric Company [Member] | Noncontrolling interests (after-tax) [Member]
Net income	14	(5)		19
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments	11	10		6
Pension and other postretirement benefits	0			0
Total other comprehensive income (loss)	11	10		6
Comprehensive income	25	5		25
San Diego Gas and Electric Company [Member] | Total [Member]
Net income	421	565		606
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments	11	10		6
Pension and other postretirement benefits	0			4
Total other comprehensive income (loss)	11	10		10
Comprehensive income	432	575		616
Southern California Gas Company [Member]
Net income	397	350		420
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Total other comprehensive income (loss)	1	(3)		(1)
Southern California Gas Company [Member] | Pretax amount [Member]
Net income	557	493		558
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments		1		1
Pension and other postretirement benefits	1	(6)		(2)
Total other comprehensive income (loss)	1	(5)		(1)
Comprehensive income	558	488		557
Southern California Gas Company [Member] | Income tax (expense) benefit [Member]
Net income	(160)	(143)		(138)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments		0		(1)
Pension and other postretirement benefits	0	2		1
Total other comprehensive income (loss)	0	2		0
Comprehensive income	(160)	(141)		(138)
Southern California Gas Company [Member] | Net-of-tax amount [Member]
Net income	397	350		420
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Financial instruments		1		0
Pension and other postretirement benefits	1	(4)		(1)
Total other comprehensive income (loss)	1	(3)		(1)
Comprehensive income	$ 398	$ 347		$ 419
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$ 351		$ 1,519	[1]	$ 1,448	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		1,490		1,312	[1]	1,250	[1]
Deferred income taxes and investment tax credits		1,160		217	[1]	239	[1]
Write-off of wildfire regulatory asset		351		0	[1]	0	[1]
Impairment losses		72		153	[1]	9	[1]
Plant closure adjustment		0		0	[1]	(26)	[1]
Gain on sale of assets		(3)		(134)	[1]	(70)	[1]
Equity earnings, net		(76)		(84)	[1]	(189)	[1]
Remeasurement of equity method investment		0		(617)	[1]	0	[1]
Fixed-price contracts and other derivatives		7		21	[1]	(10)	[1]
Other		149		62	[1]	66	[1]
Insurance receivable for Aliso Canyon costs		188		(281)	[1]	(325)	[1]
Changes in other assets		(214)		49	[1]	(169)	[1]
Changes in other liabilities		93		153	[1]	(24)	[1]
Changes in working capital components:
Accounts receivable		17		(42)	[1]	(99)	[1]
Income taxes receivable, net		(70)		3	[1]	39	[1]
Inventories		(49)		(20)	[1]	65	[1]
Regulatory balancing accounts		108		198	[1]	586	[1]
Other current assets		(12)		(41)	[1]	(19)	[1]
Accounts payable		83		122	[1]	(157)	[1]
Reserve for Aliso Canyon costs		31		(221)	[1]	274	[1]
Other current liabilities		(51)		(58)	[1]	10	[1]
Net change in other working capital components		57		(59)	[1]	699	[1]
Net cash provided by operating activities		3,625		2,311	[1]	2,898	[1]
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(3,949)		(4,214)	[1]	(3,156)	[1]
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired		(270)		(1,504)	[1]	(198)	[1]
Proceeds from sale of assets, net of cash sold		17		763	[1]	373	[1]
Distributions from investments		26		25	[1]	15	[1]
Purchases of nuclear decommissioning and other trust assets		(1,314)		(1,034)	[1]	(531)	[1]
Proceeds from sales by nuclear decommissioning and other trusts		1,314		1,134	[1]	577	[1]
Advances to unconsolidated affiliates		(531)		(25)	[1]	(31)	[1]
Repayments of advances to unconsolidated affiliates		9		11	[1]	74	[1]
Other		(2)		9	[1]	9	[1]
Net cash used in investing activities		(4,700)		(4,835)	[1]	(2,868)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(755)		(686)	[1]	(628)	[1]
Preferred dividends paid by subsidiary		(1)		(1)	[1]	(1)	[1]
Issuances of common stock		47		51	[1]	52	[1]
Repurchases of common stock		(15)		(56)	[1]	(74)	[1]
Issuances of debt (maturities greater than 90 days)		4,509		2,951	[1]	2,992	[1]
Payments on debt (maturities greater than 90 days)		(2,800)		(2,057)	[1]	(1,854)	[1]
(Decrease) increase in short-term debt, net		(36)		692	[1]	(622)	[1]
Advances from unconsolidated affiliates		35		0	[1]	0	[1]
Proceeds from sale of noncontrolling interests, net of $3 and $40 in offering costs, respectively		196		1,692	[1]	0	[1]
Net distributions to noncontrolling interests		(130)		(63)	[1]	(73)	[1]
Tax benefit related to share-based compensation		0		0	[1]	52	[1]
Other		(43)		(21)	[1]	(20)	[1]
Net cash provided by (used in) financing activities		1,007		2,502	[1]	(176)	[1]
Effect of exchange rate changes on cash, cash equivalents and restricted cash		7		(3)	[1]	(14)	[1]
Decrease in cash, cash equivalents and restricted cash		(61)		(25)	[1]	(160)	[1]
Cash, cash equivalents and restricted cash, January 1	[1]	425		450		610
Cash, cash equivalents and restricted cash, December 31		364		425	[1]	450	[1]
Cash and cash equivalents, January 1	[2]	349
Cash and cash equivalents, December 31		288		349	[2]
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		619		532	[1]	537	[1]
Income tax payments (refunds), net		172		160	[1]	67	[1]
Noncash acquisition of businesses:
Assets acquired, net of cash, cash equivalents and restricted cash		436		3,808	[1]	10	[1]
Value of equity method investment immediately prior to acquisition		(28)		(1,144)	[1]	0	[1]
Liabilities assumed		(261)		(1,322)	[1]	(2)	[1]
Accrued purchase price		0		0	[1]	(5)	[1]
Cash paid, net of cash, cash equivalents and restricted cash acquired		147		1,342	[1]	3	[1]
Other Noncash Investing and Financing Items [Abstract]
Accrued capital expenditures		562		626	[1]	566	[1]
Increase in capital lease obligations for investment in property, plant and equipment		504		0	[1]	24	[1]
Accrued Merger-related transaction costs		31		0	[1]	0	[1]
Financing of build-to-suit property		0		0	[1]	61	[1]
Redemption of industrial development bonds		0		0	[1]	79	[1]
Equitization of note receivable due from unconsolidated affiliate		19		0	[1]	0	[1]
Common dividends issued in stock		53		53	[1]	55	[1]
Dividends declared but not paid		214		196	[1]	180	[1]
San Diego Gas and Electric Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		421		565	[1]	606	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		670		646	[1]	604	[1]
Deferred income taxes and investment tax credits		(10)		258	[1]	195	[1]
Write-off of wildfire regulatory asset		351		0	[1]	0	[1]
Plant closure adjustment		0		0	[1]	(26)	[1]
Fixed-price contracts and other derivatives		(2)		(3)	[1]	(4)	[1]
Other		(22)		(35)	[1]	(16)	[1]
Changes in other assets		(108)		(20)	[1]	(125)	[1]
Changes in other liabilities		78		11	[1]	13	[1]
Changes in working capital components:
Accounts receivable		(76)		(31)	[1]	(10)	[1]
Due to/from affiliates, net		(10)		(19)	[1]	21	[1]
Income taxes receivable, net		136		(115)	[1]	0	[1]
Inventories		(25)		(5)	[1]	(2)	[1]
Regulatory balancing accounts		56		35	[1]	474	[1]
Other current assets		9		25	[1]	(24)	[1]
Accounts payable		75		39	[1]	(28)	[1]
Other current liabilities		4		(28)	[1]	(17)	[1]
Net cash provided by operating activities		1,547		1,323	[1]	1,661	[1]
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(1,555)		(1,399)	[1]	(1,133)	[1]
Purchases of nuclear decommissioning trust assets		(1,314)		(1,034)	[1]	(526)	[1]
Proceeds from sales by nuclear decommissioning trusts		1,314		1,134	[1]	577	[1]
Decrease (increase) in loans to affiliate, net		31		(31)	[1]	0	[1]
Other		9		6	[1]	5	[1]
Net cash used in investing activities		(1,515)		(1,324)	[1]	(1,077)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(450)		(175)	[1]	(300)	[1]
Issuances of debt (maturities greater than 90 days)		398		498	[1]	444	[1]
Payments on debt (maturities greater than 90 days)		(186)		(204)	[1]	(547)	[1]
(Decrease) increase in short-term debt, net		253		(114)	[1]	(131)	[1]
Net distributions to noncontrolling interests		(34)		(21)	[1]	(30)	[1]
Debt issuance costs		(4)		(6)	[1]	(4)	[1]
Net cash provided by (used in) financing activities		(23)		(22)	[1]	(568)	[1]
Increase (decrease) in cash, cash equivalents and restricted cash		9		(23)	[1]	16	[1]
Cash, cash equivalents and restricted cash, January 1	[1]	20		43		27
Cash, cash equivalents and restricted cash, December 31		29		20	[1]	43	[1]
Cash and cash equivalents, January 1	[2]	8
Cash and cash equivalents, December 31		12		8	[2]
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		195		187	[1]	199	[1]
Income tax payments (refunds), net		27		137	[1]	88	[1]
Other Noncash Investing and Financing Items [Abstract]
Accrued capital expenditures		217		227	[1]	191	[1]
Increase in capital lease obligations for investment in property, plant and equipment		500		0	[1]	15	[1]
Southern California Gas Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		397		350		420
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		515		476		461
Deferred income taxes and investment tax credits		137		103		127
Impairment losses		0		22		9
Other		11		(26)		(20)
Insurance receivable for Aliso Canyon costs		188		(281)		(325)
Changes in other assets		(80)		35		(91)
Changes in other liabilities		(13)		7		(7)
Changes in working capital components:
Accounts receivable		72		37		(90)
Due to/from affiliates, net		7		6		(11)
Income taxes receivable, net		(5)		(2)		8
Inventories		(66)		4		102
Regulatory balancing accounts		53		163		112
Other current assets		0		(13)		8
Accounts payable		39		36		(143)
Reserve for Aliso Canyon costs		31		(221)		274
Other current liabilities		20		(25)		46
Net cash provided by operating activities		1,306		671		880
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(1,367)		(1,319)		(1,352)
Decrease (increase) in loans to affiliate, net		0		50	[1]	(50)	[1]
Other		4		0		0
Net cash used in investing activities		(1,363)		(1,269)		(1,402)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		0		0		(50)
Preferred dividends paid		(1)		(1)		(1)
Issuances of debt (maturities greater than 90 days)		0		499		599
Payments on debt (maturities greater than 90 days)		0		(3)		0
(Decrease) increase in short-term debt, net		54		62		(50)
Debt issuance costs		0		(5)		(3)
Net cash provided by (used in) financing activities		53		552		495
Increase (decrease) in cash and cash equivalents		(4)		(46)		(27)
Cash and cash equivalents, January 1		12	[2]	58		85
Cash and cash equivalents, December 31		8		12	[2]	58
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		97		92		79
Income tax payments (refunds), net		28		41		1
Other Noncash Investing and Financing Items [Abstract]
Accrued capital expenditures		$ 208		$ 207		$ 189
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Cash Flows [Abstract]
Offering costs from sale of noncontrolling interests	$ 3	$ 40

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total		Common Stock [Member]	Retained earnings [Member]	Accumulated other comprehensive income (loss) [Member]	Shareholders' equity [Member]	Non-controlling interests [Member]	San Diego Gas and Electric Company [Member]		San Diego Gas and Electric Company [Member]Common Stock [Member]	San Diego Gas and Electric Company [Member]Retained earnings [Member]	San Diego Gas and Electric Company [Member]Accumulated other comprehensive income (loss) [Member]	San Diego Gas and Electric Company [Member]Shareholders' equity [Member]	San Diego Gas and Electric Company [Member]Non-controlling interests [Member]	Southern California Gas Company [Member]	Southern California Gas Company [Member]Preferred stock [Member]	Southern California Gas Company [Member]Common Stock [Member]	Southern California Gas Company [Member]Retained earnings [Member]	Southern California Gas Company [Member]Accumulated other comprehensive income (loss) [Member]
Beginning Balance at Dec. 31, 2014	$ 12,100		$ 2,484	$ 9,339	$ (497)	$ 11,326	$ 774	$ 4,992		$ 1,338	$ 3,606	$ (12)	$ 4,932	$ 60	$ 2,781	$ 22	$ 866	$ 1,911	$ (18)
Net income	1,448	[1]		1,350		1,350	98	606	[1]		587		587	19	420			420
Comprehensive income (loss)	(334)				(309)	(309)	(25)	10				4	4	6	(1)				(1)
Share-based compensation expense	52		52			52
Preferred stock dividends declared															(1)			(1)
Common stock dividends declared	(694)			(694)		(694)		(300)			(300)		(300)		(50)			(50)
Preferred dividends of subsidiary	(1)			(1)		(1)
Issuances of common stock	107		107			107
Repurchases of common stock	(74)		(74)			(74)
Tax benefit related to share-based compensation	52		52			52
Distributions to noncontrolling interests	(80)						(80)	(32)						(32)
Equity contributed by noncontrolling interests	3						3
Ending balance at Dec. 31, 2015	12,579		2,621	9,994	(806)	11,809	770	5,276		1,338	3,893	(8)	5,223	53	3,149	22	866	2,280	(19)
Cumulative-effect adjustment from change in accounting principle	107			107		107		23			23		23		15			15
Net income	1,519	[1]		1,371		1,371	148	565	[1]		570		570	(5)	350			350
Comprehensive income (loss)	52				38	38	14	10						10	(3)				(3)
Share-based compensation expense	52		52			52
Preferred stock dividends declared															(1)			(1)
Common stock dividends declared	(754)			(754)		(754)		(175)			(175)		(175)
Preferred dividends of subsidiary	(1)			(1)		(1)
Issuances of common stock	104		104			104
Repurchases of common stock	(56)		(56)			(56)
Sale of noncontrolling interests, net of offering costs	1,701		261		20	281	1,420
Distributions to noncontrolling interests	(65)						(65)	(23)						(23)
Equity contributed by noncontrolling interests	3						3	2						2
Ending balance at Dec. 31, 2016	15,241	[2]	2,982	10,717	(748)	12,951	2,290	5,678	[2]	1,338	4,311	(8)	5,641	37	3,510	22	866	2,644	(22)
Net income	351			257		257	94	421			407		407	14	397			397
Comprehensive income (loss)	142				122	122	20	11						11	1				1
Share-based compensation expense	82		82			82
Preferred stock dividends declared															(1)			(1)
Common stock dividends declared	(826)			(826)		(826)		(450)			(450)		(450)
Preferred dividends of subsidiary	(1)			(1)		(1)
Issuances of common stock	100		100			100
Repurchases of common stock	(15)		(15)			(15)
Sale of noncontrolling interests, net of offering costs	196						196
Distributions to noncontrolling interests	(132)						(132)	(35)						(35)
Equity contributed by noncontrolling interests	2						2	1						1
Ending balance at Dec. 31, 2017	$ 15,140		$ 3,149	$ 10,147	$ (626)	$ 12,670	$ 2,470	$ 5,626		$ 1,338	$ 4,268	$ (8)	$ 5,598	$ 28	$ 3,907	$ 22	$ 866	$ 3,040	$ (21)
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Significant Accounting Policies And Other Financial Data	SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA PRINCIPLES OF CONSOLIDATION Sempra Energy Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Energy’s principal operating units are ▪ Sempra Utilities, which includes our SDG&E, SoCalGas and Sempra South American Utilities reportable segments; and ▪ Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments. We provide descriptions of each of our segments in Note 16. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our South American utilities or the utilities in our Sempra Infrastructure operating unit. 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 Utilities,” “Sempra Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. IEnova is a separate legal entity comprised of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. IEnova’s financial results are reported in Mexico under International Financial Reporting Standards, as required by the Mexican Stock Exchange, where its shares are traded under the symbol IENOVA. Sempra Energy uses the equity method to account for investments in companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 3, 4 and 10. SDG&E SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra Energy. SoCalGas SoCalGas’ common stock is wholly owned by 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. Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively: ▪ the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs; ▪ the Consolidated Financial Statements and related Notes of SDG&E and its VIE; and ▪ the Financial Statements and related Notes of SoCalGas. Balance Sheet Reclassifications We have made certain balance sheet reclassifications at December 31, 2016 to conform to the current year presentation. Line item captions for various types of regulatory assets and liabilities have been combined or separated into four new line items: current and noncurrent regulatory assets and current and noncurrent regulatory liabilities. The details of regulatory assets and liabilities are provided in Note 14. Additionally, greenhouse gas allowances have been separated from other current assets and sundry assets and greenhouse gas obligations have been separated from other current liabilities and deferred credits and other into four new line items: current and noncurrent greenhouse gas allowances and current and noncurrent greenhouse gas obligations. These reclassifications and related disclosures had no effect on our financial position as of December 31, 2016 and are intended to provide additional clarity into the financial position of Sempra Energy, SDG&E and SoCalGas. The following tables summarize the balance sheet line items affected by these reclassifications: SEMPRA ENERGY CONSOLIDATED – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Regulatory assets $ — $ 348 Greenhouse gas allowances — 40 Regulatory balancing accounts – undercollected 259 — Other 271 142 Other assets: Greenhouse gas allowances — 295 Sundry 815 520 Current liabilities: Regulatory liabilities — 122 Greenhouse gas obligations — 40 Regulatory balancing accounts – overcollected 122 — Other 557 517 Deferred credits and other liabilities: Regulatory liabilities — 2,876 Greenhouse gas obligations — 171 Regulatory liabilities arising from removal obligations 2,697 — Deferred credits and other 1,523 1,173 SDG&E – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Regulatory assets $ 81 $ 340 Greenhouse gas allowances — 16 Regulatory balancing accounts – net undercollected 259 — Other 19 3 Other assets: Regulatory assets — 2,012 Greenhouse gas allowances — 182 Deferred taxes recoverable in rates 1,014 — Other regulatory assets 998 — Sundry 358 176 Current liabilities: Greenhouse gas obligations — 16 Other 82 66 Deferred credits and other liabilities: Regulatory liabilities — 1,725 Greenhouse gas obligations — 72 Regulatory liabilities arising from removal obligations 1,725 — Deferred credits and other 421 349 SOCALGAS – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Greenhouse gas allowances $ — $ 24 Other 63 39 Other assets: Regulatory assets — 1,331 Greenhouse gas allowances — 109 Regulatory assets arising from pension obligations 742 — Other regulatory assets 589 — Sundry 399 290 Current liabilities: Regulatory liabilities — 122 Greenhouse gas obligations — 24 Regulatory balancing accounts – net overcollected 122 — Other 195 171 Deferred credits and other liabilities: Regulatory liabilities — 1,151 Greenhouse gas obligations — 96 Regulatory liabilities arising from removal obligations 972 — Deferred credits and other 521 246 Use of Estimates in the Preparation of the Financial Statements We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates. Subsequent Events We evaluated events and transactions that occurred after December 31, 2017 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation. See Note 18 for a discussion of certain financing transactions that were completed in January 2018. EFFECTS OF REGULATION The California Utilities’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods. Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of: ▪ the nature of the event giving rise to the assessment; ▪ existing statutes and regulatory code; ▪ legal precedents; ▪ regulatory principles and analogous regulatory actions; ▪ testimony presented in regulatory hearings; ▪ regulatory orders; ▪ a commission-authorized mechanism established for the accumulation of costs; ▪ status of applications for rehearings or state court appeals; ▪ specific approval from a commission; and ▪ historical experience . Sempra Mexico’s natural gas distribution utility, Ecogas, also applies U.S. GAAP for rate-regulated utilities to its operations, including the same evaluation of probability of recovery of regulatory assets described above. We provide information concerning regulatory assets and liabilities in Notes 13 and 14. Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Revenues are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction by IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.” Sempra LNG & Midstream owned Mobile Gas in southwest Alabama and Willmut Gas in Mississippi until they were sold in September 2016, as we discuss in Note 3. Mobile Gas and Willmut Gas also prepared their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations. We discuss revenue recognition at our utilities in “Revenues” below. FAIR VALUE MEASUREMENTS We measure certain assets and liabilities at fair value on a recurring basis, primarily nuclear decommissioning and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances. These assets can include goodwill, intangible assets, equity method investments and other long-lived assets. “Fair value” is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value. We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 – Pricing inputs are quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including: ▪ quoted forward prices for commodities ▪ time value ▪ current market and contractual prices for the underlying instruments ▪ volatility factors ▪ other relevant economic measures Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E. CASH AND CASH EQUIVALENTS Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase. RESTRICTED CASH Restricted cash at Sempra Energy was $76 million at both December 31, 2017 and 2016 , and includes: ▪ for SDG&E, $17 million and $12 million at December 31, 2017 and 2016 , respectively, representing funds held by a trustee for Otay Mesa VIE to pay certain operating costs. ▪ for Sempra Mexico, $56 million and $61 million at December 31, 2017 and 2016 , respectively, primarily denominated in Mexican pesos, representing funds to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects. ▪ for Sempra Renewables, $3 million at both December 31, 2017 and 2016 , primarily representing funds held in accordance with debt agreements at our wholly owned solar project. ▪ for Sempra South American Utilities, negligible amounts at both December 31, 2017 and 2016. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported on the Consolidated Balance Sheets to the sum of such amounts reported on the Consolidated Statements of Cash Flows. RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH (Dollars in millions) At December 31, 2017 2016 Sempra Energy Consolidated: Cash and cash equivalents $ 288 $ 349 Restricted cash, current 62 66 Restricted cash, noncurrent 14 10 Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows $ 364 $ 425 SDG&E: Cash and cash equivalents $ 12 $ 8 Restricted cash, current 6 11 Restricted cash, noncurrent 11 1 Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows $ 29 $ 20 COLLECTION ALLOWANCES We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below: COLLECTION ALLOWANCES (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Allowances for collection of receivables at January 1 $ 35 $ 32 $ 34 Provisions for uncollectible accounts 16 23 20 Write-offs of uncollectible accounts (18 ) (20 ) (22 ) Allowances for collection of receivables at December 31 $ 33 $ 35 $ 32 SDG&E: Allowances for collection of receivables at January 1 $ 8 $ 9 $ 7 Provisions for uncollectible accounts 8 6 7 Write-offs of uncollectible accounts (7 ) (7 ) (5 ) Allowances for collection of receivables at December 31 $ 9 $ 8 $ 9 SoCalGas: Allowances for collection of receivables at January 1 $ 21 $ 17 $ 17 Provisions for uncollectible accounts 4 14 11 Write-offs of uncollectible accounts (9 ) (10 ) (11 ) Allowances for collection of receivables at December 31 $ 16 $ 21 $ 17 We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to collection allowances are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends. We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received. INVENTORIES The California Utilities value natural gas inventory using the LIFO method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. At December 31, 2016, SoCalGas recognized a permanent LIFO liquidation of $33 million . The California Utilities generally value materials and supplies at the lower of average cost or net realizable value. Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra LNG & Midstream value LNG inventory using the first-in first-out method. The components of inventories by segment are as follows: INVENTORY BALANCES AT DECEMBER 31 (Dollars in millions) Natural gas LNG Materials and supplies Total 2017 2016 2017 2016 2017 2016 2017 2016 SDG&E $ 4 $ 2 $ — $ — $ 101 $ 78 $ 105 $ 80 SoCalGas (1) 75 11 — — 49 47 124 58 Sempra South American Utilities — — — — 30 27 30 27 Sempra Mexico — — 7 6 2 1 9 7 Sempra Renewables — — — — 5 4 5 4 Sempra LNG & Midstream 30 79 4 3 — — 34 82 Sempra Energy Consolidated $ 109 $ 92 $ 11 $ 9 $ 187 $ 157 $ 307 $ 258 (1) At December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas storage facility leak, which we discuss in Note 15. INCOME TAXES Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC. At our other businesses, we reduce the book basis of the related asset by the amount of ITCs earned. At Sempra Renewables, PTCs are recognized in income tax expense as earned. Under the regulatory accounting treatment required for flow-through temporary differences, as discussed in Note 6, the California Utilities and Sempra Mexico recognize ▪ regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and ▪ regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers. When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more likely than not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more likely than not criterion at the largest amount of tax benefit that is greater than 50 percent likely of being realized upon its effective resolution. Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR. On December 22, 2017, the TCJA was signed into law. As a result, all cumulative undistributed earnings from non-U.S. subsidiaries were deemed repatriated and subjected to a one-time U.S. federal deemed repatriation tax. To the extent we intend to repatriate cash into the U.S., incremental U.S. state and non-U.S. withholding taxes are accrued. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries to the extent the related cumulative undistributed earnings are indefinitely reinvested. We provide additional information about income taxes in Note 6. GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS The California Utilities, Sempra Mexico and Sempra LNG & Midstream are required by California AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. At the California Utilities, many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Mexico and Sempra LNG & Midstream record the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered. RENEWABLE ENERGY CERTIFICATES RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets. Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS. The cost of RECs at SDG&E is recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations. PROPERTY, PLANT AND EQUIPMENT PP&E primarily represents the buildings, equipment and other facilities used by the Sempra Utilities to provide natural gas and electric utility services, and by the Sempra Infrastructure businesses in their operations, including construction work in progress at these operating units. PP&E also includes lease improvements and other equipment at Parent and Other, as well as property acquired under a build-to-suit lease, which we discuss further in Note 15. Our plant costs include ▪ labor ▪ materials and contract services ▪ expenditures for replacement parts incurred during a major maintenance outage of a generating plant In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP at Sempra Mexico and Sempra LNG & Midstream includes AFUDC. We discuss AFUDC below. The cost of other PP&E includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation. We discuss assets collateralized as security for certain indebtedness in Note 5. PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY (Dollars in millions) PP&E at Depreciation rates for 2017 2016 2017 2016 2015 SDG&E: Natural gas operations $ 2,186 $ 1,897 2.40 % 2.40 % 2.52 % Electric distribution 6,975 6,497 3.92 3.86 3.79 Electric transmission (1) 5,626 5,152 2.71 2.66 2.62 Electric generation (2) 2,435 1,932 4.05 4.00 3.89 Other electric (3) 1,114 1,059 5.54 5.66 5.73 Construction work in progress (1) 1,451 1,307 NA NA NA Total SDG&E 19,787 17,844 SoCalGas: Natural gas operations (4) 15,759 14,428 3.63 3.64 3.83 Other non-utility 32 34 5.28 6.55 3.95 Construction work in progress 981 882 NA NA NA Total SoCalGas 16,772 15,344 Estimated Weighted-average Other operating units and parent (5) : useful lives useful life Land and land rights 416 381 22 to 55 years (6) 33 Machinery and equipment: Utility electric distribution operations 1,751 1,519 12 to 60 years 52 Generating plants 2,242 1,874 2 to 100 years 31 LNG terminals 1,133 1,129 43 years 43 Pipelines and storage 4,408 3,242 3 to 55 years 43 Other 269 235 1 to 50 years 13 Construction work in progress 691 1,488 NA NA Other (7) 639 568 1 to 80 years 33 11,549 10,436 Total Sempra Energy Consolidated $ 48,108 $ 43,624 (1) At December 31, 2017 , includes $440 million in electric transmission assets and $29 million in construction work in progress related to SDG&E’s 92 -percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. (2) Includes capital lease assets of $757 million and $258 million at December 31, 2017 and 2016 , respectively. (3) Includes capital lease assets of $22 million and $21 million at December 31, 2017 and 2016 , respectively. (4) Includes capital lease assets of $34 million and $32 million at December 31, 2017 and 2016 , respectively. (5) Includes $145 million and $128 million at December 31, 2017 and 2016 , respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas. (6) Estimated useful lives are for land rights. (7) Includes capital lease assets of $136 million at both December 31, 2017 and 2016 , related to a build-to-suit lease. Depreciation expense is computed using the straight-line method over the asset’s estimated original composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest. Depreciation expense on our Consolidated Statements of Operations is as follows: DEPRECIATION EXPENSE (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 1,422 $ 1,236 $ 1,178 SDG&E 621 583 544 SoCalGas 514 474 459 Accumulated depreciation on our Consolidated Balance Sheets is as follows: ACCUMULATED DEPRECIATION (Dollars in millions) December 31, 2017 2016 SDG&E: Accumulated depreciation: Electric (1) $ 4,193 $ 3,873 Natural gas 756 721 Total SDG&E 4,949 4,594 SoCalGas: Accumulated depreciation of natural gas utility plant in service (2) 5,352 5,079 Accumulated depreciation – other non-utility 14 13 Total SoCalGas 5,366 5,092 Other operating units and parent and other: Accumulated depreciation – other (3) 972 755 Accumulated depreciation of utility electric distribution operations 318 252 1,290 1,007 Total Sempra Energy Consolidated $ 11,605 $ 10,693 (1) Includes accumulated depreciation for capital lease assets of $47 million and $39 million at December 31, 2017 and 2016 , respectively. Includes $241 million at December 31, 2017 related to SDG&E’s 92 -percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities. (2) Includes accumulated depreciation for capital lease assets of $33 million and $31 million at December 31, 2017 and 2016 , respectively. (3) Includes $39 million and $33 million at December 31, 2017 and 2016 , respectively, of accumulated depreciation for utility plant at Ecogas. The California Utilities finance their construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets. Pipeline projects currently under construction by Sempra Mexico and Sempra LNG & Midstream that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC. We capitalize interest costs incurred to finance capital projects. We also capitalize interest on equity method investments that have not commenced planned principal operations. Interest capitalized and AFUDC are as follows: CAPITALIZED FINANCING COSTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 256 $ 236 $ 201 SDG&E 85 62 51 SoCalGas 60 55 49 GOODWILL AND OTHER INTANGIBLE ASSETS Goodwil l 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 we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. 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. For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include ▪ consideration of market transactions ▪ future cash flows ▪ the appropriate risk-adjusted discount rate ▪ country risk ▪ entity risk Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows: GOODWILL (D

NEW ACCOUNTING STANDARDS

NEW ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2017
Accounting Changes and Error Corrections [Abstract]
NEW ACCOUNTING STANDARDS	NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures. ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606. ASU 2015-14 defers the effective date of ASC 606 by one year for all entities and permits early adoption on a limited basis. For public entities, ASC 606 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which will result in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification has no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers will be included in our Notes to Consolidated Financial Statements beginning in the first quarter of 2018. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs ▪ Issue 3 – contingent consideration payments made after a business combination ▪ Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies) ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents. ASU 2016-15 and ASU 2016-18 must be adopted retrospectively. We early adopted ASU 2016-15 and ASU 2016-18 in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Statements of Cash Flows. Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Consolidated Statements of Cash Flows: Cash flows from operating activities: Adjustments to reconcile net income to net cash provided by $ 63 $ (1 ) $ 62 $ 66 $ — $ 66 Changes in other assets 56 (7 ) 49 (162 ) (7 ) (169 ) Net cash provided by operating activities 2,319 (8 ) 2,311 2,905 (7 ) 2,898 Cash flows from investing activities: Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired (1,582 ) 1,582 — (200 ) 200 — Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired — (1,504 ) (1,504 ) — (198 ) (198 ) Increases in restricted cash (139 ) 139 — (100 ) 100 — Decreases in restricted cash 175 (175 ) — 93 (93 ) — Other — 9 9 1 8 9 Net cash used in investing activities (4,886 ) 51 (4,835 ) (2,885 ) 17 (2,868 ) Cash flows from financing activities: Other (10 ) (11 ) (21 ) (17 ) (3 ) (20 ) Net cash provided by (used in) financing activities 2,513 (11 ) 2,502 (173 ) (3 ) (176 ) Effect of exchange rate changes on cash and cash equivalents — — — (14 ) 14 — Effect of exchange rate changes on cash, cash equivalents and restricted cash — (3 ) (3 ) — (14 ) (14 ) Decrease in cash and cash equivalents (54 ) 54 — (167 ) 167 — Decrease in cash, cash equivalents, and restricted cash — (25 ) (25 ) — (160 ) (160 ) Cash and cash equivalents, January 1 403 (403 ) — 570 (570 ) — Cash, cash equivalents and restricted cash, January 1 — 450 450 — 610 610 Cash and cash equivalents, December 31 349 (349 ) — 403 (403 ) — Cash, cash equivalents and restricted cash, December 31 — 425 425 — 450 450 SDG&E Consolidated Statements of Cash Flows: Cash flows from operating activities: Changes in other assets $ (16 ) $ (4 ) $ (20 ) $ (122 ) $ (3 ) $ (125 ) Net cash provided by operating activities 1,327 (4 ) 1,323 1,664 (3 ) 1,661 Cash flows from investing activities: Increases in restricted cash (49 ) 49 — (39 ) 39 — Decreases in restricted cash 60 (60 ) — 35 (35 ) — Other — 6 6 — 5 5 Net cash used in investing activities (1,319 ) (5 ) (1,324 ) (1,086 ) 9 (1,077 ) Cash flows from financing activities: Other (1) (4 ) (2 ) (6 ) (2 ) (2 ) (4 ) Net cash used in financing activities (20 ) (2 ) (22 ) (566 ) (2 ) (568 ) (Decrease) increase in cash and cash equivalents (12 ) 12 — 12 (12 ) — (Decrease) increase in cash, cash equivalents, and restricted cash — (23 ) (23 ) — 16 16 Cash and cash equivalents, January 1 20 (20 ) — 8 (8 ) — Cash, cash equivalents and restricted cash, January 1 — 43 43 — 27 27 Cash and cash equivalents, December 31 8 (8 ) — 20 (20 ) — Cash, cash equivalents and restricted cash, December 31 — 20 20 — 43 43 (1) Previously labeled “Debt issuance costs.” ASU 2017-01, “Clarifying the Definition of a Business”: ASU 2017-01 narrows the definition of a business and provides a framework to assist entities in determining whether a transaction involves an asset or a business. Specifically, the ASU provides a “screen” for determining when an integrated set of assets and activities (collectively referred to as a “set”) is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted. We early adopted ASU 2017-01 on July 1, 2017. ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard. ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. Entities may apply a full retrospective or modified retrospective approach. Under a modified retrospective approach, entities are required to apply the guidance to any transactions that are not completed as of the adoption date. We adopted the standard in conjunction with our adoption of ASC 606 on January 1, 2018 using the modified retrospective transition method. As we discuss in Note 1, Sempra Renewables expects the formation of a tax equity arrangement to be completed in the first half of 2018. While the arrangement would be in the scope of this ASU, we do not expect it to have a material impact on our financial condition, results of operations or cash flows. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Consolidated Statements of Operations: Operation and maintenance $ 3,117 $ 3,096 $ 2,970 $ 2,976 Other income, net 254 233 132 138 SDG&E Consolidated Statements of Operations: Operation and maintenance $ 1,020 $ 1,024 $ 1,048 $ 1,062 Operating income 713 709 990 976 Other income, net 66 70 50 64 SoCalGas Statements of Operations: Operation and maintenance $ 1,479 $ 1,474 $ 1,385 $ 1,391 Operating income 622 627 557 551 Other income, net 36 31 32 38 ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. For public entities, ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. If an entity early adopts ASU 2017-12 in an interim period, any transition adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. Entities will adopt ASU 2017-12 by applying a modified retrospective approach to the accounting for existing hedging relationships and will prospectively apply the new presentation and disclosure requirements. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018, and it will not materially affect our financial condition, results of operations or cash flows. ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard.

ACQUISTION AND DIVESTITURE ACTI

ACQUISTION AND DIVESTITURE ACTIVITY	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquistion and divestiture activity	ACQUISITION AND DIVESTITURE ACTIVITY We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date. ACQUISITIONS SEMPRA MEXICO 2017 Acquisition Ductos y Energéticos del Norte, S. de R.L. de C.V. On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50 -percent interest in DEN, a joint venture that holds a 50 -percent interest in the Los Ramones Norte pipeline through TAG, for a purchase price of $165 million (exclusive of $18 million of cash and cash equivalents acquired), plus the assumption of $96 million of short-term debt. This acquisition increased IEnova’s ownership interest in DEN through IEnova Pipelines from 50 percent to 100 percent , and increased IEnova’s indirect ownership interest in TAG from 25 percent to 50 percent . IEnova Pipelines previously accounted for its 50 -percent interest in DEN as an equity method investment. At closing, DEN became a wholly owned, consolidated subsidiary of IEnova Pipelines. DEN will continue to account for its interest in TAG as an equity method investment. This acquisition also included a $66 million intangible asset that represents a favorable O&M agreement, which has an amortization period of 23 years . 2016 Acquisitions The following table summarizes the total fair value of the 2016 business combinations at Sempra Mexico, described below, and the final purchase price allocations of the assets acquired and liabilities assumed at the dates of acquisition: PURCHASE PRICE ALLOCATIONS (Dollars in millions) IEnova Pipelines Ventika At September 26, 2016 (1) At December 14, 2016 (2) Fair value of business combination: Cash consideration (fair value of total consideration) $ 1,144 $ 310 Fair value of equity interest in IEnova Pipelines immediately prior to acquisition 1,144 — Total fair value of business combination $ 2,288 $ 310 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 66 $ — Restricted cash — 68 Accounts receivable 39 14 Other current assets 6 1 Other intangible assets — 154 Deferred income taxes — 36 Regulatory assets 33 — Property, plant and equipment 1,248 673 Other noncurrent assets 1 3 Short-term debt — (125 ) Accounts payable (11 ) (1 ) Due to unconsolidated affiliates (3 ) — Current portion of long-term debt (49 ) (7 ) Fixed-price contracts and other derivatives, current (6 ) (4 ) Other current liabilities (20 ) (8 ) Long-term debt (315 ) (478 ) Asset retirement obligations (5 ) (2 ) Deferred income taxes (127 ) (120 ) Fixed-price contracts and other derivatives, noncurrent (19 ) (10 ) Other noncurrent liabilities (11 ) — Total identifiable net assets 827 194 Goodwill 1,461 116 Total fair value of business combination $ 2,288 $ 310 (1) During the fourth quarter of 2016, we received additional information regarding IEnova Pipelines’ deferred income taxes as of the acquisition date, primarily related to basis differences in IEnova Pipelines’ PP&E. As a result, we recorded measurement period adjustments that resulted in a net increase to goodwill of $86 million , an increase in deferred income tax liabilities of $119 million and $33 million of regulatory assets related to deferred income taxes on AFUDC. (2) During the fourth quarter of 2017, we received additional information regarding Ventika’s deferred income taxes as of the acquisition date, primarily related to net operating loss carryforwards. As a result, we recorded a measurement period adjustment that resulted in a decrease to goodwill and an increase in deferred income tax assets of $13 million . IEnova Pipelines, S. de R.L. de C.V. (formerly known as Gasoductos de Chihuahua, S. de R.L. de C.V., or GdC) Background and Financing. On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50 -percent interest in IEnova Pipelines, which develops and operates energy infrastructure in Mexico, for a purchase price of $1.144 billion (exclusive of $66 million of cash and cash equivalents acquired), plus the assumption of $364 million of long-term debt, increasing IEnova’s ownership interest in IEnova Pipelines to 100 percent . IEnova Pipelines became a consolidated subsidiary of IEnova on this date. Prior to the acquisition date, IEnova owned 50 percent of IEnova Pipelines and accounted for its interest as an equity method investment. The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excluded the Los Ramones Norte pipeline, in which IEnova continued to hold an indirect 25 -percent ownership interest through IEnova Pipelines’ interest in DEN until November 2017, as we discuss above. IEnova paid $1.078 billion in cash ( $1.144 billion purchase price less $66 million of cash and cash equivalents acquired), which was funded using interim financing provided by Sempra Global through a $1.15 billion bridge loan to IEnova. Sempra Global funded the majority of the transaction using commercial paper borrowings. As we discuss in Note 1, in October 2016, IEnova completed a private follow-on offering of its common stock in the U.S. and outside of Mexico and a concurrent public common stock offering in Mexico. IEnova used a portion of the net proceeds from the offerings to fully repay the Sempra Global bridge loan. Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on their respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. None of the goodwill is expected to be deductible in Mexico or the U.S. for income tax purposes. Gain on Remeasurement of Equity Method Investment. In the year ended December 31, 2016, we recorded a pretax gain of $617 million ( $432 million after-tax) for the excess of the acquisition-date fair value of Sempra Mexico’s previously held equity interest in IEnova Pipelines over the carrying value of that interest, included as Remeasurement of Equity Method Investment on the Sempra Energy Consolidated Statement of Operations. We used a market approach to measure the acquisition-date fair value of IEnova’s equity interest in IEnova Pipelines immediately prior to the business acquisition. We discuss non-recurring fair value measures and the associated accounting impact of the IEnova Pipelines acquisition in Note 10. Valuation of IEnova Pipelines’ Assets and Liabilities. Based on the nature of the Mexico regulatory environment and the oversight surrounding the establishment and maintenance of rates that IEnova Pipelines charges for services on its assets, IEnova Pipelines applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Therefore, when determining the fair value of the acquired assets and liabilities assumed, we considered the effect of regulation on a market participant’s view of the highest and best use of the assets, in particular for the fair value of IEnova Pipelines’ PP&E. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s PP&E, and the impact of regulation is considered a fundamental input to measuring the fair value of PP&E in a business combination involving a regulated business. Under this premise, the fair value of the PP&E of a regulated business is generally assumed to be equivalent to carrying value for financial reporting purposes. Management concluded that the carrying value of IEnova Pipelines’ PP&E is representative of fair value. We applied an income approach, specifically the discounted cash flow method, to measure the fair value of debt and derivatives. We valued debt by discounting future debt payments by a market yield, and we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data. For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature. Impact on Operating Results. We incurred acquisition costs of $4 million and $1 million in the years ended December 31, 2016 and 2015, respectively. These costs are included in Operation and Maintenance on the Sempra Energy Consolidated Statements of Operations. For the year ended December 31, 2016, the Sempra Energy Consolidated Statement of Operations includes $82 million of revenues and $33 million of earnings (after noncontrolling interests) from IEnova Pipelines since the September 26, 2016 date of acquisition. Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V. Background and Financing. On December 14, 2016, IEnova acquired 100 percent of the equity interests in the Ventika wind power generation facilities for cash consideration of $310 million and the assumption of $610 million of existing debt. Ventika is a 252 -MW wind farm located in Nuevo Leon, Mexico, that began commercial operations in April 2016. All of Ventika’s generation capacity is contracted under 20 -year, U.S. dollar-denominated PPAs with five private off-takers. The acquisition was funded using $50 million of net proceeds from the IEnova equity offerings that we discuss in Note 1, $250 million of borrowings against Sempra Mexico’s revolving credit facility, and $10 million of available cash at IEnova. The acquisition also included $68 million of restricted cash that represents funds set aside for servicing debt, operations, and other costs pursuant to the long-term debt agreements. Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on their respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. None of the goodwill is expected to be deductible in Mexico or in the U.S. for income tax purposes. Valuation of Ventika’s Assets and Liabilities. The fair values of the tangible and intangible assets acquired and liabilities assumed were recognized based on their preliminary values at the acquisition date. Significant inputs used to measure the fair values of the acquired PP&E, intangible asset, debt, and derivatives are as follows: ▪ PP&E – We applied an income approach using market-based discounted cash flows. We used the pricing included in the existing PPAs, which was determined to reflect current market rates in the Mexican renewable energy market. ▪ Intangible asset – Ventika is the holder of a renewable energy transmission and consumption permit that allows it to transmit its generated power to various locations within Mexico at beneficial rates and reduces the administrative burden to manage transmitting power to off-takers. With recent renewable energy market reforms in Mexico, these transmission and consumption permits are no longer available, resulting in higher tariffs for generators. We applied an income approach based on a cash flow differential approach that measures the fair value of the transmission rights by comparing the operating expenses under the transmission and consumption permit as compared to under the new, higher tariffs. This acquired intangible asset has an amortization period of 19 years , reflecting the remaining life of the transmission and consumption transmission permit at the time of acquisition. ▪ Debt – Using an income approach, we valued debt by discounting future debt payments by a market yield commensurate with the remaining term of the loans. ▪ Derivatives – Using an income approach, we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data. Additionally, we recognized deferred income taxes on Ventika’s existing NOLs, and for the difference between the fair values and tax bases of the net assets acquired using the Mexican statutory rate. For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature. Impact on Operating Results. We incurred acquisition costs of $1 million in the year ended December 31, 2016, which are included in Operation and Maintenance on the Sempra Energy Consolidated Statement of Operations. For the year ended December 31, 2016, the Sempra Energy Consolidated Statement of Operations includes $4 million of revenues and $3 million of earnings (after noncontrolling interests) from Ventika since the December 14, 2016 date of acquisition. Unaudited Pro Forma Information The following table presents unaudited pro forma information for the years ended December 31, 2016 and 2015, combining the historical results of operations of Sempra Energy, IEnova Pipelines and Ventika as though the acquisitions occurred on January 1, 2015. The pro forma information is not necessarily indicative of results that would have been achieved had the businesses been combined during the periods presented or the results that we will experience going forward. UNAUDITED PRO FORMA INFORMATION – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Years ended December 31, 2016 2015 Revenues $ 10,463 $ 10,473 Net income 1,145 1,938 Earnings 1,058 1,641 The unaudited pro forma information above assumes ▪ the related IEnova equity offerings, discussed above and in Note 1, occurred on January 1, 2015, which results in a change in Sempra Energy’s noncontrolling interest in IEnova from 18.9 percent to 33.6 percent for all periods presented; ▪ the proceeds from the IEnova equity offerings were used to fund the acquisitions, instead of the bridge loan that was provided by Sempra Global to IEnova for the IEnova Pipelines acquisition, therefore interest expense on the commercial paper borrowings supporting the bridge loan is excluded for all periods presented; ▪ interest expense on the borrowings against Sempra Mexico’s revolving credit facility began when Ventika’s commercial operations commenced in April 2016; ▪ equity earnings, net of income tax, from IEnova Pipelines that were previously included in Sempra Energy’s results have been excluded for both periods presented; ▪ the gain related to the remeasurement of our previously held equity interest in IEnova Pipelines has been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude the gain; and ▪ acquisition-related transaction costs have been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude them. Most of Sempra Mexico’s operations, including IEnova Pipelines and Ventika, use the U.S. dollar as their functional currency. SEMPRA RENEWABLES On July 10, 2017, Sempra Renewables paid $124 million in cash for an asset acquisition of a portfolio of four solar projects located in Fresno County, California, that were under construction. We placed three of the four projects into service in the fourth quarter of 2017 and expect to place the fourth project into service in the first half of 2018. When fully constructed, the portfolio will be capable of producing up to 200 MW of solar power. The solar projects are fully contracted under four long-term PPAs, with an average contract term of 18 years . In July 2016, Sempra Renewables acquired a 100 -percent interest in a 100 -MW wind farm in Huron County, Michigan, with a 15 -year PPA, for a total purchase price of $22 million . Sempra Renewables paid $18 million in cash on the acquisition date and paid the remaining $4 million in cash on achievement of certain construction milestones in the fourth quarter of 2016. We placed this wind farm into service in November 2017. In March 2015, Sempra Renewables invested $8 million to acquire a 100 -percent interest in a 78 -MW wind development project in Stearns County, Minnesota. The wind farm has a 20 -year PPA with a load serving entity and began commercial operation in December 2016. PENDING ACQUISITION SEMPRA ENERGY Energy Future Holdings Corp. On August 21, 2017, Sempra Energy entered into an Agreement and Plan of Merger, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018 (together referred to as the Merger Agreement), with Energy Future Holdings Corp., the indirect owner of 80.03 percent of Oncor Electric Delivery Company LLC. Oncor is a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. Following closing, this acquisition will expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region. Under the Merger Agreement, we will pay the Merger Consideration of $9.45 billion in cash. Pursuant to the Merger Agreement and subject to the satisfaction of certain closing conditions described below, EFH will be merged with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy (the Merger), as follows: The foregoing is a simplified ownership structure that does not show all the subsidiaries of, or other equity interests owned by, these entities. TTI, an investment vehicle indirectly owned by third parties unaffiliated with EFH or Sempra Energy, owns 19.75 percent of Oncor’s outstanding membership interests, and certain current and former directors and officers of Oncor indirectly beneficially own 0.22 percent of Oncor’s outstanding membership interests through their ownership of Class B membership interests in OMI. On October 3, 2017, Sempra Energy provided written confirmation to Oncor Holdings and Oncor that, contemporaneously with the closing of the Merger, equivalent value (approximately $25.9 million ) will be provided in exchange for the Class B membership interests in OMI for cash or, if mutually agreed by the parties, alternative benefit and/or incentive plans. The consummation of the Merger is not conditioned on the acquisition of the interest in OMI, and there has been no formal agreement by us or the owners of these interests to accept the terms of our written confirmation. Merger Consideration and Financing Under the Merger Agreement, Sempra Energy will pay Merger Consideration of $9.45 billion in cash. We intend to initially finance the Merger Consideration of $9.45 billion , as well as associated transaction costs, with the net proceeds from debt and equity issuances, including proceeds from the common stock, mandatory convertible preferred stock and debt offerings completed in January 2018, which we discuss in Note 18, and initial additional financing consisting of up to $2.7 billion aggregate principal amount of commercial paper, although we may reduce the amount of commercial paper by borrowings under our revolving credit facilities and cash from operations. We expect to ultimately fund approximately 65 percent of the Merger Consideration, along with the associated transaction costs, with the net proceeds from sales of Sempra Energy common stock and other equity securities and approximately 35 percent with the net proceeds from issuances of Sempra Energy debt securities. However, we may use cash from operations and proceeds from asset sales in place of some of the equity financing. Some of the equity issuances will likely occur following the Merger, including common stock to be sold pursuant to the forward sale agreements entered into in connection with the common stock offering discussed in Note 18, to repay outstanding indebtedness, including indebtedness we incur to initially finance the Merger Consideration and associated transaction costs. The total amount of equity we ultimately issue may be reduced by cash from operations and proceeds from asset sales. In addition, we have agreed that, within 60 days of the Merger, we will contribute our proportionate share of the aggregate investment in Oncor in an amount necessary for Oncor to achieve a capital structure consisting of 57.5 percent long-term debt and 42.5 percent equity, as calculated for regulatory purposes. We have incurred transaction costs of $43 million as of December 31, 2017. These costs are included in Sundry on the Sempra Energy Consolidated Balance Sheet, and will be charged against related gross proceeds of equity offerings, debt offerings and/or included in the basis of EFH’s equity method investment in Oncor Holdings upon consummation of the Merger. If the Merger does not occur, the transaction costs that would be included in the basis of EFH’s equity method investment in Oncor Holdings will be expensed. Ring-Fencing In April 2014, EFH and the substantial majority of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court. The bankruptcy does not include Oncor Holdings or Oncor. Certain existing “ring-fencing” measures, governance mechanisms and restrictions will remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. In accordance with the ring-fencing measures and commitments made by Sempra Energy as part of the Joint Application to the PUCT for regulatory approval of the Merger, and the Stipulation with key stakeholders entered into in connection with that proceeding, Sempra Energy and Oncor will be subject to certain restrictions following the Merger. Sempra Energy will not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions will limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. These limitations include limited representation on the Oncor Holdings and Oncor boards of directors. Following consummation of the Merger, if the Stipulation is approved by the PUCT, the board of directors of Oncor is expected to consist of thirteen members and be constituted as follows: ▪ seven members will be independent directors in all material respects under the rules of the New York Stock Exchange in relation to Sempra Energy and its subsidiaries and affiliated entities and any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings (and those directors must have no material relationship with Sempra Energy or its affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings at the time of the Merger or within the previous ten years) (“independent directors”); ▪ two members will be designated by Sempra Energy; ▪ two members will be appointed by TTI. If Sempra Energy acquires TTI’s interest in Oncor, the two board positions on the Oncor board of directors that TTI is entitled to appoint shall be eliminated, and the size of the Oncor board of directors will be reduced by two; and ▪ two members will be current or former officers of Oncor (the Oncor Officer Directors). In order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, such officer cannot have worked for Sempra Energy or any of its affiliates (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten years prior to such officer being employed by Oncor. Oncor Holdings, at the direction of EFIH (a subsidiary of EFH, which will be a wholly owned indirect subsidiary of, and controlled by, Sempra Energy following the Merger), will have the right to nominate and/or seek the removal of the Oncor Officer Directors, with such nomination or removal subject to approval by a majority of the Oncor board of directors. Oncor Holdings will also continue to have a majority of independent directors following the consummation of the Merger. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced). Upon consummation of the acquisition, we will consolidate EFH, and EFH will continue to account for its ownership interest in Oncor Holdings as an equity method investment. Settlement Agreement Regarding Joint Application In December 2017 and January 2018, Sempra Energy and Oncor entered into a comprehensive Stipulation with 10 intervening parties, including the Staff of the PUCT, reflecting the parties’ settlement of all issues in the PUCT proceeding regarding the Joint Application. Pursuant to the Stipulation, the parties have agreed that Sempra Energy’s acquisition of EFH is in the public interest and will bring substantial benefits. The Stipulation includes regulatory commitments by Sempra Energy, most of which are similar to the regulatory commitments made by Sempra Energy as part of the Joint Application and are consistent with the “ring-fencing” measures currently in place. Sempra Energy and Oncor are entitled to seek modifications of the PUCT order to be entered in the proceedings regarding the Joint Application, which modifications would be subject to PUCT approval. On January 5, 2018, Oncor, Sempra Energy and the Staff of the PUCT jointly filed with the PUCT, requesting that the PUCT approve the Merger consistent with the Stipulation. As of January 31, 2018, all 10 intervening parties including the Staff of the PUCT, had agreed to the Stipulation. Closing Conditions The Merger is subject to customary closing conditions, including the approval of the Bankruptcy Court, the PUCT, the Vermont Department of Financial Regulation, and the FERC, among others, as well as receipt of a private letter ruling from the IRS and the issuance of certain tax opinions regarding the Merger. On September 6, 2017, the Bankruptcy Court approved EFH’s and EFIH’s entry into the Merger Agreement. Under the terms of the Merger Agreement, a $190 million termination fee would be owed to Sempra Energy if EFH or EFIH terminates the Merger Agreement in certain circumstances and consummates an alternative proposal with a third party. On October 5, 2017, Sempra Energy and Oncor filed a joint application with the PUCT and an application with the FERC seeking approval of the Merger. On October 12, 2017, the ALJ in the PUCT proceeding issued an order deeming the joint application sufficient. On October 16, 2017, the PUCT set a procedural schedule to complete a review of Sempra Energy’s and Oncor’s change-in-control request within 180 days of the filing of the joint application on October 5, 2017. On November 2, 2017, EFH received a supplemental private letter ruling from the IRS that provides that the Merger will not affect the tax-free treatment of the 2016 Vistra (formerly TCEH Corp.) spinoff from EFH. This ruling satisfies the closing condition described above. On November 29, 2017, Sempra Energy received the necessary approval from the Vermont Department of Financial Regulation. On December 11, 2017, the FERC issued an order authorizing the Merger, subject to customary conditions. On February 26, 2018, the Bankruptcy Court held a hearing to consider confirmation of EFH’s plan of reorganization and final approval of the Merger. At the conclusion of the hearing, the Bankruptcy Court ruled that it will confirm the plan of reorganization and approve the Merger and that it will promptly enter an order reflecting such ruling. We currently expect the Merger will close in the first half of 2018, although there can be no assurance that the Merger will be completed on that timetable, or at all. ASSETS HELD FOR SALE We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next 12 months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs. SEMPRA MEXICO Termoeléctrica de Mexicali In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a 625 -MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified it as held for sale. In connection with the sales process, in late September 2016 and early July 2017, Sempra Mexico received market information indicating that the fair value of TdM was less than its carrying value. After performing analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing noncash impairment charges of $131 million ( $111 million after-tax) in the third quarter of 2016 and $71 million in the second quarter of 2017, recorded in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. We discuss non-recurring fair value measures and the associated accounting impact on TdM in Note 10. In connection with TdM’s classification as held for sale, we recognized an $8 million income tax benefit in 2017 and an $8 million income tax expense in 2016, for a deferred Mexican income tax liability related to the excess of carrying value over the tax basis. As the Mexican income tax on this outside basis difference is based on current carrying value, foreign exchange rates and inflation, such amount could change in future periods until the date of sale. We continue to actively pursue the sale of TdM, which we expect to be completed in 2018. At December 31, 2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows: ASSETS HELD FOR SALE AT DECEMBER 31, 2017 (Dollars in millions) TdM Inventories $ 10 Other current assets 59 Property, plant and equipment, net 56 Other noncurrent assets 2 Total assets held for sale $ 127 Accounts payable $ 5 Other current liabilities 38 Asset retirement obligations 5 Other noncurrent liabilities 1 Total liabilities held for sale $ 49 DIVESTITURES SEMPRA RENEWABLES Rosamond Solar In December 2015, Sempra Renewables sold its 100 -percent interest in Rosamond Solar, a development project located in Antelope Valley, California for $26 million in cash. Upon completion of the sale that was comprised of $18 million of net PP&E, Sempra Renewables recognized a pretax gain of $8 million ( $5 million after-tax), which is included in Gain on Sale of Assets on our Consolidated Statement of Operations. SEMPRA LNG & MIDSTREAM EnergySouth Inc. In September 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas, to Spire Inc. (formerly The Laclede Group, Inc.) for cash proceeds of $318 million , net of $2 million cash sold, with the buyer assuming debt of $67 million . We recognized a pretax gain on the sale of $130 million ( $78 million after-tax) in the year ended December 31, 2016, in Gain on Sale of Assets on Sempra Energy’s Consolidated Statement of Operations. On September 12, 2016, Sempra LNG & Midstream deconsolidated EnergySouth. The following table summarizes the deconsolidation: DECONSOLIDATION OF SUBSIDIARY (Dollars in millions) EnergySouth Proceeds from sale, net of transaction costs $ 304 Cash (2 ) Other current assets (17 ) Property, plant and equipment, net (199 ) Goodwill (72 ) Other noncurrent assets (65 ) Current liabilities 25 Long-term debt 67 Other noncurrent liabilities 89 Gain on sale $ 130 Investment in Rockies Express In March 2016, Sempra LNG & Midstream entered into an agreement to sell its 25 -percent interest in Rockies Express to a subsidiary of Tallgrass Development, LP for cash consideration of $440 million , subject to adjustment at closing. The transaction closed in May 2016 for total cash proceeds of $443 million . At the date of the agreement, the carrying value of Sempra LNG & Midstream’s investment in Rockies Express was $484 million . Following the execution of the agreement, Sempra LNG & Midstream measured the fair value of its equity method investment at $440 million , and recognized a $44 million ( $27 million after-tax) impairment in Equity Earnings, Before Income Tax, on the Sempra Energy Consolidated Statement of Operations. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 10. We discuss Sempra LNG & Midstream’s 2016 permanent release of pipeline capacity th

INVESTMENTS IN UNCONSOLIDATED E

INVESTMENTS IN UNCONSOLIDATED ENTITIES	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
INVESTMENTS IN UNCONSOLIDATED ENTITIES	NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. We adjust each investment for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss. We evaluate the carrying value of unconsolidated entities for impairment under the U.S. GAAP provisions for equity method investments. We provide the carrying value of our investments and earnings (losses) on these investments below: EQUITY METHOD AND OTHER INVESTMENT BALANCES (Dollars in millions) December 31, 2017 2016 Sempra South American Utilities: Eletrans (1) $ 16 $ (8 ) Sempra Mexico: DEN — 42 Energía Sierra Juárez (2) 39 38 IMG (3) 221 100 TAG (4) 364 — Sempra Renewables: Wind: Auwahi Wind 42 41 Broken Bow 2 Wind 32 35 Cedar Creek 2 Wind 72 75 Flat Ridge 2 Wind 255 271 Fowler Ridge 2 Wind 44 43 Mehoopany Wind 89 92 Solar: California solar partnership 107 113 Copper Mountain Solar 2 35 33 Copper Mountain Solar 3 44 42 Mesquite Solar 1 81 86 Other 12 13 Sempra LNG & Midstream: Cameron LNG JV (5) 997 997 Parent and other: RBS Sempra Commodities 67 67 Total equity method investments 2,517 2,080 Other 10 17 Total $ 2,527 $ 2,097 (1) Reflects losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the CLF relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018. (2) The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014. (3) The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees, which we discuss below. (4) The carrying value of our equity method investment is $ 130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill. (5) The carrying value of our equity method investment is $237 million and $190 million higher than the underlying equity in the net assets of the investee at December 31, 2017 and 2016 , respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations. EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Earnings (losses) recorded before income tax: Sempra Renewables: Wind: Auwahi Wind $ 5 $ 4 $ 4 Broken Bow 2 Wind (2 ) (2 ) (2 ) Cedar Creek 2 Wind (2 ) (2 ) (6 ) Flat Ridge 2 Wind (13 ) (7 ) (12 ) Fowler Ridge 2 Wind 4 4 4 Mehoopany Wind (1 ) — (1 ) Solar: California solar partnership 7 7 6 Copper Mountain Solar 2 5 6 7 Copper Mountain Solar 3 8 8 8 Mesquite Solar 1 18 17 16 Other — (1 ) — Sempra LNG & Midstream: Cameron LNG JV 5 (2 ) 5 Rockies Express Pipeline — (26 ) 79 Parent and other: RBS Sempra Commodities — — (4 ) $ 34 $ 6 $ 104 Earnings (losses) recorded net of income tax (1) : Sempra South American Utilities: Eletrans $ 4 $ 3 $ (4 ) Sempra Mexico: DEN (13 ) 5 — Energía Sierra Juárez — 6 6 IEnova Pipelines — 64 83 IMG 45 — — TAG 6 — — $ 42 $ 78 $ 85 (1) As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our ETR . Our share of the undistributed earnings of equity method investments was $89 million and $44 million at December 31, 2017 and 2016 , respectively. These balances do not include remaining distributions of $67 million associated with our investment in RBS Sempra Commodities and expected to be received from the partnership as it is dissolved, as we discuss below. SEMPRA SOUTH AMERICAN UTILITIES In February 2017, Sempra South American Utilities recorded the equitization of its $19 million note receivable due from Eletrans, resulting in an increase in its investment in this unconsolidated joint venture. During the year ended December 31, 2017 , Sempra South American Utilities invested cash of $1 million in Eletrans. SEMPRA MEXICO IEnova Pipelines, DEN and TAG On September 26, 2016, IEnova completed the acquisition of the remaining 50 -percent interest in IEnova Pipelines and IEnova Pipelines became a consolidated subsidiary. Prior to the acquisition date, IEnova owned 50 percent of IEnova Pipelines and accounted for its interest as an equity method investment. As of the acquisition date, IEnova accounted for IEnova Pipelines’ 50 -percent interest in DEN as an equity method investment. On November 15, 2017, IEnova acquired the remaining 50 -percent interest in DEN, and DEN became a consolidated subsidiary. Since the acquisition date, IEnova accounts for DEN’s 50 -percent interest in TAG as an equity method investment. We discuss these acquisitions in Note 3. IMG In June 2016, IMG, a joint venture between IEnova and a subsidiary of TransCanada, was awarded the right to build, own and operate the Sur de Texas-Tuxpan natural gas marine pipeline by the CFE. IEnova has a 40 -percent interest in the project and accounts for its interest as an equity method investment, and TransCanada owns the remaining 60 -percent interest. The marine pipeline is fully contracted under a 25 -year natural gas transportation service contract with the CFE. We expect the project to be completed in the second half of 2018. During the years ended December 31, 2017 and 2016, Sempra Mexico invested cash of $72 million and $100 million respectively, in the IMG joint venture. SEMPRA RENEWABLES Sempra Renewables has 50 -percent interests in wind and solar energy generation facilities in operation in the U.S. The generating capacities of the facilities are contracted under long-term PPAs. These facilities are accounted for under the equity method. During the years ended December 31, 2016 and 2015, Sempra Renewables invested cash of $18 million and $21 million , respectively, in its unconsolidated joint ventures. SEMPRA LNG & MIDSTREAM Rockies Express As we discuss in Note 3, in May 2016, Sempra LNG & Midstream sold its 25 -percent interest in Rockies Express, a partnership that operates a natural gas pipeline, REX, that links the Rocky Mountain region to the upper Midwest and the eastern U.S. In 2015, Sempra LNG & Midstream invested $113 million of cash in Rockies Express to repay project debt that matured in early 2015. Cameron LNG JV The Cameron LNG JV is a joint venture partnership that was formed in October 2014 among Sempra Energy and three project partners. The Cameron LNG existing regasification terminal that was contributed to the joint venture included two marine berths and three LNG storage tanks, and facilities capable of processing 1.5 Bcf of natural gas per day. The current liquefaction project, which is utilizing Cameron LNG JV’s existing facilities, is comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.9 Mtpa of LNG, with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. As of October 2014, Sempra LNG & Midstream began accounting for its investment in Cameron LNG JV under the equity method. During the years ended December 31, 2017 , 2016 and 2015, Sempra LNG & Midstream capitalized $47 million , $47 million and $49 million , respectively, of interest related to this equity method investment that has not commenced planned principal operations. During the years ended December 31, 2017 and 2015, Sempra LNG & Midstream invested $1 million and $10 million , respectively, of cash in Cameron LNG JV. Cameron LNG JV Financing General. In August 2014, Cameron LNG JV entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $7.4 billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI). The Cameron LNG JV Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans will be used for financing the cost of development and construction of the three-train Cameron LNG project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG JV financing. Interest. The weighted-average all-in cost of the loans outstanding under all the Loan Facility Agreements (and based on certain assumptions as to timing of drawdown) is 1.59 percent per annum over LIBOR prior to financial completion of the project and 1.78 percent per annum over LIBOR following financial completion of the project. The Loan Facility Agreements require Cameron LNG JV to hedge 50 percent of outstanding borrowings to fix the interest rate, beginning in 2016. The hedges are to remain in place until the debt principal has been amortized by 50 percent . In November 2014, Cameron LNG JV entered into floating-to-fixed interest rate swaps for approximately $3.7 billion notional amount, resulting in an effective fixed rate of 3.19 percent for the LIBOR component of the interest rate on the loans. In June 2015, Cameron LNG JV entered into additional floating-to-fixed interest rate swaps effective starting in 2020, for approximately $1.5 billion notional amount, resulting in an effective fixed rate of 3.32 percent for the LIBOR component of the interest rate on the loans. Guarantees. In August 2014, Sempra Energy entered into agreements for the benefit of all of Cameron LNG JV’s creditors under the Loan Facility Agreements and related finance documents. Pursuant to these agreements, Sempra Energy has severally guaranteed 50.2 percent of Cameron LNG JV’s obligations under the Loan Facility Agreements and related finance documents, or a maximum amount of $3.9 billion . Guarantees for the remaining 49.8 percent of Cameron LNG JV’s senior secured financing have been provided by the other project partners. The Sempra Energy guarantee of 50.2 percent of Cameron LNG JV’s financing became effective upon effectiveness of the joint venture. Sempra Energy’s agreements and guarantees will terminate upon financial completion of the three-train Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. We expect the project to achieve financial completion and the guarantees to be terminated approximately nine months after all three trains achieve commercial operation. Sempra Energy recorded a liability of $82 million in October 2014, with an associated carrying value of $26 million at December 31, 2017, for the fair value of its obligations associated with the Loan Facility Agreements and related finance documents, which constitute guarantees. This liability is being reduced on a straight-line basis over the duration of the guarantees by recognizing equity earnings from Cameron LNG JV, included in Equity Earnings, Before Income Tax. In August 2014, Sempra Energy and the other project partners entered into a transfer restrictions agreement with Société Générale, as intercreditor agent for the lenders under the Loan Facility Agreements. Pursuant to the transfer restriction agreement, Sempra Energy agreed to certain restrictions on its ability to dispose of Sempra Energy’s indirect fully diluted economic and beneficial ownership interests in Cameron LNG JV. These restrictions vary over time. Prior to financial completion of the three-train Cameron LNG project, Sempra Energy must retain 37.65 percent of such interest in Cameron LNG JV. Starting six months after financial completion of the three-train Cameron LNG project, Sempra Energy must retain at least 10 percent of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra Energy controlled (but not necessarily wholly owned) subsidiary must directly own 50.2 percent of the membership interests of the Cameron LNG JV. Events of Default. Cameron LNG JV’s Loan Facility Agreements and related finance documents contain events of default customary for such financings, including events of default for: failure to pay principal and interest on the due date; insolvency of Cameron LNG JV; abandonment of the project; expropriation; unenforceability or termination of the finance documents; and a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to an additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under Cameron LNG JV’s financing and a potential demand on Sempra Energy’s guarantees. Security. To support Cameron LNG JV’s obligations under the Loan Facility Agreements and related finance documents, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra Energy and the other project partners. The security trustee under Cameron LNG JV’s financing can demand that a payment be made by Sempra Energy under its guarantees of Sempra Energy’s 50.2 -percent share of senior debt obligations due and payable either on the date such amounts were due from Cameron LNG JV (taking into account cure periods) in the event of a failure by Cameron LNG JV to pay such senior debt obligations when they become due or within 10 business days in the event of an acceleration of senior debt obligations under the terms of the finance documents. If an event of default occurs under the Sempra Energy completion agreement, the security trustee can demand that Sempra Energy purchase its 50.2 -percent share of all then outstanding senior debt obligations within five business days (other than in the case of a bankruptcy default, which is automatic). RBS SEMPRA COMMODITIES RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report miscellaneous costs since the sale of the business 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. The investment balance of $67 million at December 31, 2017 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 in “Legal Proceedings – 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 items for which JP Morgan, one of the buyers of the partnership’s businesses, has agreed to indemnify us. SUMMARIZED FINANCIAL INFORMATION We present summarized financial information below, aggregated for all of our equity method investments for the periods in which we were invested in the entity. The amounts below represent the aggregate financial position and results of operations of 100 percent of each of Sempra Energy’s equity method investments. SUMMARIZED FINANCIAL INFORMATION (Dollars in millions) Years ended December 31, 2017 (1) 2016 (2) 2015 Gross revenues $ 846 $ 1,079 $ 1,533 Operating expense (590 ) (726 ) (845 ) Income from operations 256 353 688 Interest expense (217 ) (127 ) (312 ) Net income/Earnings (3) 116 252 440 At December 31, 2017 (1) 2016 (2) Current assets $ 974 $ 704 Noncurrent assets 14,087 9,970 Current liabilities 797 629 Noncurrent liabilities 9,809 6,627 (1) On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50 -percent interest in DEN, increasing its ownership percentage to 100 percent . At December 31, 2017, DEN is no longer an equity method investment. (2) On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50 -percent interest in IEnova Pipelines, increasing its ownership percentage to 100 percent , and on May 9, 2016, Sempra LNG & Midstream sold its 25 -percent interest in Rockies Express. At December 31, 2016, IEnova Pipelines and Rockies Express are no longer equity method investments. (3) Except for our investments in South America and Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships. GUARANTEES Project financing at our solar and wind joint ventures generally requires the joint venture partners, for each partner’s interest, to return cash to the projects in the event that the projects do not meet certain cash flow criteria or in the event that the projects’ debt service, O&M, and firm transmission and PTC reserve accounts are not maintained at specific thresholds. In some cases, the joint venture partners have provided guarantees to the lenders in lieu of the projects funding the reserve account requirements. We recorded liabilities for the fair value of certain of our obligations associated with these guarantees and the liabilities are being amortized over their expected lives. The outstanding loans at our solar and wind joint ventures are not guaranteed by the partners, but are secured by project assets. IEnova has an indirect 40 -percent ownership interest and TransCanada has an indirect 60 -percent ownership interest in IMG. IEnova and TransCanada have each provided guarantees to third parties associated with construction of IMG’s Sur de Texas-Tuxpan natural gas marine pipeline. The aggregate amount of the obligations guaranteed by IEnova shall not exceed $288 million and will terminate upon completion of all guaranteed obligations. IEnova expects the construction giving rise to these guarantees to be completed by the end of 2018. At December 31, 2017 , we provided guarantees aggregating a maximum of $183 million with an associated aggregated carrying value of $6 million for guarantees related to project financing. In addition, at December 31, 2017 , we provided guarantees to joint ventures aggregating a maximum of $370 million with an associated aggregated carrying value of $3 million , primarily related to PPAs and EPC contracts.

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt and Credit Facilities	DEBT AND CREDIT FACILITIES LINES OF CREDIT At December 31, 2017 , Sempra Energy Consolidated had an aggregate of $4.3 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the principal terms of which we describe below. Available unused credit on these lines at December 31, 2017 was approximately $3.0 billion . Our foreign operations have additional general purpose credit facilities aggregating $1.8 billion at December 31, 2017 . Available unused credit on these lines totaled $1.4 billion at December 31, 2017 . PRIMARY U.S. COMMITTED LINES OF CREDIT (Dollars in millions) At December 31, 2017 Total facility Commercial paper outstanding (1) Available unused credit Sempra Energy (2) $ 1,000 $ — $ 1,000 Sempra Global (3) 2,335 (931 ) 1,404 California Utilities (4) : SDG&E 750 (253 ) 497 SoCalGas 750 (116 ) 634 Less: subject to a combined limit of $1 billion for both utilities (500 ) — (500 ) 1,000 (369 ) 631 Total $ 4,335 $ (1,300 ) $ 3,035 (1) Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit. (2) The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017. (3) Sempra Energy guarantees Sempra Global’s obligations under the credit facility. (4) The facility also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017. Related to the committed lines of credit in the table above: ▪ Each is a 5 -year syndicated revolving credit agreement expiring in October 2020. ▪ Citibank N.A. serves as administrative agent for the Sempra Energy and Sempra Global facilities and JPMorgan Chase Bank, N.A. serves as administrative agent for the California Utilities combined facility. ▪ Each facility has a syndicate of 21 lenders. No single lender has greater than a 7 -percent share in any facility. ▪ Sempra Energy, SDG&E and SoCalGas must maintain a ratio of indebtedness to total capitalization (as defined in each agreement) of no more than 65 percent at the end of each quarter. Each entity is in compliance with this and all other financial covenants under its respective credit facility at December 31, 2017. ▪ Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings in the case of the Sempra Energy and Sempra Global lines of credit, and with the borrowing utility’s credit rating in the case of the California Utilities line of credit. ▪ The California Utilities’ obligations under their 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. On January 17, 2018, pursuant to the terms of the Sempra Energy and Sempra Global credit facilities, the amounts available under the lines of credit were increased by $250 million , from $1.0 billion to $1.25 billion , for Sempra Energy and by $850 million , from $2.335 billion to $3.185 billion , for Sempra Global. This additional borrowing capacity is available to us for working capital, capital expenditures and other general corporate purposes, and is intended to provide us with additional liquidity and to support commercial paper that we may utilize from time to time to fund our strategic and growth initiatives. CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO (U.S. dollar equivalent in millions) At December 31, 2017 Denominated in Total facility Amount Available unused credit Sempra South American Utilities (1) : Peru (2) Peruvian sol $ 465 $ (169 ) (3) $ 296 Chile Chilean peso 115 — 115 Sempra Mexico: IEnova (4) U.S. dollar 1,170 (137 ) 1,033 Total $ 1,750 $ (306 ) $ 1,444 (1) The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021. (2) The Peruvian facilities require a debt to equity ratio of no more than 170 percent , with which we were in compliance at December 31, 2017. (3) Includes bank guarantees of $18 million . (4) Five-year revolver expiring in August 2020 with a syndicate of eight lenders. Outside of these domestic and foreign committed credit facilities, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2017, we had approximately $629 million in standby letters of credit outstanding under these agreements. WEIGHTED-AVERAGE INTEREST RATES The weighted-average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.92 percent and 1.51 percent at December 31, 2017 and 2016 , respectively. The weighted-average interest rate on total short-term debt at SDG&E was 1.65 percent at December 31, 2017 . The weighted-average interest rates on total short-term debt at SoCalGas were 1.64 percent and 0.75 percent at December 31, 2017 and 2016 , respectively. BRIDGE FACILITY RELATED TO THE PENDING ACQUISITION OF ENERGY FUTURE HOLDINGS CORP. At December 31, 2017 , Sempra Energy had a commitment letter from a syndicate of banks, subject to customary conditions, for a $4.0 billion , 364-day senior unsecured bridge facility to backstop a portion of our obligations to pay the Merger Consideration for the acquisition of EFH, which we discuss in Note 3. The $4.0 billion commitment is reduced by the amount of funds received through Sempra Energy’s sales of equity securities and debt securities, subject in each case to certain exceptions, and increases in our borrowing capacity under our existing revolving credit facilities. At December 31, 2017 , we had no amounts outstanding under this bridge facility. Following the completion of the common stock offering and the mandatory convertible preferred stock offering, which closed on January 9, 2018, the facility was terminated. We discuss the offerings in Note 18. LONG-TERM DEBT The following tables show the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 SDG&E First mortgage bonds (collateralized by plant assets): Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017 $ — $ 140 1.65% July 1, 2018 (1) 161 161 3% August 15, 2021 350 350 1.914% payable 2015 through February 2022 161 197 3.6% September 1, 2023 450 450 2.5% May 15, 2026 500 500 6% June 1, 2026 250 250 5.875% January and February 2034 (1) 176 176 5.35% May 15, 2035 250 250 6.125% September 15, 2037 250 250 4% May 1, 2039 (1) 75 75 6% June 1, 2039 300 300 5.35% May 15, 2040 250 250 4.5% August 15, 2040 500 500 3.95% November 15, 2041 250 250 4.3% April 1, 2042 250 250 3.75% June 1, 2047 400 — 4,573 4,349 Other long-term debt: OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007), payable 2013 through April 2019 (collateralized by OMEC plant assets) 295 305 Capital lease obligations: Purchased-power contracts 731 239 Other 1 1 1,027 545 5,600 4,894 Current portion of long-term debt (220 ) (191 ) Unamortized discount on long-term debt (11 ) (11 ) Unamortized debt issuance costs (34 ) (34 ) Total SDG&E 5,335 4,658 SoCalGas First mortgage bonds (collateralized by plant assets): 5.45% April 15, 2018 250 250 1.55% June 15, 2018 250 250 3.15% September 15, 2024 500 500 3.2% June 15, 2025 350 350 2.6% June 15, 2026 500 500 5.75% November 15, 2035 250 250 5.125% November 15, 2040 300 300 3.75% September 15, 2042 350 350 4.45% March 15, 2044 250 250 3,000 3,000 Other long-term debt (uncollateralized): 1.875% Notes payable 2016 through May 2026 (1) 4 4 5.67% Notes January 18, 2028 5 5 Capital lease obligations 1 — 10 9 3,010 3,009 Current portion of long-term debt (501 ) — Unamortized discount on long-term debt (7 ) (7 ) Unamortized debt issuance costs (17 ) (20 ) Total SoCalGas 2,485 2,982 LONG-TERM DEBT (CONTINUED) (Dollars in millions) December 31, 2017 2016 Sempra Energy Other long-term debt (uncollateralized): 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease (2) 138 137 Sempra South American Utilities Other long-term debt (uncollateralized): Chilquinta Energía – 4.25% Series B Bonds October 30, 2030 205 185 Luz del Sur Bank loans 5.18% to 6.7% payable 2016 through December 2018 53 75 Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029 415 346 Other bonds at 3.77% to 4.61% payable 2020 through May 2022 6 7 Capital lease obligations 6 6 Sempra Mexico Other long-term debt (uncollateralized unless otherwise noted): Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency swaps effective 2013) 66 63 6.3% Notes February 2, 2023 (4.12% after cross-currency swap) 198 189 Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014), payable 2016 through December 2026, collateralized by plant assets 314 352 3.75% Notes January 14, 2028 300 — Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates (weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets 468 481 4.875% Notes January 14, 2048 540 — Sempra Renewables Other long-term debt (collateralized by project assets): Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028 except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012 (1) 77 84 Sempra LNG & Midstream Other long-term debt (uncollateralized unless otherwise noted): Notes at 2.87% to 3.51% October 1, 2026 (1) 20 20 8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee — 6 9,405 7,548 Current portion of long-term debt (706 ) (722 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized premium on long-term debt 4 4 Unamortized debt issuance costs (65 ) (31 ) Total other Sempra Energy 8,625 6,789 Total Sempra Energy Consolidated $ 16,445 $ 14,429 (1) Callable long-term debt not subject to make-whole provisions. (2) We discuss this lease in Note 15. MATURITIES OF LONG-TERM DEBT (1) (Dollars in millions) SDG&E SoCalGas Other Sempra Energy Total Sempra Energy Consolidated 2018 $ 207 $ 500 $ 705 $ 1,412 2019 321 — 1,098 1,419 2020 36 — 997 1,033 2021 385 — 961 1,346 2022 18 — 629 647 Thereafter 3,901 2,509 4,872 11,282 Total $ 4,868 $ 3,009 $ 9,262 $ 17,139 (1) Excludes capital lease obligations, build-to-suit lease, market value adjustments for interest rate swaps, discounts, premiums and debt issuance costs. Various long-term obligations totaling $8.4 billion at Sempra Energy Consolidated at December 31, 2017 are unsecured. This includes unsecured long-term obligations totaling $9 million at SoCalGas. There were no unsecured long-term obligations at SDG&E. CALLABLE LONG-TERM DEBT At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2017 is callable subject to premiums: CALLABLE LONG-TERM DEBT (Dollars in millions) SDG&E SoCalGas Other Total Not subject to make-whole provisions $ 412 $ 4 $ 97 $ 513 Subject to make-whole provisions 4,161 3,005 7,058 14,224 In addition, the OMEC LLC project financing loan discussed in Note 1, with $295 million of outstanding borrowings at December 31, 2017 , may be prepaid at OMEC LLC’s option. FIRST MORTGAGE BOND S The California Utilities issue first mortgage bonds secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $4.7 billion at SDG&E and $1.1 billion at SoCalGas at December 31, 2017 . In June 2017, SDG&E publicly offered and sold $400 million of 3.75 -percent, first mortgage bonds maturing in June 2047. SDG&E used the proceeds from the offering to repay outstanding commercial paper. OTHER LONG-TERM DEBT Sempra Energy In January 2018, Sempra Energy publicly offered and sold an aggregate principal amount of $5.0 billion of fixed and floating rate notes, which we discuss in Note 18. In October 2017, Sempra Energy publicly offered and sold $850 million of floating rate notes, maturing in March 2021. The floating rate notes bear interest at a rate equal to the three-month LIBOR plus 45 bps. The interest rate is reset quarterly. Sempra Energy used a substantial portion of the net proceeds from the offering to repay outstanding commercial paper, with remaining proceeds used for general corporate purposes. In June 2017, Sempra Energy publicly offered and sold $750 million of 3.25 -percent, fixed rate notes maturing in June 2027. Sempra Energy used the proceeds from the offering to repay outstanding commercial paper. SDG&E In 2015, SDG&E entered into a CPUC-approved 25 -year PPA with a peaker plant facility. Construction of the peaker plant facility was completed and delivery of contracted power commenced in June 2017, at which time we recorded a $500 million capital lease obligation on SDG&E’s and Sempra Energy’s Consolidated Balance Sheets. Sempra South American Utilities Luz del Sur has outstanding corporate bonds and bank loans that are denominated in the local currency. In February 2017, Luz del Sur publicly offered and sold $50 million of corporate bonds at 6.375 percent, maturing in February 2023. In December 2017, Luz del Sur publicly offered and sold $50 million of corporate bonds at 5.9375 percent, maturing in December 2027. Sempra Mexico In December 2017, Sempra Mexico offered and sold in a private placement $300 million of 3.75 -percent, fixed rate notes maturing in January 2028 and $540 million of 4.875 -percent, fixed rate notes maturing in January 2048. Sempra Mexico used a substantial portion of the net proceeds from the offering to repay outstanding short-term debt, with remaining proceeds used for general corporate purposes. INTEREST RATE SWAPS We discuss our fair value and cash flow hedging interest rate swaps in Note 9.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES Reconciliation of net U.S. statutory federal income tax rates to the ETRs is as follows: RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: U.S. federal statutory income tax rate 35 % 35 % 35 % Effects of the TCJA 55 — — Utility depreciation 6 4 5 Foreign exchange and inflation effects (1) 3 (2 ) (2 ) State income taxes, net of federal income tax benefit 1 1 1 Utility repairs expenditures (6 ) (4 ) (5 ) Tax credits (4 ) (3 ) (4 ) Self-developed software expenditures (4 ) (3 ) (3 ) Non-U.S. earnings taxed at lower statutory income tax rates (2) (3 ) (3 ) (2 ) Allowance for equity funds used during construction (3 ) (2 ) (2 ) Resolution of prior years’ income tax items (2 ) — (3 ) Share-based compensation — (2 ) — Other, net 3 — — Effective income tax rate 81 % 21 % 20 % SDG&E: U.S. federal statutory income tax rate 35 % 35 % 35 % Depreciation 7 5 4 Effects of the TCJA 5 — — State income taxes, net of federal income tax benefit 3 5 5 Repairs expenditures (8 ) (4 ) (4 ) Self-developed software expenditures (6 ) (3 ) (3 ) Allowance for equity funds used during construction (4 ) (2 ) (2 ) Resolution of prior years’ income tax items (4 ) (1 ) (2 ) Share-based compensation — (1 ) — Other, net (1 ) (1 ) (1 ) Effective income tax rate 27 % 33 % 32 % SoCalGas: U.S. federal statutory income tax rate 35 % 35 % 35 % Depreciation 9 9 8 State income taxes, net of federal income tax benefit 3 2 4 Repairs expenditures (8 ) (9 ) (10 ) Self-developed software expenditures (5 ) (6 ) (6 ) Allowance for equity funds used during construction (3 ) (2 ) (2 ) Resolution of prior years’ income tax items (2 ) 2 (3 ) Share-based compensation — (1 ) — Other, net — (1 ) (1 ) Effective income tax rate 29 % 29 % 25 % (1) Primarily due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of significant appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova. (2) Related to operations in Mexico, Chile and Peru. On December 22, 2017, the TCJA was signed into law. This legislation significantly changes the IRC. Under U.S. GAAP, certain effects of the TCJA are required to be recognized upon enactment, and, as a result, Sempra Energy, SDG&E, and SoCalGas recorded the related effects in 2017. The TCJA reduces the U.S. statutory corporate income tax rate from 35 percent to 21 percent , effective January 1, 2018, which will be applied to future U.S. earnings. U.S. GAAP requires that deferred income tax assets and liabilities, including NOLs, be remeasured at the income tax rate expected to apply when those temporary differences reverse and that the effects of any change to such income tax rate be recognized in the period when the change was enacted. This remeasurement resulted in significant reductions in deferred income tax balances at Sempra Energy Consolidated, SDG&E and SoCalGas. The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes that previously have been collected from ratepayers at the higher rate. These excess deferred income taxes have been recorded as regulatory liabilities as of December 31, 2017 and will be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and FERC. Our 2017 financial statements were materially impacted by the effects of the TCJA, primarily related to two provisions: ▪ Lower U.S. statutory corporate income tax rate: The change in the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent resulted in income tax expense of $182 million for the year ended December 31, 2017 for Sempra Energy Consolidated because of the remeasurement of deferred income tax balances. SDG&E’s and SoCalGas’ impacts were primarily offset with adjustments to regulatory liabilities, however, they also recorded $28 million and $2 million of income tax expense, respectively, for the year ended December 31, 2017 associated with the TCJA. ▪ Deemed repatriation: The TCJA imposes a one-time tax for deemed repatriation of foreign undistributed earnings as determined under U.S. federal tax law. Under this provision, a U.S. shareholder must include in taxable income its pro-rata share of foreign undistributed earnings, which are taxed at 15.5 percent on cash or cash equivalents and 8 percent on cumulative other earnings. Sempra Energy Consolidated recorded deemed repatriation tax expense of $328 million . Based on our preliminary analysis, we currently anticipate using our existing NOLs to offset the deemed repatriation tax liability. In addition, we plan to repatriate these foreign undistributed earnings (estimated to be approximately $4 billion ) that have now been taxed at the U.S. federal level. As a result, for the year ended December 31, 2017, we accrued $360 million of U.S. state and non-U.S. withholding tax expense on this expected future repatriation. This liability could change as a result of various factors, such as interpretation and clarification of the TCJA provisions, changes in foreign tax laws, foreign currency movements, the source of cash to be repatriated or adjustments to our provisional estimates, as we discuss below. We have not recorded deferred income tax with respect to remaining basis differences of approximately $1 billion between financial statement and income tax investment amounts in our non-U.S subsidiaries as of December 31, 2017 because we consider them to be indefinitely reinvested. It is not practicable to determine the hypothetical amount of tax that might be payable if the underlying basis differences were realized. If these basis differences were realized, we would need to adjust our income tax provision in the period we determine that they are no longer indefinitely reinvested. EFFECTS OF THE TAX CUTS AND JOBS ACT OF 2017 (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas Consolidated Balance Sheets: Decrease in net deferred income tax liabilities due to remeasurement $ (2,220 ) $ (1,400 ) $ (972 ) Increase in net regulatory liabilities from remeasurement of deferred income tax assets and liabilities $ 2,402 $ 1,428 $ 974 Consolidated Statements of Operations: Income tax expense related to remeasurement of deferred income tax assets and liabilities $ 182 $ 28 $ 2 Income tax expense related to deemed repatriation 328 — — U.S. state and non-U.S. withholding tax expense related to expected future repatriation of foreign earnings 360 — — Total increase in income tax expense $ 870 $ 28 $ 2 We recorded the effects of the TCJA in 2017 using our best estimates and the information available to us through the date the financial statements were issued. However, our analysis is ongoing and as such, the income tax effects that we have recorded are provisional. As permitted by and in accordance with the guidance issued by the SEC, we may adjust our provisional estimates in future reporting periods throughout 2018 as we complete our analysis and as more information becomes available, and these adjustments may affect earnings. Events and information that may result in adjustments to our provisional estimates include interpretations or rulings by the U.S. Department of the Treasury or states, the filing of our 2017 income tax return and the finalization of our calculation of foreign undistributed earnings. For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment: ▪ repairs expenditures related to a certain portion of utility plant fixed assets ▪ the equity portion of AFUDC ▪ a portion of the cost of removal of utility plant assets ▪ utility self-developed software expenditures ▪ depreciation on a certain portion of utility plant assets ▪ state income taxes The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment. The 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings. We expect that certain amounts recorded in the tracking accounts may give rise to regulatory assets or liabilities. We discuss the tracking accounts further in Note 14. The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy Consolidated are as follows: GEOGRAPHIC COMPONENTS (Dollars in millions) Pretax book income Years ended December 31, 2017 2016 2015 U.S. $ 878 $ 773 $ 1,189 Non-U.S. 707 1,057 515 Total $ 1,585 $ 1,830 $ 1,704 U.S. pretax book income decreased in 2016 compared to 2015 at the California Utilities primarily due to the reallocation of 2012-2015 income tax benefits generated from income tax repairs deductions to ratepayers pursuant to the 2016 GRC FD, as we discuss in Note 14; at Sempra LNG & Midstream for the loss on permanent release of pipeline capacity, as we discuss in Note 15; and the impairment charge related to the investment in Rockies Express, as we discuss in Note 3. U.S. pretax income remained lower in 2017 due to the write-off of SDG&E’s wildfire regulatory asset, as we discuss in Note 15. Non-U.S. pretax book income was lower in 2017 and 2015 compared to 2016 primarily due to the noncash gain in 2016 associated with the remeasurement of our equity interest in IEnova Pipelines, as we discuss in Note 3. The components of income tax expense are as follows: INCOME TAX EXPENSE (BENEFIT) (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Current: U.S. federal $ — $ — $ 3 U.S. state — 1 (24 ) Non-U.S. 116 171 123 Total 116 172 102 Deferred: U.S. federal 536 78 242 U.S. state 297 9 34 Non-U.S. 327 135 (32 ) Total 1,160 222 244 Deferred investment tax credits — (5 ) (5 ) Total income tax expense $ 1,276 $ 389 $ 341 SDG&E: Current: U.S. federal $ 100 $ — $ 12 U.S. state 65 22 77 Total 165 22 89 Deferred: U.S. federal 29 223 233 U.S. state (41 ) 38 (35 ) Total (12 ) 261 198 Deferred investment tax credits 2 (3 ) (3 ) Total income tax expense $ 155 $ 280 $ 284 SoCalGas: Current: U.S. federal $ — $ — $ (1 ) U.S. state 23 40 12 Total 23 40 11 Deferred: U.S. federal 144 123 122 U.S. state (5 ) (18 ) 7 Total 139 105 129 Deferred investment tax credits (2 ) (2 ) (2 ) Total income tax expense $ 160 $ 143 $ 138 We show the components of deferred income taxes, which reflect the effects of the TCJA, at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below: DEFERRED INCOME TAXES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) December 31, 2017 2016 Deferred income tax liabilities: Differences in financial and tax bases of fixed assets, investments and other assets (1) $ 4,233 $ 6,111 U.S. state and non-U.S. withholding tax on repatriation of foreign earnings 360 — Regulatory balancing accounts 376 783 Property taxes 37 63 Other deferred income tax liabilities 117 143 Total deferred income tax liabilities 5,123 7,100 Deferred income tax assets: Tax credits 1,066 431 Net operating losses 968 2,304 Compensation-related items 199 252 Postretirement benefits 251 434 Other deferred income tax assets 115 87 Accrued expenses not yet deductible 60 112 Deferred income tax assets before valuation allowances 2,659 3,620 Less: valuation allowances 133 31 Total deferred income tax assets 2,526 3,589 Net deferred income tax liability (2) $ 2,597 $ 3,511 (1) In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries. (2) At December 31, 2017 and 2016, includes $170 million and $234 million , respectively, recorded as a noncurrent asset and $2,767 million and $3,745 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets. DEFERRED INCOME TAXES – SDG&E AND SOCALGAS (Dollars in millions) SDG&E SoCalGas December 31, December 31, 2017 2016 2017 2016 Deferred income tax liabilities: Differences in financial and tax bases of utility plant and other assets $ 1,472 $ 2,549 $ 987 $ 1,699 Regulatory balancing accounts 113 379 271 411 Property taxes 26 42 12 21 Other 10 10 1 4 Total deferred income tax liabilities 1,621 2,980 1,271 2,135 Deferred income tax assets: Net operating losses — — 58 83 Tax credits 7 27 15 17 Postretirement benefits 43 98 152 244 Compensation-related items 5 8 25 32 State income taxes 14 — 7 19 Accrued expenses not yet deductible 3 7 12 20 Other 19 11 7 11 Total deferred income tax assets 91 151 276 426 Net deferred income tax liability $ 1,530 $ 2,829 $ 995 $ 1,709 The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017. NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS (Dollars in millions) Unused amount at December 31, 2017 Year expiration begins Sempra Energy Consolidated: U.S. federal: NOLs (1) $ 3,145 2031 General business tax credits (1) 389 2032 Foreign tax credits (2) 631 2024 U.S. state (2) : NOLs 2,295 2019 General business tax credits 51 2018 Non-U.S. (2) NOLs 607 2018 SoCalGas: U.S. federal (1) : NOLs $ 334 2032 General business tax credits 12 2031 (1) We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis. (2) We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below. At December 31, 2017 , Sempra Energy recorded a valuation allowance against a portion of its total deferred income tax assets, as shown above in the “Deferred Income Taxes – Sempra Energy Consolidated” table. A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. Of the valuation allowances recorded to date, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses in various U.S. state and non-U.S. jurisdictions resulting in a deferred income tax asset related to NOLs, as shown in the “Net Operating Losses and Tax Credit Carryforwards” table above, that we currently do not believe will be realized on a more-likely-than-not basis. Of Sempra Energy’s total valuation allowance of $133 million at December 31, 2017 , $20 million is related to non-U.S. NOLs and tax credits, $30 million to U.S. state NOLs and tax credits, and $83 million to U.S. foreign tax credits. Of Sempra Energy’s total valuation allowance of $31 million at December 31, 2016 , $1 million was related to non-U.S. NOLs and $30 million to U.S. state NOLs and tax credits. Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31: RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS (Dollars in millions) 2017 2016 2015 Sempra Energy Consolidated: Balance at January 1 $ 90 $ 87 $ 117 Increase in prior period tax positions 22 2 10 Decrease in prior period tax positions (15 ) (2 ) — Increase in current period tax positions 4 6 8 Settlements with taxing authorities (12 ) (3 ) (48 ) Balance at December 31 $ 89 $ 90 $ 87 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (77 ) $ (87 ) $ (83 ) increase the effective tax rate (1) 20 36 32 SDG&E: Balance at January 1 $ 22 $ 20 $ 14 Increase in prior period tax positions 9 — 5 Decrease in prior period tax positions (11 ) — — Increase in current period tax positions — 2 2 Settlements with taxing authorities (10 ) — (1 ) Balance at December 31 $ 10 $ 22 $ 20 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (7 ) $ (19 ) $ (16 ) increase the effective tax rate (1) 1 13 11 SoCalGas: Balance at January 1 $ 29 $ 27 $ 19 Increase in prior period tax positions 3 — 2 Decrease in prior period tax positions — (2 ) — Increase in current period tax positions 4 4 6 Settlements with taxing authorities (1 ) — — Balance at December 31 $ 35 $ 29 $ 27 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (26 ) $ (29 ) $ (27 ) increase the effective tax rate (1) 20 24 21 (1) Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above. It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following: POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS (Dollars in millions) At December 31, 2017 2016 2015 Sempra Energy Consolidated: Expiration of statutes of limitations on tax assessments $ — $ (2 ) $ (2 ) Potential resolution of audit issues with various U.S. federal, state and local and non-U.S. taxing authorities (8 ) (36 ) (32 ) $ (8 ) $ (38 ) $ (34 ) SDG&E: Expiration of statutes of limitations on tax assessments $ — $ (1 ) $ (1 ) Potential resolution of audit issues with various U.S. federal, state and local taxing authorities (6 ) (10 ) (8 ) $ (6 ) $ (11 ) $ (9 ) SoCalGas: Potential resolution of audit issues with various U.S. federal, state and local taxing authorities $ (2 ) $ (25 ) $ (22 ) Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Consolidated Statements of Operations. Sempra Energy Consolidated accrued a negligible amount and $1 million for interest expense and penalties at December 31, 2017 and 2016, respectively, on the Consolidated Balance Sheets, and recorded negligible amounts of interest income and penalties in each of 2017 and 2016 and $2 million in 2015 on the Consolidated Statements of Operations. SDG&E and SoCalGas accrued negligible amounts of interest expense and penalties at December 31, 2017 and 2016 on the Consolidated Balance Sheets, and recorded negligible amounts of interest expense and penalties in 2017, 2016 and 2015 on the Consolidated Statements of Operations. INCOME TAX AUDITS Sempra Energy is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2013. We are subject to examination by major state tax jurisdictions for tax years after 2008. Certain major non-U.S. income tax returns for tax years 2008 through the present are open to examination. We are also open to examination for non-U.S. income tax returns related to our prior interest in our commodities business, which we divested in 2010, for years 1996 through 2010. In addition, we have filed state refund claims for tax years back to 2006. The pre-2009 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years. SDG&E and SoCalGas are subject to U.S. federal income tax as well as income tax of state jurisdictions. They remain subject to examination for U.S. federal tax years after 2013 and by state tax jurisdictions for tax years after 2008.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS We are required by applicable U.S. GAAP to: ▪ recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position; ▪ measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and ▪ recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity. The detailed information presented below covers the employee benefit plans of Sempra Energy and its consolidated subsidiaries. Sempra Energy has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology. IEnova has an unfunded noncontributory defined benefit plan covering all employees. Chilquinta Energía has an unfunded noncontributory defined benefit plan covering all employees hired before October 1, 1981 and an unfunded noncontributory termination indemnity plan covering represented employees. The plans generally provide defined benefits to retirees based on date of hire, years of service and final average earnings. Sempra Energy also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses. Chilquinta Energía also has two noncontributory postretirement benefit plans which cover represented employees – a health care plan and an energy subsidy plan that provides for reduced energy rates. The health care plan includes benefits for retirees’ spouses and dependents. Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans. RABBI TRUST In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $455 million and $430 million at December 31, 2017 and 2016 , respectively. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS Special Termination Benefits Affecting 2017 and 2016 In 2017, certain represented and in 2016, certain nonrepresented employees age 62 or older with 5 years of service or age 55 to 61 with 10 years of service that retired under the Voluntary Retirement Enhancement Program offered in either of those years received an additional postretirement health benefit in the form of a $100,000 Health Reimbursement Account. We treated the benefit obligation attributable to the Health Reimbursement Account as a special termination benefit. This resulted in increases to the recorded liability for PBOP and net periodic benefit cost of $18 million for each of Sempra Energy Consolidated and SoCalGas in 2017, and $26 million for Sempra Energy Consolidated, $14 million for SDG&E and $11 million for SoCalGas in 2016. The Voluntary Retirement Enhancement Program resulted in a higher than expected number of retirements in 2017 and 2016. As a result, the total lump sum benefits paid from the Sempra Energy nonqualified and SoCalGas qualified pension plans in 2017, and the SDG&E qualified pension plan in 2016, exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $194 million at Sempra Energy Consolidated and $175 million at SoCalGas in 2017, and $75 million at each of Sempra Energy Consolidated and SDG&E in 2016. This also resulted in settlement charges in net periodic benefit cost of $38 million at Sempra Energy Consolidated and $30 million at SoCalGas in 2017, and $16 million at each of Sempra Energy Consolidated and SDG&E in 2016. The settlement charges at SoCalGas in 2017, and at SDG&E in 2016, were recorded as regulatory assets on the Consolidated Balance Sheets. Measurement dates of December 31, 2017 and 2016 were used for the respective settlement accounting triggered in each year, as the year-to-date lump sum benefit payments first exceeded the settlement threshold in December of both of those years. Divestiture Affecting 2016 On September 12, 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas, as we discuss in Note 3. The benefit obligations and plan assets of the benefit plans that covered employees of Mobile Gas and Willmut Gas were transferred to the buyer on the date of sale. This resulted in decreases to the recorded pension liability and other postretirement benefit plan liability of $61 million and $6 million , respectively, and decreases to pension plan assets and other postretirement benefit plan assets of $44 million and $4 million , respectively, for Sempra Energy Consolidated. Benefit Obligations and Assets The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2017 and 2016 , and a statement of the funded status at December 31, 2017 and 2016 : PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 3,679 $ 3,649 $ 922 $ 963 Service cost 117 107 21 20 Interest cost 151 160 39 42 Contributions from plan participants — — 20 20 Actuarial loss (gain) 286 116 6 (81 ) Benefit payments (182 ) (217 ) (63 ) (61 ) Divestiture of EnergySouth — (61 ) — (6 ) Plan amendments 1 — — — Special termination benefits — — 18 26 Curtailments (1 ) — — — Settlements (194 ) (75 ) — (1 ) Net obligation at December 31 3,857 3,679 963 922 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 2,459 2,484 1,057 1,003 Actual return on plan assets 421 207 185 94 Employer contributions 155 104 10 6 Contributions from plan participants — — 20 20 Benefit payments (182 ) (217 ) (63 ) (61 ) Divestiture of EnergySouth — (44 ) — (4 ) Settlements (194 ) (75 ) — (1 ) Fair value of plan assets at December 31 2,659 2,459 1,209 1,057 Funded status at December 31 $ (1,198 ) $ (1,220 ) $ 246 $ 135 Net recorded (liability) asset at December 31 $ (1,198 ) $ (1,220 ) $ 246 $ 135 PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SAN DIEGO GAS & ELECTRIC COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 935 $ 965 $ 190 $ 165 Service cost 29 29 5 5 Interest cost 38 41 8 7 Contributions from plan participants — — 7 7 Actuarial loss (gain) 50 7 (9 ) 6 Benefit payments (83 ) (25 ) (16 ) (14 ) Special termination benefits — — — 14 Settlements — (75 ) — — Transfer of liability from (to) other plans 2 (7 ) — — Net obligation at December 31 971 935 185 190 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 714 752 169 161 Actual return on plan assets 120 59 30 13 Employer contributions 22 3 5 2 Contributions from plan participants — — 7 7 Benefit payments (83 ) (25 ) (16 ) (14 ) Settlements — (75 ) — — Transfer of assets from other plans 3 — — — Fair value of plan assets at December 31 776 714 195 169 Funded status at December 31 $ (195 ) $ (221 ) $ 10 $ (21 ) Net recorded (liability) asset at December 31 $ (195 ) $ (221 ) $ 10 $ (21 ) PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SOUTHERN CALIFORNIA GAS COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 2,343 $ 2,255 $ 691 $ 752 Service cost 76 67 14 14 Interest cost 98 101 29 32 Contributions from plan participants — — 13 13 Actuarial loss (gain) 216 77 16 (86 ) Benefit payments (73 ) (158 ) (44 ) (45 ) Special termination benefits — — 18 11 Settlements (175 ) — — — Transfer of liability from other plans 1 1 — — Net obligation at December 31 2,486 2,343 737 691 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 1,579 1,537 870 822 Actual return on plan assets 269 128 151 79 Employer contributions 93 72 3 1 Contributions from plan participants — — 13 13 Benefit payments (73 ) (158 ) (44 ) (45 ) Settlements (175 ) — — — Transfer of assets from other plans 1 — — — Fair value of plan assets at December 31 1,694 1,579 993 870 Funded status at December 31 $ (792 ) $ (764 ) $ 256 $ 179 Net recorded (liability) asset at December 31 $ (792 ) $ (764 ) $ 256 $ 179 Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and Other Postretirement Benefit Plans” and updates to census data. In 2017, 2016 and 2015, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. We have incorporated these assumptions, adjusted for the Sempra Energy companies’ actual mortality experience, in our calculations for each of those years. Actuarial losses in pension plans at Sempra Energy Consolidated in 2017 were driven primarily by actuarial losses at SDG&E and SoCalGas due to a decrease in discount rates and, additionally at SoCalGas, actuarial losses due to updated census data. Actuarial losses in PBOP plans at Sempra Energy Consolidated in 2017 were driven primarily by actuarial losses at SDG&E and SoCalGas due to a decrease in discount rates, offset by actuarial gains at SDG&E and partially offset by actuarial gains at SoCalGas due to a reduction in the 2018 expected health care costs. Net Assets and Liabilities The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year. The 10 -percent corridor accounting method is used at Sempra Energy Consolidated, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10 -percent corridor accounting methods help mitigate volatility of net periodic costs from year to year. We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in Accumulated Other Comprehensive Income (Loss) on the balance sheet. The California Utilities record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on agreements with regulatory agencies. The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their plans as authorized by the CPUC. The annual contributions to the pension plans are limited to a minimum required funding amount as determined by the IRS. The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Until the date of sale, Mobile Gas recorded annual pension and other postretirement net periodic benefit costs based on an estimate of the net periodic cost at the beginning of the year calculated in accordance with U.S. GAAP for pension and PBOP plans, as authorized by the Alabama Public Service Commission. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities. The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31: PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31 (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Noncurrent assets $ — $ — $ 266 $ 179 Current liabilities (69 ) (56 ) (1 ) — Noncurrent liabilities (1,129 ) (1,164 ) (19 ) (44 ) Net recorded (liability) asset $ (1,198 ) $ (1,220 ) $ 246 $ 135 SDG&E: Noncurrent assets $ — $ — $ 10 $ — Current liabilities (13 ) (10 ) — — Noncurrent liabilities (182 ) (211 ) — (21 ) Net recorded (liability) asset $ (195 ) $ (221 ) $ 10 $ (21 ) SoCalGas: Noncurrent assets $ — $ — $ 256 $ 179 Current liabilities (3 ) (2 ) — — Noncurrent liabilities (789 ) (762 ) — — Net recorded (liability) asset $ (792 ) $ (764 ) $ 256 $ 179 Amounts recorded in AOCI at December 31, 2017 and 2016 , net of income tax effects and amounts recorded as regulatory assets, are as follows: AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Net actuarial (loss) gain $ (84 ) $ (95 ) $ 4 $ 3 Prior service cost (4 ) (4 ) — — Total $ (88 ) $ (99 ) $ 4 $ 3 SDG&E: Net actuarial loss $ (8 ) $ (8 ) SoCalGas: Net actuarial loss $ (6 ) $ (6 ) Prior service cost (2 ) (3 ) Total $ (8 ) $ (9 ) The accumulated benefit obligation for defined benefit pension plans at December 31, 2017 and 2016 was as follows: ACCUMULATED BENEFIT OBLIGATION (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas 2017 2016 2017 2016 2017 2016 Accumulated benefit obligation $ 3,551 $ 3,465 $ 930 $ 904 $ 2,241 $ 2,167 Sempra Energy, SDG&E and SoCalGas each have a funded pension plan. We also have unfunded pension plans at Sempra Energy, SDG&E, SoCalGas, IEnova and Chilquinta Energía. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31: OBLIGATIONS OF FUNDED PENSION PLANS (Dollars in millions) 2017 2016 Sempra Energy Consolidated: Projected benefit obligation $ 3,623 $ 3,431 Accumulated benefit obligation 3,334 3,227 Fair value of plan assets 2,659 2,459 SDG&E: Projected benefit obligation $ 939 $ 902 Accumulated benefit obligation 900 874 Fair value of plan assets 776 714 SoCalGas: Projected benefit obligation $ 2,462 $ 2,320 Accumulated benefit obligation 2,220 2,148 Fair value of plan assets 1,694 1,579 Net Periodic Benefit Cost The following three tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31: NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 117 $ 107 $ 114 $ 21 $ 20 $ 26 Interest cost 151 160 154 39 42 44 Expected return on assets (161 ) (166 ) (173 ) (66 ) (69 ) (68 ) Amortization of: Prior service cost (credit) 11 11 11 1 — (4 ) Actuarial loss (gain) 36 30 38 (4 ) (1 ) — Settlement and curtailment charges 38 16 4 — — — Special termination benefits — — — 18 26 — Regulatory adjustment (42 ) (57 ) (110 ) — (11 ) 12 Total net periodic benefit cost 150 101 38 9 7 10 CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss (gain) — 26 17 (2 ) (2 ) (4 ) Prior service cost 1 — 4 — — — Amortization of actuarial loss (18 ) (10 ) (14 ) — — — Amortization of prior service cost (1 ) (1 ) — — — — Total recognized in OCI (18 ) 15 7 (2 ) (2 ) (4 ) Total recognized in net periodic benefit cost and OCI $ 132 $ 116 $ 45 $ 7 $ 5 $ 6 NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SAN DIEGO GAS & ELECTRIC COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 29 $ 29 $ 29 $ 5 $ 5 $ 7 Interest cost 38 41 39 8 7 8 Expected return on assets (47 ) (49 ) (54 ) (11 ) (12 ) (11 ) Amortization of: Prior service cost 1 1 8 3 3 3 Actuarial loss (gain) 9 10 2 — (1 ) — Settlement charge — 16 — — — — Special termination benefits — — — — 14 — Regulatory adjustment (8 ) (45 ) (20 ) — (14 ) — Total net periodic benefit cost 22 3 4 5 2 7 CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss (gain) 2 1 (6 ) — — — Amortization of actuarial loss (1 ) (1 ) (1 ) — — — Total recognized in OCI 1 — (7 ) — — — Total recognized in net periodic benefit cost and OCI $ 23 $ 3 $ (3 ) $ 5 $ 2 $ 7 NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SOUTHERN CALIFORNIA GAS COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 76 $ 67 $ 74 $ 14 $ 14 $ 17 Interest cost 98 101 98 29 32 34 Expected return on assets (103 ) (103 ) (106 ) (53 ) (56 ) (56 ) Amortization of: Prior service cost (credit) 9 9 9 (3 ) (4 ) (7 ) Actuarial loss (gain) 19 11 21 (3 ) — — Settlement charge 30 — — — — — Special termination benefits — — — 18 11 — Regulatory adjustment (34 ) (12 ) (90 ) — 3 12 Total net periodic benefit cost 95 73 6 2 — — CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss — 4 — — — — Prior service cost — 2 2 — — — Amortization of prior service cost (1 ) — — — — — Total recognized in OCI (1 ) 6 2 — — — Total recognized in net periodic benefit cost and OCI $ 94 $ 79 $ 8 $ 2 $ — $ — The estimated net loss for the pension and PBOP plans that will be amortized from AOCI into net periodic benefit cost in 2018 is $10 million for Sempra Energy Consolidated and $1 million for each of SDG&E and SoCalGas. The estimated prior service cost that will be similarly amortized in 2018 is $1 million for each of Sempra Energy Consolidated and SoCalGas and a negligible amount for SDG&E. Assumptions for Pension and Other Postretirement Benefit Plans Benefit Obligation and Net Periodic Benefit Cost Except for the IEnova and Chilquinta Energía plans, we develop the discount rate assumptions based on the results of a third party modeling tool that matches each plan’s expected cash flows to interest rates and expected maturity values of individually selected bonds in a hypothetical portfolio. The model controls the level of accumulated surplus that may result from the selection of bonds based solely on their premium yields by limiting the number of years to look back for selection to 3 years for pre-30-year and 6 years for post-30-year benefit payments. Additionally, the model ensures that an adequate number of bonds are selected in the portfolio by limiting the amount of the plan’s benefit payments that can be met by a single bond to 7.5 percent. We selected individual bonds from a universe of Bloomberg AA-rated bonds that: ▪ have an outstanding issue of at least $50 million; ▪ are non-callable (or callable with make-whole provisions); ▪ exclude collateralized bonds; and ▪ exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded . This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics: ▪ The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio. ▪ Recent events have caused significant price volatility to which rating agencies have not reacted. ▪ Lack of liquidity is causing price quotes to vary significantly from broker to broker. We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP. We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. We develop the discount rate assumptions for the plans at Chilquinta Energía based on 10 -year Chilean government bond yields and the expected local long-term rate of inflation. These methods for developing the discount rate are required when there is no deep market for high quality corporate bonds. Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types. We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP. The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows: WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION AT DECEMBER 31 Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Discount rate 3.65 % 4.08 % 3.70 % 4.19 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SDG&E: Discount rate 3.64 % 4.08 % 3.65 % 4.15 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SoCalGas: Discount rate 3.65 % 4.10 % 3.70 % 4.20 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST YEARS ENDED DECEMBER 31 Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 Sempra Energy Consolidated: Discount rate 4.08 % 4.46 % 4.09 % 4.19 % 4.49 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.47 6.98 6.98 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SDG&E: Discount rate 4.08 % 4.35 % 4.00 % 4.15 % 4.50 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.91 6.90 6.91 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SoCalGas: Discount rate 4.10 % 4.50 % 4.15 % 4.20 % 4.50 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.37 7.00 7.00 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 Health Care Cost Trend Rates Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans: ASSUMED HEALTH CARE COST TREND RATES AT DECEMBER 31 Other postretirement benefit plans (1) Pre-65 retirees Retirees aged 65 years and older 2017 2016 2015 2017 2016 2015 Health care cost trend rate assumed for next year 7.00 % 8.00 % 8.10 % 5.00 % 5.50 % 5.50 % Rate to which the cost trend rate is assumed to decline (the ultimate trend) 5.00 % 5.00 % 5.00 % 4.50 % 4.50 % 4.50 % Year the rate reaches the ultimate trend 2022 2022 2022 2022 2022 2022 (1) Excludes Mobile Gas plan. For Mobile Gas, which we deconsolidated on September 12, 2016, the health care cost trend rate assumed for next year for all retirees was 8.10 percent in 2015; the ultimate trend was 5.00 percent in 2015; and the year the rate reaches the ultimate trend was 2022 in 2015. For Chilquinta Energía, the health care cost trend rate assumed for next year, and the ultimate trend, was 3.00 percent in each of 2017, 2016 and 2015. A one-percent change in assumed health care cost trend rates would have had the following effects in 2017: EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas 1% 1% 1% 1% 1% 1% increase decrease increase decrease increase decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 5 $ (4 ) $ 1 $ — $ 4 $ (3 ) Effect on the health care component of the accumulated other postretirement benefit obligations 53 (44 ) 3 (2 ) 48 (40 ) Plan Assets Investment Allocation Strategy for Sempra Energy’s Pension Master Trust Sempra Energy’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts as we discuss below for certain of the California Utilities’ PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra Energy. The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ target asset allocations are ▪ 38 percent domestic equity ▪ 26 percent international equity ▪ 18 percent long credit ▪ 8 percent ultra-long duration government securities ▪ 5 percent return-seeking credit ▪ 5 percent real assets The asset allocation of the plans is reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including: ▪ long-term cost ▪ variability and level of contributions ▪ funded status ▪ a range of expected outcomes over varying confidence levels We maintain asset allocations at strategic levels with reasonable bands of variance. In accordance with the Sempra Energy pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities. Rate of Return Assumption The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 7 -percent expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 7 percent and 9 percent on return-seeking assets and between 3 percent and 5 percent for risk-mitigating assets. Certain trusts that hold assets for the SDG&E other postretirement benefit plan are subject to taxation, which impacts the expected after-tax return on assets in the plan. Concentration of Risk Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited. I nvestment Strategy for SDG&E’s and SoCalGas’ Other Postretirement Benefit Plans SDG&E’s and SoCalGas’ PBOP plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Certain assets of SoCalGas’ PBOP plans, which are held in the pension master trust, are invested based on an allocation that seeks to mitigate risks for the assets of these plans, with 38 percent invested in return-seeking and 62 percent invested in risk-mitigating assets. The assets in the Voluntary Employee Beneficiary Association trusts are invested at an allocation similar to the pension master trust, with 74 percent invested in return-seeking and 26 percent invested in risk-mitigating assets. These allocations are periodically reviewed to ensure that plan assets are best positioned to meet plan obligations. Fair Value of Pension and Other Postretirement Benefit Plan Assets We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ PBOP plans based on the fair value hierarchy, except for certain investments measured at net asset value (NAV). The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts. Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges. Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information. Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Investments in certain fixed income securities are valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks for the remaining fixed income securities. Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets. Private Equity Funds – These funds consist of investments in private equities that are held by limited partnerships following various strategies, including private equity and corporate finance. These partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. The value is determined based on the NAV of the proportionate share of an ownership interest in partners’ capital. Holdings in these types of private equity funds are negligible, as the funds are well past their expected investment term and have distributed the bulk of proceeds from investment sales. Derivative Financial Instruments – Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index future contracts are valued at the last sales price quoted on the exchange on which they primarily trade. While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain fi

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Share-based Compensation	SHARE-BASED COMPENSATION SEMPRA ENERGY EQUITY COMPENSATION PLANS Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including: ▪ non-qualified stock options ▪ incentive stock options ▪ restricted stock awards ▪ restricted stock units ▪ stock appreciation rights ▪ performance awards ▪ stock payments ▪ dividend equivalents Eligible employees, including those from the California Utilities, participate in Sempra Energy’s share-based compensation plans as a component of their compensation package. In the three years ended December 31, 2017, Sempra Energy had the following types of equity awards outstanding: ▪ Non-Qualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a four -year period, and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements, in accordance with the terms of the grant, or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment. ▪ Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra Energy common stock at the end of three -year (for awards granted during or after 2015) or four -year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra Energy’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our targets for awards that vest based on EPS growth. ◦ For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50 percent of the number of granted RSUs may be issued. ◦ For awards granted during or after 2014, up to an additional 100 percent of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels. ◦ For awards granted in 2015 and 2016, and certain awards granted in 2017, that vest based on Sempra Energy’s total return to shareholders, a modifier adds 20 percent to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra Energy and reduces the award’s payout by 20 percent for performance in the bottom quartile. However, in no event will more than an additional 100 percent of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices. If Sempra Energy’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis. ▪ Other Performance-Based Restricted Stock Units: RSUs were granted in 2014 and 2015 in connection with the creation of Cameron LNG JV. ◦ The 2014 awards vest to the extent that the Compensation Committee of Sempra Energy’s board of directors determines that the objectives of the joint venture are continuing to be achieved. These awards vest on the anniversary of the grant date over a period of either two or three years. ◦ The 2015 awards vest to the extent that the Compensation Committee of Sempra Energy’s board of directors determines that Sempra Energy has achieved positive cumulative net income for fiscal years 2015 through 2017 and Cameron LNG JV has commenced commercial operations of the first train. ▪ Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest at the end of three -year (for awards granted during or after 2015) or four -year service periods. ▪ Restricted Stock Awards: RSAs are solely service-based and generally vest at the end of four years of service. Accelerated vesting of RSAs may occur upon eligibility for retirement. Holders of RSAs have full voting rights. For RSA and RSU awards, vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, in accordance with severance pay agreements , or at the discretion of the Compensation Committee of Sempra Energy’s board of directors . Dividend equivalents on shares subject to RSAs and RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSAs and RSUs to which the dividends relate. In April 2013, the IEnova board of directors approved the IEnova 2013 Long-Term Incentive Plan. The purpose of this plan is to align the interests of employees and directors of IEnova with its shareholders. All awards issued from this plan and any related dividend equivalents will settle in cash at vesting based on the price of IEnova common stock. In 2017, 2016 and 2015, IEnova granted 1,043,709 RSUs, 378,367 RSUs and 278,538 RSUs, respectively, from this plan, 1,374,114 of which remain outstanding at December 31, 2017. During 2017, 2016 and 2015, IEnova paid cash of $2 million , $1 million and $4 million , respectively, to settle vested awards. SHARE-BASED AWARDS AND COMPENSATION EXPENSE At December 31, 2017, 5,589,925 common shares were authorized and available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases. We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for non-qualified stock options, RSAs and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, in the year that an employee becomes eligible for retirement, the remaining expense related to the employee’s awards is recognized immediately. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. Beginning in 2016, we recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments. In 2015, $52 million in excess tax benefits was recorded within Sempra Energy’s Shareholders’ Equity. Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra Energy plans’ corporate staff costs. Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows: SHARE-BASED COMPENSATION EXPENSE (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Share-based compensation expense, before income taxes $ 78 $ 46 $ 48 Income tax benefit (31 ) (18 ) (19 ) $ 47 $ 28 $ 29 Capitalized share-based compensation cost $ 9 $ 7 $ 6 Excess income tax benefit $ — $ (34 ) $ — SDG&E: Share-based compensation expense, before income taxes $ 13 $ 7 $ 8 Income tax benefit (5 ) (3 ) (3 ) $ 8 $ 4 $ 5 Capitalized share-based compensation cost $ 5 $ 4 $ 4 Excess income tax benefit $ — $ (7 ) $ — SoCalGas: Share-based compensation expense, before income taxes $ 17 $ 8 $ 10 Income tax benefit (7 ) (3 ) (4 ) $ 10 $ 5 $ 6 Capitalized share-based compensation cost $ 4 $ 3 $ 2 Excess income tax benefit $ — $ (4 ) $ — SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS We use a Black-Scholes option-pricing model to estimate the fair value of each non-qualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on the historical volatility of Sempra Energy’s common stock price. We base the average expected life for options on the contractual term of the option and expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected life assumed at the date of the grant. The following table shows a summary of non-qualified stock options at December 31, 2017 and activity for the year then ended: NON-QUALIFIED STOCK OPTIONS Common shares under option Weighted- average exercise price Weighted- average remaining contractual term (in years) Aggregate intrinsic value (in millions) Outstanding at January 1, 2017 360,255 $ 52.46 Exercised (164,454 ) $ 55.04 Outstanding at December 31, 2017 195,801 $ 50.30 1.5 $ 11 Vested at December 31, 2017 195,801 $ 50.30 1.5 $ 11 Exercisable at December 31, 2017 195,801 $ 50.30 1.5 $ 11 The aggregate intrinsic value at December 31, 2017 is the total of the difference between Sempra Energy’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for non-qualified stock options exercised in the last three years was ▪ $9 million in 2017 ▪ $8 million in 2016 ▪ $12 million in 2015 No stock options were granted in 2017, 2016 or 2015. All outstanding stock options were fully vested and all compensation cost related to stock options had been recognized as of December 31, 2014. We received cash of $9 million from stock option exercises during 2017. SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS We use a Monte-Carlo simulation model to estimate the fair value of our RSAs and our RSUs that vest based on Sempra Energy’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return, and a number of other variables. Below are key assumptions for awards granted in 2017, 2016 and 2015 for Sempra Energy: KEY ASSUMPTIONS FOR AWARDS GRANTED Years ended December 31, 2017 2016 2015 Risk-free rate of return 1.5 % 1.3 % 1.1 % Stock price volatility 17 16 14 Restricted Stock Awards No RSAs were granted in 2017, 2016 or 2015. All outstanding RSAs were fully vested and all compensation cost related to RSAs had been recognized as of December 31, 2016. The total fair value of RSA shares vested during the year was a negligible amount in 2016 and $1 million in 2015. Restricted Stock Units We provide below a summary of Sempra Energy’s RSUs as of December 31, 2017 and the activity during the year. RESTRICTED STOCK UNITS Performance-based restricted stock units Service-based restricted stock units Units Weighted- average grant-date fair value Units Weighted- average Nonvested at January 1, 2017 1,954,322 $ 88.58 305,736 $ 94.68 Granted 424,760 $ 110.54 93,619 $ 101.88 Vested (637,577 ) $ 57.42 (108,880 ) $ 79.61 Forfeited (39,888 ) $ 103.17 (4,580 ) $ 97.84 Nonvested at December 31, 2017 (1) 1,701,617 $ 105.84 285,895 $ 98.81 Expected to vest at December 31, 2017 1,670,885 $ 105.38 282,106 $ 98.65 (1) Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, except for those issued in connection with the creation of Cameron LNG JV, up to an additional 50 percent ( 100 percent for awards granted during or after 2014) of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions. The total fair value of RSU shares vested during the year was $45 million in 2017 and $46 million in each of 2016 and 2015. The $17 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2017 is expected to be recognized over a weighted-average period of 1.9 years. The weighted-average per-share fair values for performance-based RSUs granted were $100.37 and $123.30 in 2016 and 2015, respectively. The weighted-average per-share fair values for service-based RSUs granted were $93.59 and $111.43 in 2016 and 2015, respectively.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	DERIVATIVE FINANCIAL INSTRUMENTS We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below. In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below. In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Consolidated Statements of Cash Flows. HEDGE ACCOUNTING We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria. We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria. ENERGY DERIVATIVES Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows: ▪ The California Utilities use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas. ▪ SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. ▪ Sempra Mexico, Sempra LNG & Midstream and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its 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 Consolidated Statements of Operations. ▪ From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel and GHG allowances. We summarize net energy derivative volumes at December 31, 2017 and 2016 as follows: NET ENERGY DERIVATIVE VOLUMES (Quantities in millions) December 31, Commodity Unit of measure 2017 2016 California Utilities: SDG&E: Natural gas MMBtu 39 48 Electricity MWh 3 4 Congestion revenue rights MWh 59 48 SoCalGas – natural gas MMBtu — 1 Energy-Related Businesses: Sempra LNG & Midstream – natural gas MMBtu 3 31 Sempra Mexico – natural gas MMBtu 4 — In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales. INTEREST RATE DERIVATIVES We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy and its other subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes. At December 31, 2017 and 2016 , the net notional amounts of our interest rate derivatives, excluding joint ventures, were: INTEREST RATE DERIVATIVES (Dollars in millions) December 31, 2017 December 31, 2016 Notional debt Maturities Notional debt Maturities Sempra Energy Consolidated: Cash flow hedges (1) $ 861 2018-2032 $ 924 2017-2032 SDG&E: Cash flow hedge (1) 295 2018-2019 305 2017-2019 (1) Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE. FOREIGN CURRENCY DERIVATIVES We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar. We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or inflation. In addition, Sempra South American Utilities and its joint ventures use foreign currency derivatives to manage foreign currency rate risk. We discuss these derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4. At December 31, 2017 and 2016 , the net notional amounts of our foreign currency derivatives, excluding joint ventures, were: FOREIGN CURRENCY DERIVATIVES (Dollars in millions) December 31, 2017 December 31, 2016 Notional amount Maturities Notional amount Maturities Sempra Energy Consolidated: Cross-currency swaps $ 408 2018-2023 $ 408 2017-2023 Other foreign currency derivatives (1) 345 2018-2019 86 2017-2018 (1) In the first quarter of 2018, we entered into foreign currency derivatives with notional amounts totaling $650 million that expire between December 2018 and January 2019. FINANCIAL STATEMENT PRESENTATION The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets at December 31, 2017 and 2016 , including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions. DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (Dollars in millions) December 31, 2017 Current assets: Fixed-price contracts and other derivatives (1) Other assets: Sundry Current liabilities: Fixed-price contracts and other derivatives (2) Deferred credits and other liabilities: Fixed-price contracts and other derivatives Sempra Energy Consolidated: Derivatives designated as hedging instruments: Interest rate and foreign exchange instruments (3) $ 5 $ 2 $ (51 ) $ (165 ) Derivatives not designated as hedging instruments: Foreign exchange instruments — — (1 ) — Commodity contracts not subject to rate recovery 81 8 (72 ) (6 ) Associated offsetting commodity contracts (67 ) (5 ) 67 5 Commodity contracts subject to rate recovery 28 101 (65 ) (120 ) Associated offsetting commodity contracts — (1 ) — 1 Associated offsetting cash collateral — — 19 4 Net amounts presented on the balance sheet 47 105 (103 ) (281 ) Additional cash collateral for commodity contracts not subject to rate recovery 2 — — — Additional cash collateral for commodity contracts subject to rate recovery 17 — — — Total (4) $ 66 $ 105 $ (103 ) $ (281 ) SDG&E: Derivatives designated as hedging instruments: Interest rate instruments (3) $ — $ — $ (10 ) $ (3 ) Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery 26 101 (63 ) (120 ) Associated offsetting commodity contracts — (1 ) — 1 Associated offsetting cash collateral — — 19 4 Net amounts presented on the balance sheet 26 100 (54 ) (118 ) Additional cash collateral for commodity contracts subject to rate recovery 16 — — — Total (4) $ 42 $ 100 $ (54 ) $ (118 ) SoCalGas: Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery $ 2 $ — $ (2 ) $ — Net amounts presented on the balance sheet 2 — (2 ) — Additional cash collateral for commodity contracts subject to rate recovery 1 — — — Total $ 3 $ — $ (2 ) $ — (1) Included in Current Assets: Other for SoCalGas. (2) Included in Current Liabilities: Other for SoCalGas. (3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. (4) Normal purchase contracts previously measured at fair value are excluded. DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (Dollars in millions) December 31, 2016 Current assets: Fixed-price contracts and other derivatives (1) Other assets: Sundry Current liabilities: Fixed-price contracts and other derivatives (2) Deferred credits and other liabilities: Fixed-price contracts and other derivatives Sempra Energy Consolidated: Derivatives designated as hedging instruments: Interest rate and foreign exchange instruments (3) $ 7 $ 2 $ (24 ) $ (228 ) Commodity contracts not subject to rate recovery — — (14 ) — Derivatives not designated as hedging instruments: Commodity contracts not subject to rate recovery 248 36 (254 ) (28 ) Associated offsetting commodity contracts (242 ) (27 ) 242 27 Associated offsetting cash collateral — (1 ) 16 1 Commodity contracts subject to rate recovery 37 73 (57 ) (150 ) Associated offsetting commodity contracts (9 ) (1 ) 9 1 Associated offsetting cash collateral — — 5 13 Net amounts presented on the balance sheet 41 82 (77 ) (364 ) Additional cash collateral for commodity contracts not subject to rate recovery 10 — — — Additional cash collateral for commodity contracts subject to rate recovery 32 — — — Total (4) $ 83 $ 82 $ (77 ) $ (364 ) SDG&E: Derivatives designated as hedging instruments: Interest rate instruments (3) $ — $ — $ (13 ) $ (12 ) Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery 33 73 (51 ) (150 ) Associated offsetting commodity contracts (6 ) (1 ) 6 1 Associated offsetting cash collateral — — 3 13 Net amounts presented on the balance sheet 27 72 (55 ) (148 ) Additional cash collateral for commodity contracts not subject to rate recovery 1 — — — Additional cash collateral for commodity contracts subject to rate recovery 30 — — — Total (4) $ 58 $ 72 $ (55 ) $ (148 ) SoCalGas: Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery $ 4 $ — $ (6 ) $ — Associated offsetting commodity contracts (3 ) — 3 — Associated offsetting cash collateral — — 2 — Net amounts presented on the balance sheet 1 — (1 ) — Additional cash collateral for commodity contracts not subject to rate recovery 1 — — — Additional cash collateral for commodity contracts subject to rate recovery 2 — — — Total $ 4 $ — $ (1 ) $ — (1) Included in Current Assets: Other for SoCalGas. (2) Included in Current Liabilities: Other for SoCalGas. (3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. (4) Normal purchase contracts previously measured at fair value are excluded. The table below includes the effects of derivative instruments designated as fair value hedges on the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. There were no fair value hedges outstanding during the year ended December 31, 2017. FAIR VALUE HEDGE IMPACTS (Dollars in millions) Pretax gain (loss) on derivatives recognized in earnings Years ended December 31, Location 2016 2015 Sempra Energy Consolidated: Interest rate instruments Interest Expense $ 3 $ 6 Interest rate instruments Other Income, Net (2 ) (5 ) Total (1) $ 1 $ 1 (1) There was no hedge ineffectiveness in 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net. The effects of derivative instruments designated as cash flow hedges on the Consolidated Statements of Operations and in OCI and AOCI for the years ended December 31 were: CASH FLOW HEDGE IMPACTS (Dollars in millions) Pretax gain (loss) recognized in OCI Pretax gain (loss) reclassified from AOCI into earnings Years ended December 31, Years ended December 31, 2017 2016 2015 Location 2017 2016 2015 Sempra Energy Consolidated: Interest rate and foreign exchange instruments (1) $ 19 $ (8 ) $ (18 ) Interest Expense $ 4 $ (17 ) $ (18 ) Interest rate instruments (25 ) (9 ) (80 ) Equity Earnings, Before Income Tax (8 ) (10 ) (12 ) Interest rate and foreign exchange instruments — — — Remeasurement of Equity Method Investment — (7 ) — Interest rate and foreign exchange instruments (9 ) 5 (20 ) Equity Earnings, Net of Income Tax (12 ) (5 ) (13 ) Foreign exchange instruments 4 4 — Revenues: Energy- Related Businesses 2 — — Commodity contracts not subject to rate recovery 3 (13 ) 12 Revenues: Energy- Related Businesses (9 ) 6 14 Total (2) $ (8 ) $ (21 ) $ (106 ) $ (23 ) $ (33 ) $ (29 ) SDG&E: Interest rate instruments (1)(3) $ (2 ) $ (2 ) $ (6 ) Interest Expense $ (13 ) $ (12 ) $ (12 ) SoCalGas: Interest rate instruments $ — $ — $ — Interest Expense $ — $ (1 ) $ (1 ) (1) Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. (2) There was $5 million , $4 million and $2 million of losses from ineffectiveness related to these cash flow hedges in 2017 , 2016 and 2015 , respectively. (3) There was negligible hedge ineffectiveness related to these cash flow hedges in 2017 , 2016 and 2015 . For Sempra Energy Consolidated, we expect that net losses of $33 million , which are net of income tax benefit, that are currently recorded in AOCI (including $9 million of losses in noncontrolling interest related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. SoCalGas expects that $1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature. For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at December 31, 2017 is approximately 14 years and 1 year for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 18 years . The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were: UNDESIGNATED DERIVATIVE IMPACTS (Dollars in millions) Pretax gain (loss) on derivatives recognized in earnings Years ended December 31, Location 2017 2016 2015 Sempra Energy Consolidated: Interest rate and foreign exchange instruments Other Income, Net $ 49 $ (32 ) $ (4 ) Foreign exchange instruments Equity Earnings, Net of Income Tax 1 3 (4 ) Commodity contracts not subject to rate recovery Revenues: Energy-Related Businesses 16 (18 ) 42 Commodity contracts not subject to rate recovery Operation and Maintenance — 1 (1 ) Commodity contracts subject to rate recovery Cost of Electric Fuel and Purchased Power 54 (53 ) (126 ) Commodity contracts subject to rate recovery Cost of Natural Gas (2 ) (4 ) 1 Total $ 118 $ (103 ) $ (92 ) SDG&E: Commodity contracts subject to rate recovery Cost of Electric Fuel and Purchased Power $ 54 $ (53 ) $ (126 ) SoCalGas: Commodity contracts not subject to rate recovery Operation and Maintenance $ — $ 1 $ (1 ) Commodity contracts subject to rate recovery Cost of Natural Gas (2 ) (4 ) 1 Total $ (2 ) $ (3 ) $ — CONTINGENT FEATURES For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization. For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at December 31, 2017 and 2016 is $6 million and $10 million , respectively. At December 31, 2017 , if the credit ratings of Sempra Energy were reduced below investment grade, $6 million of additional assets could be required to be posted as collateral for these derivative contracts. For SDG&E, the total fair value of this group of derivative instruments in a net liability position at December 31, 2017 and 2016 is $1 million and negligible, respectively. At December 31, 2017 , if the credit ratings of SDG&E were reduced below investment grade, $1 million of additional assets could be required to be posted as collateral for these derivative contracts. For Sempra Energy Consolidated, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASURES The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 . 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. The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 in “Financial Statement Presentation.” The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 in the tables below include the following: ▪ Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2). ▪ For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information.” ▪ Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both December 31, 2017 and 2016 . There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented. RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 491 $ 5 $ — $ 496 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 45 9 — 54 Municipal bonds — 250 — 250 Other securities — 217 — 217 Total debt securities 45 476 — 521 Total nuclear decommissioning trusts (1) 536 481 — 1,017 Interest rate and foreign exchange instruments — 7 — 7 Commodity contracts not subject to rate recovery 5 12 — 17 Effect of netting and allocation of collateral (2) 2 — — 2 Commodity contracts subject to rate recovery — 2 126 128 Effect of netting and allocation of collateral (2) 12 — 5 17 Total $ 555 $ 502 $ 131 $ 1,188 Liabilities: Interest rate and foreign exchange instruments $ — $ 217 $ — $ 217 Commodity contracts not subject to rate recovery — 6 — 6 Commodity contracts subject to rate recovery 23 7 154 184 Effect of netting and allocation of collateral (2) (23 ) — — (23 ) Total $ — $ 230 $ 154 $ 384 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 508 $ — $ — $ 508 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 36 16 — 52 Municipal bonds — 206 — 206 Other securities — 141 — 141 Total debt securities 36 363 — 399 Total nuclear decommissioning trusts (1) 544 363 — 907 Interest rate and foreign exchange instruments — 9 — 9 Commodity contracts not subject to rate recovery — 15 — 15 Effect of netting and allocation of collateral (2) 2 7 — 9 Commodity contracts subject to rate recovery 1 3 96 100 Effect of netting and allocation of collateral (2) 27 — 5 32 Total $ 574 $ 397 $ 101 $ 1,072 Liabilities: Interest rate and foreign exchange instruments $ — $ 252 $ — $ 252 Commodity contracts not subject to rate recovery 16 11 — 27 Effect of netting and allocation of collateral (2) (17 ) — — (17 ) Commodity contracts subject to rate recovery 19 8 170 197 Effect of netting and allocation of collateral (2) (18 ) — — (18 ) Total $ — $ 271 $ 170 $ 441 (1) Excludes cash balances and cash equivalents. (2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset. RECURRING FAIR VALUE MEASURES – SDG&E (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 491 $ 5 $ — $ 496 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 45 9 — 54 Municipal bonds — 250 — 250 Other securities — 217 — 217 Total debt securities 45 476 — 521 Total nuclear decommissioning trusts (1) 536 481 — 1,017 Commodity contracts subject to rate recovery — — 126 126 Effect of netting and allocation of collateral (2) 11 — 5 16 Total $ 547 $ 481 $ 131 $ 1,159 Liabilities: Interest rate instruments $ — $ 13 $ — $ 13 Commodity contracts subject to rate recovery 23 5 154 182 Effect of netting and allocation of collateral (2) (23 ) — — (23 ) Total $ — $ 18 $ 154 $ 172 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 508 $ — $ — $ 508 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 36 16 — 52 Municipal bonds — 206 — 206 Other securities — 141 — 141 Total debt securities 36 363 — 399 Total nuclear decommissioning trusts (1) 544 363 — 907 Commodity contracts not subject to rate recovery — — — — Effect of netting and allocation of collateral (2) 1 — — 1 Commodity contracts subject to rate recovery 1 2 96 99 Effect of netting and allocation of collateral (2) 25 — 5 30 Total $ 571 $ 365 $ 101 $ 1,037 Liabilities: Interest rate instruments $ — $ 25 $ — $ 25 Commodity contracts subject to rate recovery 17 7 170 194 Effect of netting and allocation of collateral (2) (16 ) — — (16 ) Total $ 1 $ 32 $ 170 $ 203 (1) Excludes cash balances and cash equivalents. (2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset. RECURRING FAIR VALUE MEASURES – SOCALGAS (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Commodity contracts subject to rate recovery $ — $ 2 $ — $ 2 Effect of netting and allocation of collateral (1) 1 — — 1 Total $ 1 $ 2 $ — $ 3 Liabilities: Commodity contracts subject to rate recovery $ — $ 2 $ — $ 2 Total $ — $ 2 $ — $ 2 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Commodity contracts not subject to rate recovery $ — $ — $ — $ — Effect of netting and allocation of collateral (1) 1 — — 1 Commodity contracts subject to rate recovery — 1 — 1 Effect of netting and allocation of collateral (1) 2 — — 2 Total $ 3 $ 1 $ — $ 4 Liabilities: Commodity contracts subject to rate recovery $ 2 $ 1 $ — $ 3 Effect of netting and allocation of collateral (1) (2 ) — — — (2 ) Total $ — $ 1 $ — $ 1 (1 ) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset. Level 3 Information The following table sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E: LEVEL 3 RECONCILIATIONS (1) (Dollars in millions) Years ended December 31, 2017 2016 2015 Balance at January 1 $ (74 ) $ 19 $ 107 Realized and unrealized gains (losses) 34 (120 ) (134 ) Allocated transmission instruments 6 8 12 Settlements 6 19 34 Balance at December 31 $ (28 ) $ (74 ) $ 19 Change in unrealized gains (losses) relating to instruments still held at December 31 $ 30 $ (101 ) $ (27 ) (1) Excludes the effect of contractual ability to settle contracts under master netting agreements. SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments. CRRs are recorded at fair value based almost entirely on the most current auction prices published by the CAISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, are in the following ranges: CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS Settlement year Price per MWh 2018 $ (7.25 ) to $ 11.99 2017 (11.88 ) to 6.93 2016 (23.81 ) to 10.23 The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 9. Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. These inputs range from $22.55 per MWh to $51.01 per MWh at December 31, 2017, and $17.40 per MWh to $56.67 per MWh at December 31, 2016. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 9. Realized gains and losses associated with CRRs and long-term electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities, and therefore also do not affect earnings. Fair Value of Financial Instruments The fair values of certain of our financial instruments (cash, accounts and notes receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets at December 31, 2017 and 2016 : FAIR VALUE OF FINANCIAL INSTRUMENTS (Dollars in millions) December 31, 2017 Carrying Fair value amount Level 1 Level 2 Level 3 Total Sempra Energy Consolidated: Long-term amounts due from unconsolidated affiliates (1) $ 604 $ — $ 528 $ 96 $ 624 Long-term amounts due to unconsolidated affiliates 35 — 32 — 32 Total long-term debt (2)(3) 17,138 817 17,134 458 18,409 SDG&E: Total long-term debt (3)(4) $ 4,868 $ — $ 5,073 $ 295 $ 5,368 SoCalGas: Total long-term debt (5) $ 3,009 $ — $ 3,192 $ — $ 3,192 December 31, 2016 Carrying Fair value amount Level 1 Level 2 Level 3 Total Sempra Energy Consolidated: Long-term amounts due from unconsolidated affiliates (1) $ 184 $ — $ 91 $ 84 $ 175 Total long-term debt (2)(3) 15,068 — 15,455 492 15,947 SDG&E: Total long-term debt (3)(4) $ 4,654 $ — $ 4,727 $ 305 $ 5,032 SoCalGas: Total long-term debt (5) $ 3,009 $ — $ 3,131 $ — $ 3,131 (1) Excluding accumulated interest outstanding of $29 million and $17 million at December 31, 2017 and 2016 , respectively, and excluding foreign currency translation of $35 million on a Mexican peso-denominated loan at December 31, 2017. (2) Before reductions for unamortized discount (net of premium) and debt issuance costs of $143 million and $109 million at December 31, 2017 and 2016 , respectively, and excluding build-to-suit and capital lease obligations of $877 million and $383 million at December 31, 2017 and 2016 , respectively. We discuss our long-term debt in Note 5. (3) Level 3 instruments include $295 million and $305 million at December 31, 2017 and 2016 , respectively, related to Otay Mesa VIE. (4) Before reductions for unamortized discount and debt issuance costs of $45 million at December 31, 2017 and 2016 , respectively, and excluding capital lease obligations of $732 million and $240 million at December 31, 2017 and 2016 , respectively. (5) Before reductions for unamortized discount and debt issuance costs of $24 million and $27 million at December 31, 2017 and 2016 , respectively, and excluding capital lease obligations of $1 million at December 31, 2017. We determine the fair value of certain long-term amounts due from/to unconsolidated affiliates and long-term debt based on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value certain other long-term amounts due from unconsolidated affiliates using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3). We provide the fair values for the securities held in the NDT funds related to SONGS in Note 13. NON-RECURRING FAIR VALUE MEASURES Sempra Mexico IEnova Pipelines . In September 2016, IEnova completed the acquisition of PEMEX’s 50 -percent interest in IEnova Pipelines, increasing its ownership interest to 100 percent . As a result of IEnova obtaining control over IEnova Pipelines, in the year ended December 31, 2016, Sempra Mexico recognized a pretax gain of $617 million ( $432 million after-tax) for the excess of the acquisition-date fair value of its previously held equity interest in IEnova Pipelines ( $1.144 billion ) over the carrying value of that interest ( $520 million ) and losses reclassified from AOCI ( $7 million ), included as Remeasurement of Equity Method Investment on Sempra Energy’s Consolidated Statement of Operations. The valuation technique used to measure the acquisition-date fair value of our equity interest in IEnova Pipelines immediately prior to the business acquisition was based on the fair value of the entire business combination ( $2.288 billion ) less the fair value of the consideration paid ( $1.144 billion , the equity sale price). We discuss the IEnova Pipelines acquisition in Note 3. TdM . In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM natural gas-fired power plant, and classified it as held for sale on the Sempra Energy Consolidated Balance Sheet, as we discuss in Note 3. In September 2016, we received market information that indicated that the fair value of TdM may be less than its carrying value. As a result, after performing an analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ( $111 million after-tax) in the third quarter of 2016. In 2017, Sempra Mexico received a purchase price offer resulting from negotiations with an active market participant. This new market information indicated that the fair value of TdM was lower than its carrying value at June 30, 2017. As a result, in the second quarter of 2017, Sempra Mexico further reduced the carrying value of TdM by recognizing a noncash impairment charge of $71 million . Impairments recorded for TdM are included in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. Market values resulting from a third-party bidding process and a purchase price offer are considered to be Level 2 inputs in the fair value hierarchy, as they represent observable pricing inputs. Sempra LNG & Midstream Rockies Express. As we discuss in Note 3, in March 2016, Sempra LNG & Midstream agreed to sell its 25 -percent interest in Rockies Express for cash consideration of $440 million , subject to adjustment at closing. In March 2016, we recorded a noncash impairment of our investment in Rockies Express of $44 million ( $27 million after-tax). The charge is included in Equity Earnings, Before Income Tax, on the Sempra Energy Consolidated Statement of Operations for the year ended December 31, 2016. We considered the sale price for our equity interest in Rockies Express to be a market participants’ view of the total value of Rockies Express and measured the fair value of our investment based on the equity sale price. The following table summarizes significant inputs impacting our non-recurring fair value measures: NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Estimated fair value Valuation technique Fair value hierarchy % of fair value measurement Inputs used to develop measurement Range of inputs Investment in IEnova Pipelines $ 1,144 (1) Market approach Level 2 100% Equity sale price 100% TdM $ 145 (2) Market approach Level 2 100% Purchase price offers 100% TdM $ 62 (3) Market approach Level 2 100% Purchase price offer 100% Investment in $ 440 (4) Market approach Level 2 100% Equity sale price 100% (1) At measurement date of September 26, 2016, immediately prior to acquiring a 100 -percent ownership interest in IEnova Pipelines. (2) At measurement date of September 29, 2016. (3) At measurement date of June 30, 2017. At December 31, 2017, TdM has a carrying value of $78 million , reflecting subsequent business activity, and is classified as held for sale. (4) At measurement date of March 29, 2016. On May 9, 2016, Sempra LNG & Midstream sold its equity interest in Rockies Express.

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Preferred Stock	PREFERRED STOCK Sempra Energy and SDG&E are authorized to issue up to 50 million and 45 million shares of preferred stock, respectively. At December 31, 2017 and 2016 , Sempra Energy and SDG&E have no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance. In January 2018, Sempra Energy issued 17,250,000 shares of mandatory convertible preferred stock and received proceeds of approximately $1.69 billion (net of underwriting discounts, but before related expenses), which we discuss in Note 18. SoCalGas is authorized to issue up to an aggregate of 11 million shares of preferred stock, series preferred stock and preference stock. At December 31, 2017 and 2016 , SoCalGas has the following preferred stock outstanding: PREFERRED STOCK OUTSTANDING (Dollars in millions, except per share amounts) December 31, 2017 2016 $25 par value, authorized 1,000,000 shares: 6% Series, 79,011 shares outstanding $ 3 $ 3 6% Series A, 783,032 shares outstanding 19 19 SoCalGas - Total preferred stock 22 22 Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises (2 ) (2 ) Sempra Energy - Total preferred stock of subsidiary $ 20 $ 20 None of SoCalGas’ outstanding preferred stock is callable, and no shares are subject to mandatory redemption. All outstanding shares have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid divide nds . In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize 5 million shares of series preferred stock and 5 million shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock and series preferred stock. Other rights and privileges of any new series of such stock would be established by the SoCalGas board of directors at the time of issuance.

SEMPRA ENERGY - SHAREHOLDERS' E

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE	SEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE The following table provides EPS computations for the years ended December 31, 2017 , 2016 and 2015 . Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 AND DIVIDENDS DECLARED (Dollars in millions, except per share amounts; shares in thousands) Years ended December 31, 2017 2016 2015 Numerator: Earnings/Income attributable to common shares $ 256 $ 1,370 $ 1,349 Denominator: Weighted-average common shares outstanding for basic EPS (1) 251,545 250,217 248,249 Dilutive effect of stock options, RSAs and RSUs (2) 755 938 2,674 Weighted-average common shares outstanding for diluted EPS 252,300 251,155 250,923 EPS: Basic $ 1.02 $ 5.48 $ 5.43 Diluted $ 1.01 $ 5.46 $ 5.37 Dividends declared per share of common stock (3) $ 3.29 $ 3.02 $ 2.80 (1) Includes average fully vested RSUs held in our Deferred Compensation Plan of 609 in 2017, 568 in 2016 and 491 in 2015. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued. (2) Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8, dilutive RSUs may vary widely from period-to-period. (3) Our board of directors has the discretion to determine the payment and amount of future dividends. The potentially dilutive impact from stock options, RSAs and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS excludes 237,741 , zero and 722 potentially dilutive shares for the years ended December 31, 2017 , 2016 and 2015 , respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future. We are authorized to issue 750 million shares of no par value common stock. The following table provides common stock activity for the years ended December 31, 2017 , 2016 and 2015 . COMMON STOCK ACTIVITY Years ended December 31, 2017 2016 2015 Common shares outstanding, January 1 250,152,514 248,298,080 246,330,884 RSUs vesting (1) 362,022 1,363,555 1,499,062 Stock options exercised 164,454 167,742 227,815 Savings plan issuance 567,428 653,607 652,631 Common stock investment plan (2) 254,047 266,056 249,665 Issuance of RSUs held in our Deferred Compensation Plan 7,811 — — Shares repurchased (3) (149,299 ) (596,526 ) (661,977 ) Common shares outstanding, December 31 251,358,977 250,152,514 248,298,080 (1) Includes dividend equivalents. (2) Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares. (3) From time to time, we purchase shares of our common stock or units from long-term incentive plan participants who elect to sell to us a sufficient number of vested RSAs or RSUs to meet minimum statutory tax withholding requirements. On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock in a registered public offering, pursuant to forward sale agreements. In connection with the overallotment option granted to the underwriters, on January 9, 2018, we issued 3,504,672 shares of our common stock and received net proceeds of $368 million (net of underwriting discounts, but before deducting other related expenses) for such shares, which we discuss in Note 18.

SAN ONOFRE NUCLEAR GENERATING S

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
San Onofre Nuclear Generating Station (SONGS)	SAN ONOFRE NUCLEAR GENERATING STATION SDG&E has a 20 -percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC . SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. SONGS STEAM GENERATOR REPLACEMENT PROJECT As part of the SGRP, the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS. The replacement steam generators were designed and provided by MHI. In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents. On March 13, 2017, the Tribunal overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is offset by these costs, resulting in a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million , resulting in a net damage award of $12 million , which was paid by MHI to SDG&E in March 2017. These amounts include certain adjustments to calculations supporting the Tribunal’s findings. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded the proceeds from the MHI arbitration by reducing Operation and Maintenance for previously incurred legal costs of $11 million , and shared the remaining $1 million equally between ratepayers and shareholders. SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE In November 2012, in response to the outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage. In November 2014, the CPUC issued a final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement) in the SONGS OII proceeding executed by SDG&E along with Edison, TURN, ORA and two other intervenors. The Amended Settlement Agreement does not affect ongoing or future proceedings before the NRC, or any litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries addressed in the final decision) or any proceedings addressing decommissioning activities and costs. The Amended Settlement Agreement provides for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, including base plant and construction work in progress, but excluding its investment in the SGRP, generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to: ▪ SDG&E’s weighted-average return on debt, plus ▪ 50 percent of SDG&E’s weighted-average return on preferred stock, as authorized in the CPUC’s cost of capital (discussed in Note 14) proceeding then in effect (collectively, SONGS return on rate base) In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest. In December 2016, the CPUC issued another procedural ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. Pursuant to the December ruling and a subsequent procedural ruling, the parties met to confer, engaged a mediator and held confidential mediation discussions in June, July and August of 2017. In August 2017, the parties filed status reports providing their recommendations for resolving the OII given their unsuccessful efforts at reaching a settlement through mediation. SDG&E and Edison recommended that the Amended Settlement Agreement, as adopted by the CPUC, should be affirmed and the pending intervenor petitions dismissed. Intervening parties recommended various alternative courses of action, including modifying the Amended Settlement Agreement or rejecting it in favor of litigation. In October 2017, the CPUC issued a ruling establishing a process to bring the proceeding to a conclusion. This ruling establishes a status conference and includes a preliminary schedule for additional testimony, hearings and briefings. On January 30, 2018, SDG&E, Edison, ORA, TURN and other intervenors entered into a settlement agreement (Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify the Amended Settlement Agreement approved by the CPUC in November 2014. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. On February 1, 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. On February 6, 2018, the CPUC granted the parties’ motion to stay the proceedings and established a tentative procedural schedule with public participation hearings in April and July, evidentiary hearings in April and May, and briefing in June of 2018. The Revised Settlement Agreement is subject to CPUC approval. The parties to the Revised Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. In the event that the CPUC fails to approve the Revised Settlement Agreement, the proceeding will remain open and subject to previous rulings in the SONGS OII, and the Amended Settlement Agreement will remain in effect, unless it is modified or set aside by the CPUC as a result of the OII proceeding. In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement. The timing of a ruling by the CPUC on the Joint Motion for Adoption of the Settlement Agreement is unclear. There is no assurance that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of the OII proceeding, which could result in a substantial reduction in our expected recovery or in payments to customers. These outcomes could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows. Disallowances, Refunds and Recoveries If the Revised Settlement Agreement is approved by the CPUC, SDG&E and Edison will cease rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of the date their combined remaining SONGS regulatory assets equal $775 million (the Cessation Date). Currently, the estimated Cessation Date is December 19, 2017. The Cessation Date is partly dependent on the outcome of Edison’s pending request to the CPUC, in a separate proceeding, for approval to apply certain proceeds received from the DOE to reduce Edison’s SONGS regulatory asset. If this request is rejected by the CPUC, then the estimated Cessation Date will be April 21, 2018. In either case, under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. SDG&E and Edison will refund to customers SONGS-related amounts recovered in rates after the Cessation Date. In the event that the CPUC takes an action that has the effect of invalidating the Utility Shareholder Agreement, SDG&E may, in its discretion, withdraw from the Revised Settlement Agreement, in which case Edison shall remain a party to the Revised Settlement Agreement, but the Revised Settlement Agreement shall be terminated as to SDG&E. In such a scenario, SDG&E would return to its litigation position before the CPUC in the SONGS OII that existed prior to the Revised Settlement Agreement. Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject, negotiating in good faith to seek a resolution acceptable to all parties. CPUC rules do not provide for any fixed time period for the CPUC to act on proposed settlements. Utility Shareholder Agreement On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that SDG&E will release Edison from any and all claims that SDG&E had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement becomes effective only upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commences 30 days after the first fiscal quarter in which the CPUC approves the Revised Settlement Agreement, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement. Accounting and Financial Impacts As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison totaling $152 million , $32 million classified as current and $120 million classified as noncurrent, as of December 31, 2017. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset, which SDG&E believes is now no longer probable of recovery. Assuming the Revised Settlement Agreement is approved, SDG&E and Sempra Energy do not expect that implementation of the Revised Settlement Agreement in combination with the Utility Shareholder Agreement will have a material adverse impact on either company. However, until the CPUC approves the Revised Settlement Agreement as proposed, there can be no assurance that the SONGS OII proceeding will conclude as contemplated by SDG&E in accordance with the Revised Settlement Agreement and the Utility Shareholder Agreement, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement, or take other action that may be adverse to SDG&E and Sempra Energy. Such alternative outcomes could have a material adverse effect on SDG&E’s and Sempra Energy’s results of operations, financial condition and cash flows. SETTLEMENT WITH NEIL As we discuss below, NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million , SDG&E’s share of which was $80 million . Pursuant to the terms of the Amended Settlement Agreement, after reimbursement of legal fees and a 5 -percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through the ERRA. NUCLEAR DECOMMISSIONING AND FUNDING As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. In December 2016, Edison announced that, following a 10-month competitive bid process, it had contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years . SDG&E is responsible for approximately 20 percent of the total contract price. In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities. In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.4 billion (in 2014 dollars), of which SDG&E’s share is $899 million . Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. SDG&E has received authorization from the CPUC to access NDT funds of up to $362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 SONGS Units 2 and 3 costs as decommissioning costs are incurred. In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized. Nuclear Decommissioning Trusts The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities. The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10. NUCLEAR DECOMMISSIONING TRUSTS (Dollars in millions) Cost Gross unrealized gains Gross unrealized losses Estimated fair value At December 31, 2017: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies (1) $ 54 $ — $ — $ 54 Municipal bonds (1) 245 7 (2 ) 250 Other securities (2) 215 3 (1 ) 217 Total debt securities 514 10 (3 ) 521 Equity securities 171 326 (1 ) 496 Cash and cash equivalents 16 — — 16 Total $ 701 $ 336 $ (4 ) $ 1,033 At December 31, 2016: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies $ 52 $ — $ — $ 52 Municipal bonds 203 4 (1 ) 206 Other securities 141 2 (2 ) 141 Total debt securities 396 6 (3 ) 399 Equity securities 143 366 (1 ) 508 Cash and cash equivalents 119 — — 119 Total $ 658 $ 372 $ (4 ) $ 1,026 (1) Maturity dates are 2018-2048. (2) Maturity dates are 2018-2064. The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales. SALES OF SECURITIES (Dollars in millions) Years ended December 31, 2017 2016 2015 Proceeds from sales (1) $ 1,314 $ 1,134 $ 577 Gross realized gains 157 111 29 Gross realized losses (14 ) (29 ) (15 ) (1) Excludes securities that are held to maturity. Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification. In 2017 and 2016 , sale and purchase activities in our NDT increased significantly compared to 2015 as a result of continuing changes to our asset allocations initiated in the fourth quarter of 2016 to reduce our equity volatility, lower our duration risk, and increase exposure to municipal bonds and intermediate credit. This shift in our asset mix is intended to reduce the overall risk profile of the NDT in anticipation of significant cash withdrawals over the next 10 years to fund the SONGS decommissioning. ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $607 million at December 31, 2017 . That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The asset retirement obligation at December 31, 2017 for Unit 1 is based on a cost study prepared in 2016 that is pending CPUC approval. The asset retirement obligation at December 31, 2017 for Units 2 and 3 is based on a CPUC-approved cost study prepared in 2014 that reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. SDG&E’s share of total decommissioning costs in 2017 dollars is approximately $1 billion . U.S. Department of Energy Nuclear Fuel Disposal Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel by 2019 and to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS. The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from 2006 through 2013. In May 2016, Edison refunded SDG&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS O&M cost balancing account. In September 2016, Edison filed claims with the DOE for $56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers. In October 2017, Edison filed claims with the DOE for $58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $12 million . It is unclear whether the claim will be resolved through settlement or arbitration, when resolution is expected, and whether Edison will receive an award for the full claim amount. The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017. NUCLEAR INSURANCE Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement, as described below. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, which has not yet been obtained. We expect a decision in the first quarter of 2018. SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13 billion of SFP. If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG&E’s contribution would be up to $50.9 million . This amount is subject to an annual maximum of $7.6 million , unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $450 million to $100 million and withdraw from participation in the SFP for SONGS. The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $1.06 billion . This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL, as we discuss above. Effective January 10, 2018, the NRC approved Edison’s request to reduce its property damage insurance requirement for SONGS from $1.06 billion to $50 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. REGULATORY MATTERS REGULATORY ASSETS AND LIABILITIES We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below. REGULATORY ASSETS (LIABILITIES) (Dollars in millions) December 31, 2017 2016 SDG&E: Fixed-price contracts and other derivatives $ 96 $ 141 Costs related to SONGS plant closure (1) — 183 Costs related to wildfire litigation — 353 Deferred income taxes (refundable) recoverable in rates (281 ) 1,014 Pension and other postretirement benefit plan obligations 153 210 Removal obligations (1,846 ) (1,725 ) Unamortized loss on reacquired debt 9 12 Environmental costs 29 48 Legacy meters (1) — 16 Sunrise Powerlink fire mitigation 119 118 Regulatory balancing accounts (2) Commodity – electric 82 35 Gas transportation 22 61 Safety and reliability 48 20 Public purpose programs (70 ) (106 ) Other balancing accounts 233 249 Other regulatory liabilities (70 ) (2 ) Total SDG&E (1,476 ) 627 SoCalGas: Pension and other postretirement benefit plan obligations 513 563 Employee benefit costs 45 45 Removal obligations (924 ) (972 ) Deferred income taxes (refundable) recoverable in rates (437 ) 417 Unamortized loss on reacquired debt 8 10 Environmental costs 22 22 Workers’ compensation 12 10 Regulatory balancing accounts (2) Commodity – gas, including transportation 151 207 Safety and reliability 266 230 Public purpose programs (274 ) (270 ) Other balancing accounts (114 ) (204 ) Other regulatory (liabilities) assets (64 ) 8 Total SoCalGas (796 ) 66 Sempra Mexico: Deferred income taxes recoverable in rates 83 71 Total Sempra Energy Consolidated $ (2,189 ) $ 764 (1) Regulatory assets earning a rate of return. (2) At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million . At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million , respectively. In the table above: ▪ Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. We discuss these fixed-price contracts and other derivatives further in Note 9. ▪ Regulatory assets arising from the SONGS plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline. Pursuant to the Revised Settlement Agreement, rate recovery of SONGS costs remaining as a regulatory asset as of the Cessation Date will cease. Under the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison in lieu of amounts SDG&E would have collected from ratepayers. We discuss these matters further in Note 13. ▪ Regulatory assets for CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties. In December 2017, the CPUC issued a final decision, denying SDG&E’s request to recover these costs. In 2017, SDG&E wrote off the wildfire regulatory asset resulting in a charge of $351 million , as we discuss in Note 15 in “SDG&E – 2007 Wildfire Litigation and Net Cost Recovery Status.” ▪ Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below. In 2017, as a result of the TCJA, lowering the U.S. statutory corporate federal income tax from 35 percent to 21 percent resulted in excess deferred income tax balances that we expect to refund to ratepayers in accordance with the IRS normalization rules and as determined by the CPUC and the FERC. We discuss the TCJA and the impacts on Sempra Energy, SDG&E and SoCalGas in more detail in Note 6. ▪ Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded. ▪ The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made. ▪ Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs. ▪ Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 10 years for SDG&E and from 3 years to 8 years for SoCalGas. ▪ Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 15. ▪ The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E has fully recovered this asset in rate base. ▪ The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a tru

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Regulatory Matters	SAN ONOFRE NUCLEAR GENERATING STATION SDG&E has a 20 -percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC . SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. SONGS STEAM GENERATOR REPLACEMENT PROJECT As part of the SGRP, the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS. The replacement steam generators were designed and provided by MHI. In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents. On March 13, 2017, the Tribunal overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is offset by these costs, resulting in a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million , resulting in a net damage award of $12 million , which was paid by MHI to SDG&E in March 2017. These amounts include certain adjustments to calculations supporting the Tribunal’s findings. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded the proceeds from the MHI arbitration by reducing Operation and Maintenance for previously incurred legal costs of $11 million , and shared the remaining $1 million equally between ratepayers and shareholders. SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE In November 2012, in response to the outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage. In November 2014, the CPUC issued a final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement) in the SONGS OII proceeding executed by SDG&E along with Edison, TURN, ORA and two other intervenors. The Amended Settlement Agreement does not affect ongoing or future proceedings before the NRC, or any litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries addressed in the final decision) or any proceedings addressing decommissioning activities and costs. The Amended Settlement Agreement provides for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, including base plant and construction work in progress, but excluding its investment in the SGRP, generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to: ▪ SDG&E’s weighted-average return on debt, plus ▪ 50 percent of SDG&E’s weighted-average return on preferred stock, as authorized in the CPUC’s cost of capital (discussed in Note 14) proceeding then in effect (collectively, SONGS return on rate base) In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest. In December 2016, the CPUC issued another procedural ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. Pursuant to the December ruling and a subsequent procedural ruling, the parties met to confer, engaged a mediator and held confidential mediation discussions in June, July and August of 2017. In August 2017, the parties filed status reports providing their recommendations for resolving the OII given their unsuccessful efforts at reaching a settlement through mediation. SDG&E and Edison recommended that the Amended Settlement Agreement, as adopted by the CPUC, should be affirmed and the pending intervenor petitions dismissed. Intervening parties recommended various alternative courses of action, including modifying the Amended Settlement Agreement or rejecting it in favor of litigation. In October 2017, the CPUC issued a ruling establishing a process to bring the proceeding to a conclusion. This ruling establishes a status conference and includes a preliminary schedule for additional testimony, hearings and briefings. On January 30, 2018, SDG&E, Edison, ORA, TURN and other intervenors entered into a settlement agreement (Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify the Amended Settlement Agreement approved by the CPUC in November 2014. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. On February 1, 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. On February 6, 2018, the CPUC granted the parties’ motion to stay the proceedings and established a tentative procedural schedule with public participation hearings in April and July, evidentiary hearings in April and May, and briefing in June of 2018. The Revised Settlement Agreement is subject to CPUC approval. The parties to the Revised Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. In the event that the CPUC fails to approve the Revised Settlement Agreement, the proceeding will remain open and subject to previous rulings in the SONGS OII, and the Amended Settlement Agreement will remain in effect, unless it is modified or set aside by the CPUC as a result of the OII proceeding. In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement. The timing of a ruling by the CPUC on the Joint Motion for Adoption of the Settlement Agreement is unclear. There is no assurance that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of the OII proceeding, which could result in a substantial reduction in our expected recovery or in payments to customers. These outcomes could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows. Disallowances, Refunds and Recoveries If the Revised Settlement Agreement is approved by the CPUC, SDG&E and Edison will cease rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of the date their combined remaining SONGS regulatory assets equal $775 million (the Cessation Date). Currently, the estimated Cessation Date is December 19, 2017. The Cessation Date is partly dependent on the outcome of Edison’s pending request to the CPUC, in a separate proceeding, for approval to apply certain proceeds received from the DOE to reduce Edison’s SONGS regulatory asset. If this request is rejected by the CPUC, then the estimated Cessation Date will be April 21, 2018. In either case, under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. SDG&E and Edison will refund to customers SONGS-related amounts recovered in rates after the Cessation Date. In the event that the CPUC takes an action that has the effect of invalidating the Utility Shareholder Agreement, SDG&E may, in its discretion, withdraw from the Revised Settlement Agreement, in which case Edison shall remain a party to the Revised Settlement Agreement, but the Revised Settlement Agreement shall be terminated as to SDG&E. In such a scenario, SDG&E would return to its litigation position before the CPUC in the SONGS OII that existed prior to the Revised Settlement Agreement. Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject, negotiating in good faith to seek a resolution acceptable to all parties. CPUC rules do not provide for any fixed time period for the CPUC to act on proposed settlements. Utility Shareholder Agreement On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that SDG&E will release Edison from any and all claims that SDG&E had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement becomes effective only upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commences 30 days after the first fiscal quarter in which the CPUC approves the Revised Settlement Agreement, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement. Accounting and Financial Impacts As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison totaling $152 million , $32 million classified as current and $120 million classified as noncurrent, as of December 31, 2017. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset, which SDG&E believes is now no longer probable of recovery. Assuming the Revised Settlement Agreement is approved, SDG&E and Sempra Energy do not expect that implementation of the Revised Settlement Agreement in combination with the Utility Shareholder Agreement will have a material adverse impact on either company. However, until the CPUC approves the Revised Settlement Agreement as proposed, there can be no assurance that the SONGS OII proceeding will conclude as contemplated by SDG&E in accordance with the Revised Settlement Agreement and the Utility Shareholder Agreement, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement, or take other action that may be adverse to SDG&E and Sempra Energy. Such alternative outcomes could have a material adverse effect on SDG&E’s and Sempra Energy’s results of operations, financial condition and cash flows. SETTLEMENT WITH NEIL As we discuss below, NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million , SDG&E’s share of which was $80 million . Pursuant to the terms of the Amended Settlement Agreement, after reimbursement of legal fees and a 5 -percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through the ERRA. NUCLEAR DECOMMISSIONING AND FUNDING As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. In December 2016, Edison announced that, following a 10-month competitive bid process, it had contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years . SDG&E is responsible for approximately 20 percent of the total contract price. In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities. In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.4 billion (in 2014 dollars), of which SDG&E’s share is $899 million . Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. SDG&E has received authorization from the CPUC to access NDT funds of up to $362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 SONGS Units 2 and 3 costs as decommissioning costs are incurred. In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized. Nuclear Decommissioning Trusts The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities. The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10. NUCLEAR DECOMMISSIONING TRUSTS (Dollars in millions) Cost Gross unrealized gains Gross unrealized losses Estimated fair value At December 31, 2017: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies (1) $ 54 $ — $ — $ 54 Municipal bonds (1) 245 7 (2 ) 250 Other securities (2) 215 3 (1 ) 217 Total debt securities 514 10 (3 ) 521 Equity securities 171 326 (1 ) 496 Cash and cash equivalents 16 — — 16 Total $ 701 $ 336 $ (4 ) $ 1,033 At December 31, 2016: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies $ 52 $ — $ — $ 52 Municipal bonds 203 4 (1 ) 206 Other securities 141 2 (2 ) 141 Total debt securities 396 6 (3 ) 399 Equity securities 143 366 (1 ) 508 Cash and cash equivalents 119 — — 119 Total $ 658 $ 372 $ (4 ) $ 1,026 (1) Maturity dates are 2018-2048. (2) Maturity dates are 2018-2064. The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales. SALES OF SECURITIES (Dollars in millions) Years ended December 31, 2017 2016 2015 Proceeds from sales (1) $ 1,314 $ 1,134 $ 577 Gross realized gains 157 111 29 Gross realized losses (14 ) (29 ) (15 ) (1) Excludes securities that are held to maturity. Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification. In 2017 and 2016 , sale and purchase activities in our NDT increased significantly compared to 2015 as a result of continuing changes to our asset allocations initiated in the fourth quarter of 2016 to reduce our equity volatility, lower our duration risk, and increase exposure to municipal bonds and intermediate credit. This shift in our asset mix is intended to reduce the overall risk profile of the NDT in anticipation of significant cash withdrawals over the next 10 years to fund the SONGS decommissioning. ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $607 million at December 31, 2017 . That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The asset retirement obligation at December 31, 2017 for Unit 1 is based on a cost study prepared in 2016 that is pending CPUC approval. The asset retirement obligation at December 31, 2017 for Units 2 and 3 is based on a CPUC-approved cost study prepared in 2014 that reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. SDG&E’s share of total decommissioning costs in 2017 dollars is approximately $1 billion . U.S. Department of Energy Nuclear Fuel Disposal Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel by 2019 and to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS. The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from 2006 through 2013. In May 2016, Edison refunded SDG&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS O&M cost balancing account. In September 2016, Edison filed claims with the DOE for $56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers. In October 2017, Edison filed claims with the DOE for $58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $12 million . It is unclear whether the claim will be resolved through settlement or arbitration, when resolution is expected, and whether Edison will receive an award for the full claim amount. The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017. NUCLEAR INSURANCE Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement, as described below. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, which has not yet been obtained. We expect a decision in the first quarter of 2018. SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13 billion of SFP. If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG&E’s contribution would be up to $50.9 million . This amount is subject to an annual maximum of $7.6 million , unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $450 million to $100 million and withdraw from participation in the SFP for SONGS. The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $1.06 billion . This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL, as we discuss above. Effective January 10, 2018, the NRC approved Edison’s request to reduce its property damage insurance requirement for SONGS from $1.06 billion to $50 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. REGULATORY MATTERS REGULATORY ASSETS AND LIABILITIES We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below. REGULATORY ASSETS (LIABILITIES) (Dollars in millions) December 31, 2017 2016 SDG&E: Fixed-price contracts and other derivatives $ 96 $ 141 Costs related to SONGS plant closure (1) — 183 Costs related to wildfire litigation — 353 Deferred income taxes (refundable) recoverable in rates (281 ) 1,014 Pension and other postretirement benefit plan obligations 153 210 Removal obligations (1,846 ) (1,725 ) Unamortized loss on reacquired debt 9 12 Environmental costs 29 48 Legacy meters (1) — 16 Sunrise Powerlink fire mitigation 119 118 Regulatory balancing accounts (2) Commodity – electric 82 35 Gas transportation 22 61 Safety and reliability 48 20 Public purpose programs (70 ) (106 ) Other balancing accounts 233 249 Other regulatory liabilities (70 ) (2 ) Total SDG&E (1,476 ) 627 SoCalGas: Pension and other postretirement benefit plan obligations 513 563 Employee benefit costs 45 45 Removal obligations (924 ) (972 ) Deferred income taxes (refundable) recoverable in rates (437 ) 417 Unamortized loss on reacquired debt 8 10 Environmental costs 22 22 Workers’ compensation 12 10 Regulatory balancing accounts (2) Commodity – gas, including transportation 151 207 Safety and reliability 266 230 Public purpose programs (274 ) (270 ) Other balancing accounts (114 ) (204 ) Other regulatory (liabilities) assets (64 ) 8 Total SoCalGas (796 ) 66 Sempra Mexico: Deferred income taxes recoverable in rates 83 71 Total Sempra Energy Consolidated $ (2,189 ) $ 764 (1) Regulatory assets earning a rate of return. (2) At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million . At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million , respectively. In the table above: ▪ Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. We discuss these fixed-price contracts and other derivatives further in Note 9. ▪ Regulatory assets arising from the SONGS plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline. Pursuant to the Revised Settlement Agreement, rate recovery of SONGS costs remaining as a regulatory asset as of the Cessation Date will cease. Under the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison in lieu of amounts SDG&E would have collected from ratepayers. We discuss these matters further in Note 13. ▪ Regulatory assets for CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties. In December 2017, the CPUC issued a final decision, denying SDG&E’s request to recover these costs. In 2017, SDG&E wrote off the wildfire regulatory asset resulting in a charge of $351 million , as we discuss in Note 15 in “SDG&E – 2007 Wildfire Litigation and Net Cost Recovery Status.” ▪ Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below. In 2017, as a result of the TCJA, lowering the U.S. statutory corporate federal income tax from 35 percent to 21 percent resulted in excess deferred income tax balances that we expect to refund to ratepayers in accordance with the IRS normalization rules and as determined by the CPUC and the FERC. We discuss the TCJA and the impacts on Sempra Energy, SDG&E and SoCalGas in more detail in Note 6. ▪ Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded. ▪ The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made. ▪ Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs. ▪ Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 10 years for SDG&E and from 3 years to 8 years for SoCalGas. ▪ Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 15. ▪ The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E has fully recovered this asset in rate base. ▪ The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a tru

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 15. COMMITMENTS AND CONTINGENCIES LEGAL PROCEEDINGS We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued. At December 31, 2017 , loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $92 million for Sempra Energy Consolidated, including $3 million for SDG&E and $88 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $83 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below. We discuss our policy regarding accrual of legal fees in Note 1. SDG&E 2007 Wildfire Litigation and Net Cost Recovery Status SDG&E has resolved all litigation associated with three wildfires that occurred in October 2007, except one appeal that remains pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E maintains reserves for the wildfire litigation and adjusts these reserves as information becomes available and amounts are estimable. SDG&E recorded regulatory assets for CPUC-related costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. In September 2015, SDG&E filed an application with the CPUC seeking authority to recover these CPUC-related costs in rates over a six- to ten-year period. The requested amount was the net estimated CPUC-related cost incurred by SDG&E after deductions for insurance reimbursement and third-party settlement recoveries, and reflected a voluntary 10-percent shareholder contribution applied to the net regulatory asset for wildfire costs. In August 2017, the CPUC issued a proposed decision denying SDG&E’s request to recover the 2007 wildfire costs submitted in our application. In consideration of the proposed decision (including the actions not taken through the October 26, 2017 CPUC meeting), we concluded that the wildfire regulatory asset no longer met the probability threshold for recovery required by U.S. GAAP. Accordingly, SDG&E wrote off the wildfire regulatory asset, resulting in a charge of $351 million ( $208 million after-tax) in the third quarter of 2017, in Write-off of Wildfire Regulatory Asset on the Consolidated Statements of Operations for Sempra Energy and SDG&E. In December 2017, the CPUC issued a final decision upholding the proposed decision. SDG&E will continue to vigorously pursue recovery of these costs, which were incurred through settling claims brought under the doctrine of inverse condemnation. SDG&E applied to the CPUC for rehearing of its decision on January 2, 2018. The CPUC may grant a rehearing, modify its decision, or deny the request and affirm its original decision. We will appeal the decision with the California Courts of Appeal seeking to reverse the CPUC’s decision, if necessary. Concluded Matter SDG&E participated as a claimant and respondent in an arbitration proceeding initiated by Edison in October 2013 against MHI seeking damages stemming from the failure of the MHI replacement steam generators at the SONGS nuclear power plant. In March 2017, the Tribunal found MHI liable for breach of contract, subject to a contractual limitation of liability, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. We discuss this arbitration and decision further in Note 13. SoCalGas Aliso Canyon Natural Gas Storage Facility Gas Leak On October 23, 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak), located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is one of more than 100 injection-and-withdrawal wells at the storage facility. SoCalGas worked closely with several of the world’s leading experts to stop the Leak, and on February 18, 2016, DOGGR confirmed that the well was permanently sealed. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon natural gas storage facility as a result of the Leak. Local Community Mitigation Efforts. Pursuant to a stipulation and order by the LA Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. Following the permanent sealing of the well, the DPH conducted testing in certain homes in the Porter Ranch community, and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home. In May 2016, the LA Superior Court ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016. In May 2016, the DPH also issued a directive that SoCalGas additionally professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five-mile radius of the Aliso Canyon natural gas storage facility and experienced symptoms from the Leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive. The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. To the extent any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Cost Estimates and Accounting Impact. At December 31, 2017 , SoCalGas estimates that its costs related to the Leak are $913 million , which includes $887 million of costs recovered or probable of recovery from insurance. Of the $913 million of costs, approximately 60 percent is for the temporary relocation program (including cleaning costs and certain labor costs). Other estimated costs include amounts for efforts to control the well, stop the Leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to investigate the cause of the Leak. The remaining portion of the $913 million includes legal costs incurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, the estimated costs to settle certain actions and other costs. The value of lost gas reflects the replacement cost of volumes purchased through December 2017 and estimates for purchases in 2018. As of mid-January 2018, SoCalGas has replaced all lost gas. SoCalGas adjusts its estimated total liability associated with the Leak as additional information becomes available. The $913 million represents management’s best estimate of these costs related to the Leak. Of these costs, a substantial portion has been paid and $84 million is accrued as Reserve for Aliso Canyon Costs as of December 31, 2017 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets for amounts expected to be paid after December 31, 2017 . As of December 31, 2017 , we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the Leak of $418 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. This amount is net of insurance retentions and $469 million of insurance proceeds we received through December 31, 2017 related to control-of-well expenses, lost gas and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. As described in “Governmental Investigations and Civil and Criminal Litigation” below, the actions against us seek compensatory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the above amounts as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs that may be imposed. The recorded amounts above also do not include the costs to clean additional homes pursuant to the Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate of $913 million does not include certain other costs expensed by Sempra Energy through December 31, 2017 associated with defending shareholder derivative lawsuits. In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account may be refunded to ratepayers. Insurance. Excluding directors’ and officers’ liability insurance, we have four kinds of insurance policies that together provide between $1.2 billion to $1.4 billion in insurance coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the Leak. Subject to various policy limits, exclusions and conditions, based on what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the Leak and stop or reduce emissions, the root cause analysis being conducted to investigate the cause of the Leak, the value of lost natural gas, costs incurred to mitigate the actual natural gas released, costs associated with litigation and claims by nearby residents and businesses, any costs to clean additional homes pursuant to the Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we have received insurance payments for portions of control-of-well expenses, lost gas and temporary relocation costs. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining additional insurance recovery for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. At December 31, 2017 , SoCalGas’ estimated costs related to the Leak of $913 million include $887 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Any costs not included in the $913 million cost estimate could be material. To the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including DOGGR, DPH, SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, CPUC, PHMSA, EPA, Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. Other federal agencies (e.g., the DOE and the U.S. Department of the Interior) investigated the incident as part of a joint interagency task force. In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The timing of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC. As of February 22, 2018, 373 lawsuits, including over 45,000 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. All of these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action discussed below, are coordinated before a single court in the LA Superior Court for pretrial management (the Coordination Proceeding). Pursuant to the Coordination Proceeding, in March 2017, the individuals and business entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees. In January 2017, pursuant to the Coordination Proceeding, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, one on behalf of a putative class of persons and businesses who own or lease real property within a five -mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In December 2017, the California Court of Appeal, Second Appellate District ruled that the purely economic damages alleged in the Business Class Action are not recoverable under the law. In addition to the lawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and certain of its directors in the SDCA. Five shareholder derivative actions are also pending in the Coordination Proceeding alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017. Three actions filed by public entities are pending in the Coordination Proceeding. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the LA Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and damages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the DPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the Leak, as well as punitive damages and attorneys’ fees. Second, in August 2016, the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney, filed a third amended complaint on behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Unfair Competition Law, violations of California Health and Safety Code sections 41700 (prohibiting discharge of air contaminants that cause annoyance to the public) and 25510 (requiring reporting of the release of hazardous material), as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. Third, a petition for writ of mandate filed by the County of Los Angeles is pending against DOGGR and its State Oil and Gas Supervisor and the CPUC and its Executive Director, as to which SoCalGas is the real party in interest. The petition alleges that in issuing its July 2017 determination that the requirements for the resumption of injection operations were met (discussed under “Natural Gas Storage Operations and Reliability” below), DOGGR failed to comply with the provisions of SB 380, which requires a comprehensive safety review of the Aliso Canyon natural gas storage facility before injection of natural gas may resume. The County alleges, among other things, that DOGGR failed to comply with the provisions of SB 380 in declaring the safety review complete and authorizing the resumption of injection of natural gas into the facility before the root cause analysis was complete, failing to make its safety-review documents available to the public and failing to address seismic risks to the field as part of its safety review. The County further alleges that CEQA required DOGGR to prepare an EIR before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, and to produce records in response to the County’s Public Records Act request as well as declaratory and injunctive relief against any authorization to inject natural gas and attorneys’ fees. A complaint filed by the SCAQMD against SoCalGas seeking civil penalties for alleged violations of several nuisance related statutory provisions arising from the Leak and delays in stopping the Leak was settled in February 2017, pursuant to which SoCalGas paid $8.5 million , of which $1 million is to be used to pay for a health study. The SCAQMD’s complaint was dismissed in February 2017. Separately, in February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the Leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. Pursuant to a settlement agreement with the Los Angeles County District Attorney’s Office, SoCalGas agreed to plead no contest to the notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $75,000 , penalty assessments of approximately $233,500 , and operational commitments estimated to cost approximately $5 million , reimbursement and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Certain individuals residing near the Aliso Canyon natural gas storage facility who objected to the settlement have filed a notice of appeal of the judgment, contending they should be granted restitution. The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Regulatory Proceedings. In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region. The CPUC indicated it intends to conduct the proceeding in two phases, with Phase 1 undertaking a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 using those analyses and scenarios to evaluate the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility. The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The CPUC adopted a high-level Phase 1 schedule contemplating public participation hearings and workshops beginning in April 2017, but no hearings until Phase 2. Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas does not believe the Aliso Canyon natural gas storage facility or any portion of the facility was out of service (as that term is meant in Section 455.5) for nine consecutive months, SoCalGas provided notification out of an abundance of caution to demonstrate its commitment to regulatory compliance and transparency, and because obtaining authorization to resume injection operations at the facility required more time than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of the facility was out of service for nine consecutive months under section 455.5, and if so, whether the CPUC should disallow costs for such period from SoCalGas’ rates. Under section 455.5, hearings on the investigation are to be held, if necessary, in conjunction with SoCalGas’ 2019 GRC proceeding. If the CPUC determines that all or any portion of the facility was out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Governmental Orders and Additional Regulation. In January 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency in Los Angeles County due to the Leak. The Governor’s Order imposes various orders with respect to: stopping the Leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (2) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response while protecting ratepayers, and CARB must develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (3) DOGGR, CPUC, CARB and the CEC must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California. In December 2015, SoCalGas made a commitment to mitigate the actual natural gas released from the Leak and has been working on a plan to accomplish the mitigation. In March 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program , which set forth its recommended approach to achieve full mitigation of the emissions from the Leak. The CARB program requires that reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to the amount of the emissions from the Leak, and that the amount of reductions required be derived using the global warming potential based on a 20 -year term (rather than the 100 -year term the CARB and other state and federal agencies use in regulating emissions), resulting in a target of approximately 9,000,000 metric tons of carbon dioxide equivalent. CARB’s program also calls for all of the mitigation to occur in California over the next five to ten years without the use of allowances or offsets. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the greenhouse gas impacts of the Leak. We have not agreed with CARB’s estimate of methane released and continue to work with CARB on developing a mitigation plan. Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 25, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and in accordance with SB 380, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility. In April and June of 2017, SoCalGas advised the CAISO, CEC, CPUC and PHMSA of its concerns that the inability to inject natural gas into the Aliso Canyon natural gas storage facility posed a risk to energy reliability in Southern California. Limited withdrawals of natural gas from the Aliso Canyon natural gas storage facility were made in 2017 to augment natural gas supplies during critical demand periods. On July 19, 2017, DOGGR issued its determination that SoCalGas had met the requirements of SB 380 for the resumption of injection operations, including all safety requirements. On the same date, the CPUC’s Executive Director issued his concurrence with that determination, and DOGGR issued its Order to: Test and Take Temporary Actions Upon Resuming Injection: Aliso Canyon Gas Storage Facility lifting the prohibition on injection at the Aliso Canyon natural gas storage facility, subject to certain requirements after injection resumed, including limitations on the rate at which SoCalGas may withdraw natural gas from the field. The CPUC additionally issued a directive to SoCalGas to maintain a range of working gas in the Aliso Canyon natural gas storage facility at a target of 23.6 Bcf (approximately 28 percent of its maximum capacity), and at all times above 14.8 Bcf, later amended to require the range be maintained from zero Bcf to 24.6 Bcf of working gas. The County of Los Angeles filed a petition for writ of mandate seeking declaratory and injunctive relief and a stay of DOGGR’s order lifting the prohibition against injecting natural gas at the facility. We provide further detail regarding the County of Los Angeles’ suit above in “Governmental Investigations and Civil and Criminal Litigation.” Having completed the steps outlined by state agencies to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections. If the Aliso Canyon natural gas storage facility were determined to have been out of service for any meaningful period of time or permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2017 , the Aliso Canyon natural gas storage facility has a net book value of $644 million , including $252 million of construction work in progress for the project to construct a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Sempra Mexico Property Disputes and Permit Challenges Energía Costa Azul. Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its ECA LNG terminal near Ensenada, Mexico. A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of the SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. Both challenges are pending to be resolved by a Federal Court in Mexico. Sempra Mexico expects additional proceedings regarding the claims. Several administrative challenges are pending in Mexico before the Mexican environmental protecti

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	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 Diego County. ▪ SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California. ▪ Sempra South American Utilities develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru. ▪ Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3. ▪ Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S. ▪ Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In September 2016, Sempra LNG & Midstream sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express. Sempra LNG & Midstream also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015. We discuss these divestitures in Note 3. We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1. Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation. The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 4. Amounts labeled as “All other” in the following tables consist primarily of parent organizations. SEGMENT INFORMATION (Dollars in millions) Years ended December 31, 2017 2016 2015 REVENUES SDG&E $ 4,476 $ 4,253 $ 4,219 SoCalGas 3,785 3,471 3,489 Sempra South American Utilities 1,567 1,556 1,544 Sempra Mexico 1,196 725 669 Sempra Renewables 94 34 36 Sempra LNG & Midstream 540 508 653 Adjustments and eliminations (1 ) — (2 ) Intersegment revenues (1) (450 ) (364 ) (377 ) Total $ 11,207 $ 10,183 $ 10,231 INTEREST EXPENSE SDG&E $ 203 $ 195 $ 204 SoCalGas 102 97 84 Sempra South American Utilities 38 38 32 Sempra Mexico 97 13 23 Sempra Renewables 15 4 3 Sempra LNG & Midstream 39 43 72 All other 284 282 263 Intercompany eliminations (119 ) (119 ) (120 ) Total $ 659 $ 553 $ 561 INTEREST INCOME SoCalGas $ 1 $ 1 $ 4 Sempra South American Utilities 28 21 19 Sempra Mexico 23 6 7 Sempra Renewables 7 5 4 Sempra LNG & Midstream 56 71 75 Intercompany eliminations (69 ) (78 ) (80 ) Total $ 46 $ 26 $ 29 DEPRECIATION AND AMORTIZATION SDG&E $ 670 $ 646 $ 604 SoCalGas 515 476 461 Sempra South American Utilities 54 49 50 Sempra Mexico 156 77 70 Sempra Renewables 38 6 6 Sempra LNG & Midstream 42 47 49 All other 15 11 10 Total $ 1,490 $ 1,312 $ 1,250 INCOME TAX EXPENSE (BENEFIT) SDG&E $ 155 $ 280 $ 284 SoCalGas 160 143 138 Sempra South American Utilities 80 80 67 Sempra Mexico 227 188 11 Sempra Renewables (226 ) (38 ) (49 ) Sempra LNG & Midstream (119 ) (80 ) 28 All other 999 (184 ) (138 ) Total $ 1,276 $ 389 $ 341 SEGMENT INFORMATION (CONTINUED) (Dollars in millions) Years ended December 31 or at December 31, 2017 2016 2015 EARNINGS (LOSSES) SDG&E $ 407 $ 570 $ 587 SoCalGas (2) 396 349 419 Sempra South American Utilities 186 156 175 Sempra Mexico 169 463 213 Sempra Renewables 252 55 63 Sempra LNG & Midstream 150 (107 ) 44 All other (1,304 ) (116 ) (152 ) Total $ 256 $ 1,370 $ 1,349 ASSETS SDG&E $ 17,844 $ 17,719 $ 16,515 SoCalGas 14,159 13,424 12,104 Sempra South American Utilities 4,060 3,591 3,235 Sempra Mexico 8,554 7,542 3,783 Sempra Renewables 2,898 3,644 1,441 Sempra LNG & Midstream 4,872 5,564 5,566 All other 915 475 734 Intersegment receivables (2,848 ) (4,173 ) (2,228 ) Total $ 50,454 $ 47,786 $ 41,150 EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT SDG&E $ 1,555 $ 1,399 $ 1,133 SoCalGas 1,367 1,319 1,352 Sempra South American Utilities 244 194 154 Sempra Mexico 248 330 302 Sempra Renewables 497 835 81 Sempra LNG & Midstream 20 117 87 All other 18 20 47 Total $ 3,949 $ 4,214 $ 3,156 GEOGRAPHIC INFORMATION Long-lived assets (3) : United States $ 31,487 $ 28,351 $ 26,132 Mexico 5,363 4,814 3,160 South America 2,180 1,863 1,652 Total $ 39,030 $ 35,028 $ 30,944 Revenues (4) : United States $ 8,547 $ 8,004 $ 8,119 South America 1,567 1,556 1,544 Mexico 1,093 623 568 Total $ 11,207 $ 10,183 $ 10,231 (1) Revenues for reportable segments include intersegment revenues of $7 million , $74 million , $103 million and $266 million for 2017 , $6 million , $76 million , $102 million and $180 million for 2016 , and $9 million , $75 million , $101 million and $192 million for 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively. (2) After preferred dividends. (3) Includes net PP&E and investments. (4) Amounts are based on where the revenue originated, after intercompany eliminations.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED) We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below: SEMPRA ENERGY (In millions, except per share amounts) Quarters ended March 31 June 30 September 30 December 31 2017: Revenues $ 3,031 $ 2,533 $ 2,679 $ 2,964 Expenses and other income $ 2,276 $ 2,118 $ 2,664 $ 2,564 Net income (loss) $ 452 $ 248 $ 102 $ (451 ) Earnings (losses) attributable to Sempra Energy $ 441 $ 259 $ 57 $ (501 ) Basic per-share amounts (1) : Net income (loss) $ 1.80 $ 0.99 $ 0.41 $ (1.80 ) Earnings (losses) attributable to Sempra Energy $ 1.76 $ 1.03 $ 0.23 $ (1.99 ) Weighted-average common shares outstanding 251.1 251.4 251.7 251.9 Diluted per-share amounts (1)(2) : Net income (loss) $ 1.79 $ 0.98 $ 0.41 $ (1.80 ) Earnings (losses) attributable to Sempra Energy $ 1.75 $ 1.03 $ 0.22 $ (1.99 ) Weighted-average common shares outstanding 252.2 252.8 253.4 251.9 2016: Revenues $ 2,622 $ 2,156 $ 2,535 $ 2,870 Expenses and other income $ 2,167 $ 2,268 $ 1,553 $ 2,365 Net income $ 364 $ 27 $ 719 $ 409 Earnings attributable to Sempra Energy $ 353 $ 16 $ 622 $ 379 Basic per-share amounts (1) : Net income $ 1.46 $ 0.11 $ 2.87 $ 1.63 Earnings attributable to Sempra Energy $ 1.41 $ 0.06 $ 2.48 $ 1.51 Weighted-average common shares outstanding 249.7 250.1 250.4 250.6 Diluted per-share amounts (1) : Net income $ 1.45 $ 0.11 $ 2.85 $ 1.62 Earnings attributable to Sempra Energy $ 1.40 $ 0.06 $ 2.46 $ 1.51 Weighted-average common shares outstanding 251.5 252.0 252.4 251.6 (1) Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year. (2) In the quarter ended December 31, 2017, the total weighted-average number of potentially dilutive securities was 0.8 million . However, these securities were not included in the computation of U.S. GAAP losses per common share since to do so would have decreased the loss per share. In 2017, Sempra Energy’s income tax expense included $870 million related to the impact of the TCJA, as we discuss in Note 6. In September 2017, SDG&E recognized a charge of $351 million ( $208 million after-tax) for the write-off of its wildfire regulatory asset, which we discuss in Note 15. In June 2017 and September 2016, Sempra Mexico recognized impairment charges of $71 million ( $47 million after noncontrolling interests) and $131 million ( $111 million after-tax; $90 million after-tax and after noncontrolling interests), respectively, related to assets held for sale at TdM. We discuss the impairments in Notes 3 and 10. In September 2016, Sempra Mexico recorded a $617 million noncash gain ( $432 million after-tax; $350 million after-tax and after noncontrolling interests) associated with the remeasurement of its equity interest in IEnova Pipelines, which we discuss in Note 3. In May 2016, Sempra LNG & Midstream recorded a pretax charge of $206 million ( $123 million after-tax) related to permanently released pipeline capacity with Rockies Express and others, which we discuss in Note 15. In May 2017, Sempra LNG & Midstream recorded $47 million ( $28 million after-tax) for settlement proceeds received from a breach of contract claim against a counterparty related to the charge. In March 2016, Sempra LNG & Midstream recognized an impairment charge of $44 million ( $27 million after-tax) on its investment in Rockies Express, which we discuss in Notes 3 and 10. SDG&E (Dollars in millions) Quarters ended March 31 June 30 September 30 December 31 2017: Operating revenues $ 1,057 $ 1,058 $ 1,236 $ 1,125 Operating expenses 779 817 1,290 877 Operating income (loss) $ 278 $ 241 $ (54 ) $ 248 Net income (loss) $ 157 $ 153 $ (19 ) $ 130 (Earnings) losses attributable to noncontrolling interest (2 ) (4 ) (9 ) 1 Earnings (losses) attributable to common shares $ 155 $ 149 $ (28 ) $ 131 2016: Operating revenues $ 991 $ 992 $ 1,209 $ 1,061 Operating expenses 755 822 886 800 Operating income $ 236 $ 170 $ 323 $ 261 Net income $ 137 $ 87 $ 194 $ 147 (Earnings) losses attributable to noncontrolling interest (1 ) 13 (11 ) 4 Earnings attributable to common shares $ 136 $ 100 $ 183 $ 151 SOCALGAS (Dollars in millions) Quarters ended March 31 June 30 September 30 December 31 2017: Operating revenues $ 1,241 $ 770 $ 684 $ 1,090 Operating expenses 926 675 674 888 Operating income $ 315 $ 95 $ 10 $ 202 Net income $ 203 $ 59 $ 7 $ 128 Dividends on preferred stock — (1 ) — — Earnings attributable to common shares $ 203 $ 58 $ 7 $ 128 2016: Operating revenues $ 1,033 $ 617 $ 686 $ 1,135 Operating expenses 739 628 648 899 Operating income (loss) $ 294 $ (11 ) $ 38 $ 236 Net income $ 199 $ — $ — $ 151 Dividends on preferred stock — (1 ) — — Earnings (losses) attributable to common shares $ 199 $ (1 ) $ — $ 151 SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters each year.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS SEMPRA ENERGY As part of our plans to finance the proposed Merger that we discuss in Note 3, we completed the following transactions in January 2018. Common Stock Offering On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock, no par value, in a registered public offering at $107.00 per share ( $105.074 per share after deducting the underwriting discount), pursuant to forward sale agreements with each of Morgan Stanley & Co. LLC, an affiliate of RBC Capital Markets, LLC and an affiliate of Barclays Capital Inc. (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 3,504,672 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 26,869,158 . We received net proceeds of $368 million (net of underwriting discounts, but before deducting other related expenses) from the sale of shares to cover overallotments. The initial forward sale price under the forward sale agreements is $105.074 per share, which is the public offering price in the common stock offering less the underwriting discount. However, the forward sale price is subject to adjustment pursuant to the forward sale agreements. We did not initially receive any proceeds from the sale of our common stock sold by the forward sellers to the underwriters. We expect to settle a portion of the forward sale agreements and receive proceeds, subject to certain adjustments, from the sale of those shares of common stock concurrently with, or prior to, the closing of our proposed Merger. We expect to settle the remaining portion of the forward sale agreements after the Merger, if completed, in multiple settlements on or prior to December 15, 2019, which is the final settlement date under the forward sale agreements. At the initial forward sale price of $105.074 per share, we expect that the net proceeds from full physical settlement of the forward sale agreements would be approximately $2.46 billion (after deducting the underwriting discount, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements). In the case of any forward sales that settle after the closing of the Merger, we intend to use the net proceeds to repay indebtedness incurred to finance a portion of the cost of the Merger Consideration and associated transaction costs. If for any reason the Merger has not closed on or prior to December 1, 2018, or the Merger Agreement is terminated at any time prior to such date, then we expect to use the net proceeds from this offering for general corporate purposes, which may include, in our sole discretion, voluntary redemption of the mandatory convertible preferred stock discussed below, debt repayment (including repayment of commercial paper), capital expenditures, investments and possibly repurchases of our common stock at the discretion of our board of directors. Although we expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the forward purchasers upon the occurrence of certain events. Before the issuance of shares of our common stock, if any, upon settlement of the forward sale agreements, we expect that the shares issuable upon settlement of the forward sale agreements will be reflected in our diluted EPS calculation using the treasury stock method. Under this method, the number of shares of our common stock used in calculating diluted EPS is deemed to be increased by the excess, if any, of the number of shares of common stock that would be issued upon full physical settlement of the forward sale agreements over the number of shares of common stock that could be purchased by us in the market (based on the average market price of our common stock during the applicable reporting period) using the proceeds receivable upon full physical settlement (based on the adjusted forward sale price at the end of the reporting period). Consequently, we anticipate there will be no dilutive effect on our EPS except during periods when the average market price of shares of our common stock is above the applicable adjusted forward sale price, which is initially $105.074 per share, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. However, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS. Mandatory Convertible Preferred Stock Offering On January 9, 2018, in a separate registered public offering, we sold 17,250,000 shares of our 6% mandatory convertible preferred stock, series A (mandatory convertible preferred stock) at $100.00 per share (or $98.20 per share after deducting the underwriting discount), including 2,250,000 shares purchased by the underwriters as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of mandatory convertible preferred stock has a liquidation value of $100 . We intend to use the net proceeds of approximately $1.69 billion (net of underwriting discounts, but before related expenses) from this offering to finance a portion of the Merger Consideration and associated transaction costs. If the proposed Merger is not consummated on or prior to December 1, 2018, or the Merger Agreement is terminated at any time prior to such date, then we expect to use the net proceeds for general corporate purposes, which may include, in our sole discretion, the redemption of the mandatory convertible preferred stock, debt repayment (including repayment of commercial paper), capital expenditures, investments and possibly repurchases of our common stock at the discretion of our board of directors. Mandatory Conversion Unless earlier converted or redeemed, each share of the mandatory convertible preferred stock will automatically convert on the mandatory conversion date, which is expected to be January 15, 2021, into not less than 0.7629 and not more than 0.9345 shares of our common stock, subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion of the mandatory convertible preferred stock will be determined based on the volume-weighted average market value per share of our common stock over the 20 consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding January 15, 2021, which we refer to as the “settlement period.” The following table illustrates the conversion rate per share of the mandatory convertible preferred stock, subject to certain anti-dilution adjustments: CONVERSION RATES Applicable market value per share of Conversion rate (number of shares of our common stock to be received upon conversion of each share of mandatory convertible preferred stock) Greater than $131.075 (which is the threshold appreciation price) 0.7629 shares (approximately equal to $100.00 divided by the threshold appreciation price) Equal to or less than $131.075 but greater than or equal to $107.00 Between 0.7629 and 0.9345 shares, determined by dividing $100.00 by the applicable market value of our common stock Less than $107.00 (which is the initial price) 0.9345 shares (approximately equal to $100.00 divided by the initial price) Dividends Dividends on the mandatory convertible preferred stock will be payable quarterly, beginning on April 15, 2018, on a cumulative basis when, as and if declared by our board of directors. We may pay quarterly declared dividends in cash, or subject to certain limitations, in shares of our common stock, no par value, or in any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97 percent of the volume-weighted average price per share over the five consecutive trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date. The holders of mandatory convertible preferred stock will have no voting rights. However, under certain circumstances regarding nonpayment for six or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the mandatory convertible preferred stock, voting together as a single class with holders of any and all other outstanding preferred stock of equal rank having similar voting rights, will be entitled to elect two directors to fill such newly created directorships. This right shall terminate when all accumulated dividends have been paid in full and the authorized number of directors shall automatically decrease by two, subject to revesting of that right in the event of each subsequent nonpayment. Acquisition Termination Redemption If the proposed Merger has not closed on or before December 1, 2018, the Merger Agreement is terminated or if we determine in our reasonable judgment that the proposed Merger will not occur, we may, at our option, redeem the mandatory convertible preferred stock, in whole but not in part, at a redemption amount per share, in cash, equal to an acquisition termination make-whole amount. However, if the acquisition termination share price exceeds the initial price, then, subject to certain limitations, we may pay part or all of the redemption price in shares of our common stock. The redemption of the mandatory convertible preferred stock gives us the option to redeem, in whole but not in part, the mandatory convertible preferred stock at a make-whole redemption price per share that includes a make-whole adjustment which could provide a redemption price that exceeds the initial public offering price of $100.00 per share, plus accrued and unpaid dividends. We may satisfy the redemption price by delivering cash, common stock or a combination thereof. Conversion at the Option of the Holder At any time prior to January 15, 2021, holders may elect to convert each share of the mandatory convertible preferred stock into shares of our common stock at the minimum conversion rate of 0.7629 shares of our common stock per share of the mandatory convertible preferred stock, subject to anti-dilution adjustments. However, if holders elect to convert any shares of the mandatory convertible preferred stock during a specified period beginning on the effective date of a fundamental change, as defined, such shares of the mandatory convertible preferred stock will be converted into shares of our common stock at a fundamental change conversion rate, and the holders will also be entitled to receive a fundamental change dividend make-whole amount and accumulated dividend amount. Ranking The mandatory convertible preferred stock will rank with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution: ▪ senior to our common stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise; ▪ junior to our existing and future indebtedness and other liabilities; and ▪ structurally subordinated to any existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties. The conversion of the mandatory convertible preferred stock would have resulted in the issuance of approximately 16.1 million shares of our common stock, subject to possible adjustment pursuant to the terms of the mandatory convertible preferred stock, based on the last reported sale price of our common stock on the New York Stock Exchange on December 29, 2017, which was $106.92 per share. However, if the mandatory convertible preferred stock had been issued January 1, 2017 and dividends paid for the full year 2017, an adjustment for the shares issuable on conversion would not have been reflected in our computation of diluted EPS for 2017 because the issuance of those shares would be anti-dilutive. Long-Term Debt Offering On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses): NOTES ISSUED IN LONG-TERM DEBT OFFERING (Dollars in millions) Title of each class of securities Aggregate principal amount Maturity Interest payments Floating Rate (1) Notes due 2019 $ 500 July 15, 2019 Quarterly Floating Rate (2) Notes due 2021 700 January 15, 2021 Quarterly 2.400% Senior Notes due 2020 500 February 1, 2020 Semi-annually 2.900% Senior Notes due 2023 500 February 1, 2023 Semi-annually 3.400% Senior Notes due 2028 1,000 February 1, 2028 Semi-annually 3.800% Senior Notes due 2038 1,000 February 1, 2038 Semi-annually 4.000% Senior Notes due 2048 800 February 1, 2048 Semi-annually (1) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points. (2) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points. The 2019 floating rate notes are not subject to redemption at our option. At our option, we may redeem some or all of the 2021 floating rate notes at any time on or after January 14, 2019 at the applicable redemption price per the terms of the notes. At our option, we may redeem some or all of the fixed rate notes of each series at any time at the applicable redemption price for such series of fixed rate notes. We intend to use the net proceeds from this offering to finance a portion of the Merger Consideration and associated transaction costs. If we do not consummate the Merger on or prior to December 1, 2018, or if, on or prior to such date, the Merger agreement is terminated, we will be required to redeem all of the outstanding notes (other than the 2028 notes) at a redemption price equal to 101 percent of the principal amount of the notes we are required to redeem, plus accrued and unpaid interest, if any. The 2028 notes are not subject to this special mandatory redemption. If we are required to redeem the notes, we may use all or a portion of the net proceeds we received from the issuance of these notes to pay all or a portion of the redemption price of the notes we are required to redeem, and we intend to use any remaining net proceeds for general corporate purposes, which may include, in our sole discretion, voluntary redemption of our mandatory convertible preferred stock, repayment of other debt (including repayment of commercial paper), capital expenditures, investments and possibly, repurchases of our common stock at the discretion of our board of directors. Ranking The notes are unsecured and unsubordinated obligations, ranking on a parity in right of payment with all of our other unsecured and unsubordinated indebtedness and guarantees. If the proposed Merger is consummated, the notes will also be effectively subordinated to all existing and future indebtedness and other liabilities of Oncor Holdings, Oncor and their respective subsidiaries.

SCHEDULE I, CONDENSED FINANCIAL

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent	SEMPRA ENERGY CONDENSED STATEMENTS OF OPERATIONS (Dollars in millions, except per share amounts) Years ended December 31, 2017 2016 2015 Interest expense $ (293 ) $ (277 ) $ (261 ) Operation and maintenance (87 ) (81 ) (66 ) Other income (expense), net 107 (2 ) 7 Income tax benefit 33 181 150 Loss before equity in earnings of subsidiaries (240 ) (179 ) (170 ) Equity in earnings of subsidiaries, net of income taxes 496 1,549 1,519 Net income/earnings $ 256 $ 1,370 $ 1,349 Basic earnings per common share $ 1.02 $ 5.48 $ 5.43 Weighted-average number of shares outstanding (thousands) 251,545 250,217 248,249 Diluted earnings per common share $ 1.01 $ 5.46 $ 5.37 Weighted-average number of shares outstanding (thousands) 252,300 251,155 250,923 See Notes to Condensed Financial Information of Parent. SEMPRA ENERGY CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Dollars in millions) Years ended December 31, Pretax amount Income tax benefit (expense) Net-of-tax amount 2017: Net income $ 223 $ 33 $ 256 Other comprehensive income (loss): Foreign currency translation adjustments 107 — 107 Financial instruments 2 1 3 Pension and other postretirement benefits 20 (8 ) 12 Total other comprehensive income 129 (7 ) 122 Comprehensive income $ 352 $ 26 $ 378 2016: Net income $ 1,189 $ 181 $ 1,370 Other comprehensive income (loss): Foreign currency translation adjustments 42 — 42 Financial instruments (6 ) 11 5 Pension and other postretirement benefits (13 ) 4 (9 ) Total other comprehensive income 23 15 38 Comprehensive income $ 1,212 $ 196 $ 1,408 2015: Net income $ 1,199 $ 150 $ 1,349 Other comprehensive income (loss): Foreign currency translation adjustments (260 ) — (260 ) Financial instruments (80 ) 33 (47 ) Pension and other postretirement benefits (3 ) 1 (2 ) Total other comprehensive loss (343 ) 34 (309 ) Comprehensive income $ 856 $ 184 $ 1,040 See Notes to Condensed Financial Information of Parent. SEMPRA ENERGY CONDENSED BALANCE SHEETS (Dollars in millions) December 31, December 31, Assets: Cash and cash equivalents $ 104 $ 12 Due from affiliates 83 73 Income taxes receivable 272 — Other current assets 6 2 Total current assets 465 87 Investments in subsidiaries 17,924 17,329 Due from affiliates 2 — Deferred income taxes 1,802 2,570 Other assets 656 592 Total assets $ 20,849 $ 20,578 Liabilities and shareholders’ equity: Current portion of long-term debt $ 500 $ 600 Due to affiliates 280 359 Income taxes payable — 153 Other current liabilities 396 374 Total current liabilities 1,176 1,486 Long-term debt 6,198 5,100 Due to affiliates 300 517 Other long-term liabilities 505 524 Commitments and contingencies (Note 4) Shareholders’ equity 12,670 12,951 Total liabilities and shareholders’ equity $ 20,849 $ 20,578 See Notes to Condensed Financial Information of Parent. SEMPRA ENERGY CONDENSED STATEMENTS OF CASH FLOWS (Dollars in millions) Years ended December 31, 2017 2016 (1) 2015 (1) Net cash provided by (used in) operating activities $ 89 $ (3 ) $ 95 Expenditures for property, plant and equipment (11 ) (5 ) (43 ) Purchase of trust assets — — (5 ) Decrease (increase) in loans to affiliates, net — 457 (457 ) Expenditures for Merger-related transaction costs (12 ) — — Net cash (used in) provided by investing activities (23 ) 452 (505 ) Common stock dividends paid (755 ) (686 ) (628 ) Issuances of common stock 47 51 52 Repurchases of common stock (15 ) (56 ) (74 ) Issuances of long-term debt 1,595 499 1,248 Payments on long-term debt (600 ) (750 ) — (Decrease) increase in loans from affiliates, net (239 ) 504 (230 ) Tax benefit related to share-based compensation — — 52 Other (7 ) (3 ) (9 ) Net cash provided by (used in) financing activities 26 (441 ) 411 Increase in cash and cash equivalents 92 8 1 Cash and cash equivalents, January 1 12 4 3 Cash and cash equivalents, December 31 $ 104 $ 12 $ 4 SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES Accrued Merger-related transaction costs $ 31 $ — $ — Financing of build-to-suit property — — 61 Common dividends issued in stock 53 53 55 Dividends declared but not paid 207 189 174 (1) As adjusted for the retrospective adoption of ASU 2016-15, which we discuss in Note 2. See Notes to Condensed Financial Information of Parent. BASIS OF PRESENTATION Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information. Other Income, Net, on the Condensed Statements of Operations includes ▪ $56 million , $23 million and $3 million of gains on dedicated assets in support of our executive retirement and deferred compensation plans in 2017, 2016 and 2015, respectively; and ▪ $50 million and $(28) million net gains (losses) primarily from the settlement of foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova in 2017 and 2016, respectively. Additional information on Sempra Energy’s foreign currency derivatives is provided in Note 9 of the Notes to Consolidated Financial Statements. NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below) ▪ Issue 6 – distributions received from equity method investments The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Condensed Statements of Cash Flows: Cash flows from operating activities: Net cash (used in) provided by operating activities $ (178 ) $ 175 $ (3 ) $ (255 ) $ 350 $ 95 Cash flows from investing activities: Dividends received from subsidiaries (1) 175 (175 ) — 350 (350 ) — Net cash provided by (used in) investing activities 627 (175 ) 452 (155 ) (350 ) (505 ) (1) Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Condensed Statements of Operations: Operation and maintenance $ (87 ) $ (80 ) $ (81 ) $ (76 ) Other income (expense), net 107 100 (2 ) (7 ) ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard. LONG-TERM DEBT The following table shows the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease 138 137 6,737 5,734 Current portion of long-term debt (500 ) (600 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized debt issuance costs (26 ) (24 ) Total long-term debt $ 6,198 $ 5,100 Excluding the build-to-suit lease and market value adjustments for interest rate swaps, maturities of long-term debt are $500 million in 2018, $1 billion in 2019, $900 million in 2020, $850 million in 2021, $500 million in 2022 and $2.85 billion thereafter. Additional information on Sempra Energy’s long-term debt is provided in Note 5 of the Notes to Consolidated Financial Statements. COMMITMENTS AND CONTINGENCIES For contingencies and guarantees related to Sempra Energy, refer to Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements. SUBSEQUENT EVENTS For subsequent events related to Sempra Energy, refer to Note 18 of the Notes to Consolidated Financial Statements.

SIGNIFICANT ACCOUNTING POLICI28

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation	PRINCIPLES OF CONSOLIDATION Sempra Energy Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Energy’s principal operating units are ▪ Sempra Utilities, which includes our SDG&E, SoCalGas and Sempra South American Utilities reportable segments; and ▪ Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments. We provide descriptions of each of our segments in Note 16. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our South American utilities or the utilities in our Sempra Infrastructure operating unit. 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 Utilities,” “Sempra Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. IEnova is a separate legal entity comprised of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. IEnova’s financial results are reported in Mexico under International Financial Reporting Standards, as required by the Mexican Stock Exchange, where its shares are traded under the symbol IENOVA. Sempra Energy uses the equity method to account for investments in companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 3, 4 and 10. SDG&E SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra Energy. SoCalGas SoCalGas’ common stock is wholly owned by 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. Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively: ▪ the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs; ▪ the Consolidated Financial Statements and related Notes of SDG&E and its VIE; and ▪ the Financial Statements and related Notes of SoCalGas.
Use of Estimates in the Preparation of the Financial Statements	Use of Estimates in the Preparation of the Financial Statements We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.
Subsequent Events	Subsequent Events We evaluated events and transactions that occurred after December 31, 2017 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.
Regulatory Operations	EFFECTS OF REGULATION The California Utilities’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods. Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of: ▪ the nature of the event giving rise to the assessment; ▪ existing statutes and regulatory code; ▪ legal precedents; ▪ regulatory principles and analogous regulatory actions; ▪ testimony presented in regulatory hearings; ▪ regulatory orders; ▪ a commission-authorized mechanism established for the accumulation of costs; ▪ status of applications for rehearings or state court appeals; ▪ specific approval from a commission; and ▪ historical experience . Sempra Mexico’s natural gas distribution utility, Ecogas, also applies U.S. GAAP for rate-regulated utilities to its operations, including the same evaluation of probability of recovery of regulatory assets described above. We provide information concerning regulatory assets and liabilities in Notes 13 and 14. Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Revenues are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction by IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.” Sempra LNG & Midstream owned Mobile Gas in southwest Alabama and Willmut Gas in Mississippi until they were sold in September 2016, as we discuss in Note 3. Mobile Gas and Willmut Gas also prepared their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.
Fair Value Measurements	FAIR VALUE MEASUREMENTS We measure certain assets and liabilities at fair value on a recurring basis, primarily nuclear decommissioning and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances. These assets can include goodwill, intangible assets, equity method investments and other long-lived assets. “Fair value” is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value. We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 – Pricing inputs are quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including: ▪ quoted forward prices for commodities ▪ time value ▪ current market and contractual prices for the underlying instruments ▪ volatility factors ▪ other relevant economic measures Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E. Fair Value of Financial Instruments The fair values of certain of our financial instruments (cash, accounts and notes receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. RECURRING FAIR VALUE MEASURES The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 . 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. The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 in “Financial Statement Presentation.” The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 in the tables below include the following: ▪ Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2). ▪ For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information.” ▪ Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both December 31, 2017 and 2016 . We determine the fair value of certain long-term amounts due from/to unconsolidated affiliates and long-term debt based on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value certain other long-term amounts due from unconsolidated affiliates using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).
Cash and Cash Equivalents	CASH AND CASH EQUIVALENTS Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.
Collection Allowances	COLLECTION ALLOWANCES We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to collection allowances are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends. We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.
Inventories	INVENTORIES The California Utilities value natural gas inventory using the LIFO method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. At December 31, 2016, SoCalGas recognized a permanent LIFO liquidation of $33 million . The California Utilities generally value materials and supplies at the lower of average cost or net realizable value. Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra LNG & Midstream value LNG inventory using the first-in first-out method.
Income Taxes	INCOME TAXES Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC. At our other businesses, we reduce the book basis of the related asset by the amount of ITCs earned. At Sempra Renewables, PTCs are recognized in income tax expense as earned. Under the regulatory accounting treatment required for flow-through temporary differences, as discussed in Note 6, the California Utilities and Sempra Mexico recognize ▪ regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and ▪ regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers. When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more likely than not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more likely than not criterion at the largest amount of tax benefit that is greater than 50 percent likely of being realized upon its effective resolution. Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR. On December 22, 2017, the TCJA was signed into law. As a result, all cumulative undistributed earnings from non-U.S. subsidiaries were deemed repatriated and subjected to a one-time U.S. federal deemed repatriation tax. To the extent we intend to repatriate cash into the U.S., incremental U.S. state and non-U.S. withholding taxes are accrued. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries to the extent the related cumulative undistributed earnings are indefinitely reinvested. We recorded the effects of the TCJA in 2017 using our best estimates and the information available to us through the date the financial statements were issued. However, our analysis is ongoing and as such, the income tax effects that we have recorded are provisional. As permitted by and in accordance with the guidance issued by the SEC, we may adjust our provisional estimates in future reporting periods throughout 2018 as we complete our analysis and as more information becomes available, and these adjustments may affect earnings. Events and information that may result in adjustments to our provisional estimates include interpretations or rulings by the U.S. Department of the Treasury or states, the filing of our 2017 income tax return and the finalization of our calculation of foreign undistributed earnings. For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment: ▪ repairs expenditures related to a certain portion of utility plant fixed assets ▪ the equity portion of AFUDC ▪ a portion of the cost of removal of utility plant assets ▪ utility self-developed software expenditures ▪ depreciation on a certain portion of utility plant assets ▪ state income taxes The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment. The 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings. We expect that certain amounts recorded in the tracking accounts may give rise to regulatory assets or liabilities. We discuss the tracking accounts further in Note 14. On December 22, 2017, the TCJA was signed into law. This legislation significantly changes the IRC. Under U.S. GAAP, certain effects of the TCJA are required to be recognized upon enactment, and, as a result, Sempra Energy, SDG&E, and SoCalGas recorded the related effects in 2017. The TCJA reduces the U.S. statutory corporate income tax rate from 35 percent to 21 percent , effective January 1, 2018, which will be applied to future U.S. earnings. U.S. GAAP requires that deferred income tax assets and liabilities, including NOLs, be remeasured at the income tax rate expected to apply when those temporary differences reverse and that the effects of any change to such income tax rate be recognized in the period when the change was enacted. This remeasurement resulted in significant reductions in deferred income tax balances at Sempra Energy Consolidated, SDG&E and SoCalGas. The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes that previously have been collected from ratepayers at the higher rate. These excess deferred income taxes have been recorded as regulatory liabilities as of December 31, 2017 and will be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and FERC.
Greenhouse Gas Allowances and Emissions and Renewable Energy Certificates	GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS The California Utilities, Sempra Mexico and Sempra LNG & Midstream are required by California AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. At the California Utilities, many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Mexico and Sempra LNG & Midstream record the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered. RENEWABLE ENERGY CERTIFICATES RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets. Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS. The cost of RECs at SDG&E is recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations.
Property, Plant and Equipment (PP&E)	Depreciation expense is computed using the straight-line method over the asset’s estimated original composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest. The California Utilities finance their construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets. Pipeline projects currently under construction by Sempra Mexico and Sempra LNG & Midstream that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC. We capitalize interest costs incurred to finance capital projects. We also capitalize interest on equity method investments that have not commenced planned principal operations. PROPERTY, PLANT AND EQUIPMENT PP&E primarily represents the buildings, equipment and other facilities used by the Sempra Utilities to provide natural gas and electric utility services, and by the Sempra Infrastructure businesses in their operations, including construction work in progress at these operating units. PP&E also includes lease improvements and other equipment at Parent and Other, as well as property acquired under a build-to-suit lease, which we discuss further in Note 15. Our plant costs include ▪ labor ▪ materials and contract services ▪ expenditures for replacement parts incurred during a major maintenance outage of a generating plant In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP at Sempra Mexico and Sempra LNG & Midstream includes AFUDC. We discuss AFUDC below. The cost of other PP&E includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.
Goodwill and Other Intangible Assets	Other Intangible Assets primarily includes ▪ storage and development rights related to the Bay Gas and Mississippi Hub natural gas storage facilities. ▪ a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities. ▪ a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 3. GOODWILL AND OTHER INTANGIBLE ASSETS Goodwil l 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 we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. 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. For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include ▪ consideration of market transactions ▪ future cash flows ▪ the appropriate risk-adjusted discount rate ▪ country risk ▪ entity risk
Long-lived Assets	LONG-LIVED ASSETS We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated subsidiaries. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include ▪ significant decreases in the market price of an asset ▪ a significant adverse change in the extent or manner in which we use an asset or in its physical condition ▪ a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset ▪ a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset ▪ a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
Variable Interest Entities (VIE)	VARIABLE INTEREST ENTITIES We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess ▪ the purpose and design of the VIE; ▪ the nature of the VIE’s risks and the risks we absorb; ▪ the power to direct activities that most significantly impact the economic performance of the VIE; and ▪ the obligation to absorb losses or the right to receive benefits that could be significant to the VIE .
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS For tangible long-lived assets, we record asset retirement obligations for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost over the life of the related asset by depreciating the asset retirement cost (measured as the present value of the obligation at the time the asset is placed into service), and accreting the obligation until the liability is settled. Our rate-regulated entities, including the California Utilities, record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.
Contingencies	CONTINGENCIES We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and: ▪ information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and ▪ the amount of the loss can be reasonably estimated. We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.
Legal Fees	LEGAL FEES Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable. LEGAL PROCEEDINGS We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.
Comprehensive Income	COMPREHENSIVE INCOME Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including: ▪ foreign currency translation adjustments ▪ certain hedging activities ▪ changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans ▪ unrealized gains or losses on available-for-sale securities The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to noncontrolling interests
Noncontrolling Interests	NONCONTROLLING INTERESTS 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. Noncontrolling interests are reported as a separate component of equity on the Consolidated Balance Sheets. Earnings/losses attributable to the noncontrolling interests are separately identified on the Consolidated Statements of Operations, and net income/loss and comprehensive income/loss attributable to noncontrolling interests are separately identified on the Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Changes in Equity.
Revenues	REVENUES California Utilities Our California Utilities generate revenues primarily from deliveries to their customers of electricity by SDG&E and natural gas by both SoCalGas and SDG&E and from related services. We record these revenues following the accrual method and recognize them upon delivery and performance. As described below, recorded revenues include those authorized by the CPUC to support our operations (“decoupled revenue”), as well as commodity costs that are passed through to core gas customers and electric customers: ▪ Decoupled revenue – The regulatory framework permits the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. Any difference between actual demand and the annual demand approved in the proceedings is recovered or refunded in authorized revenue in a subsequent period. This design, commonly known as “decoupling,” is intended to minimize any impact on earnings due to variability in volumetric demand for electricity and natural gas. ▪ Commodity costs – The regulatory framework authorizes the California Utilities to recover the actual cost of natural gas procured and delivered to their core customers in rates substantially as incurred. Actual electricity procurement costs are recovered as power is delivered, or to the extent actual amounts vary from forecasts, generally recovered or refunded within a subsequent period. The California Utilities may also record revenue from CPUC-approved incentive awards, some of which require approval by the CPUC prior to being recognized. SDG&E bids and self-schedules its generation into the CAISO energy market on a day-ahead and real-time basis and self-schedules power to serve the demand of its customers. Generally, SDG&E is a net purchaser of power. The CAISO settles SDG&E costs and revenues on an hourly and real-time net basis. Sempra South American Utilities Our electric distribution utilities in South America, Chilquinta Energía and Luz del Sur, serve primarily regulated customers, and their revenues are based on tariffs that are set by the CNE in Chile and the OSINERGMIN in Peru. The tariffs charged are based on an efficient model distribution company defined by Chilean law in the case of Chilquinta Energía, and OSINERGMIN in the case of Luz del Sur. The tariffs include O&M, an internal rate of return on the new replacement value of depreciable assets, charges for the use of transmission systems, and a component for the value added by the distributor. Tariffs are designed to provide for a pass-through to customers of transmission and energy charges, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base. Sempra Infrastructure Our natural gas utilities outside of California apply U.S. GAAP for revenue recognition consistent with the California Utilities, namely Ecogas, our natural gas utility in Mexico, and Mobile Gas and Willmut Gas, our natural gas utilities in Alabama and Mississippi, respectively, that were sold in September 2016. The table below shows the total utilities revenues in Sempra Energy’s Consolidated Statements of Operations for each of the last three years. The revenues include amounts for services rendered but unbilled (approximately one-half month’s deliveries) at the end of each year. Energy-Related Businesses Sempra South American Utilities Sempra South American Utilities generates revenues from energy-services companies that provide electric construction services and recognizes these revenues when services are provided in accordance with contractual agreements. The energy-services company in Chile also generates revenue from selling electricity to non-regulated customers. Sempra Mexico Sempra Mexico recognizes revenues from: ▪ pipeline transportation and storage of natural gas, LPG and ethane as capacity is provided. Certain of the revenues recognized from pipelines are under contracts that are accounted for as operating leases; ▪ sale of natural gas as deliveries are made; ▪ an LNG regasification terminal that generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements as capacity is provided; ▪ wind power generation facilities that generate revenues from selling electricity as the power is delivered at the interconnection point; and ▪ TdM, a natural gas-fired power plant that generates revenues from selling electricity and/or capacity to the CAISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point. At December 31, 2017, TdM is classified as held for sale, as we discuss in Note 3. Sempra Mexico reports revenue net of VAT in Mexico. Sempra Mexico’s revenues also include net realized gains and losses on settlements of energy derivatives and net unrealized gains and losses from the change in fair values of energy derivatives. Sempra Renewables For consolidated entities, Sempra Renewables generates revenues from the sale of solar and wind power and related green attributes pursuant to PPAs, and recognizes these revenues when the power is delivered. It also generates revenues for managing certain of its solar and wind project joint ventures. Approximately half of the revenues generated from assets under PPAs are accounted for as operating leases. Sempra LNG & Midstream Sempra LNG & Midstream records revenues from contractual counterparty obligations for non-delivery of LNG cargoes, as well as revenues from the sale of LNG and natural gas as deliveries are made to counterparties. Sempra LNG & Midstream also recognizes revenues from natural gas storage and transportation operations for services provided in accordance with contractual agreements. Sempra LNG & Midstream revenues also include net realized gains and losses on settlements of energy derivatives and net unrealized gains and losses from the change in fair values of energy derivatives. Prior to April 2015, Sempra LNG & Midstream generated revenues from selling electricity and/or capacity from its Mesquite Power plant (see Note 3) to the CAISO and to governmental, public utility and wholesale power marketing entities. Sempra LNG & Midstream recognized these revenues as the electricity was delivered and capacity was provided.
Other Cost of Sales	OTHER COST OF SALES Other Cost of Sales primarily includes ▪ pipeline capacity costs, including the permanent release of pipeline capacity in 2016 and the associated recoveries in 2017, at Sempra LNG & Midstream; ▪ pipeline transportation and natural gas marketing costs at Sempra LNG & Midstream; ▪ electric construction services costs at Sempra South American Utilities’ energy-services companies; and ▪ energy management service fees and costs associated with construction performed for and invoiced to third parties at Sempra Mexico.
Operation and Maintenance Expenses	OPERATION AND MAINTENANCE EXPENSES Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.
Foreign Currency Translation	FOREIGN CURRENCY TRANSLATION Our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI. Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in “Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash” on the Sempra Energy Consolidated Statements of Cash Flows.
New Accounting Standards	NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures. ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606. ASU 2015-14 defers the effective date of ASC 606 by one year for all entities and permits early adoption on a limited basis. For public entities, ASC 606 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which will result in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification has no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers will be included in our Notes to Consolidated Financial Statements beginning in the first quarter of 2018. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs ▪ Issue 3 – contingent consideration payments made after a business combination ▪ Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies) ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents. ASU 2016-15 and ASU 2016-18 must be adopted retrospectively. We early adopted ASU 2016-15 and ASU 2016-18 in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Statements of Cash Flows. Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Consolidated Statements of Cash Flows: Cash flows from operating activities: Adjustments to reconcile net income to net cash provided by $ 63 $ (1 ) $ 62 $ 66 $ — $ 66 Changes in other assets 56 (7 ) 49 (162 ) (7 ) (169 ) Net cash provided by operating activities 2,319 (8 ) 2,311 2,905 (7 ) 2,898 Cash flows from investing activities: Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired (1,582 ) 1,582 — (200 ) 200 — Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired — (1,504 ) (1,504 ) — (198 ) (198 ) Increases in restricted cash (139 ) 139 — (100 ) 100 — Decreases in restricted cash 175 (175 ) — 93 (93 ) — Other — 9 9 1 8 9 Net cash used in investing activities (4,886 ) 51 (4,835 ) (2,885 ) 17 (2,868 ) Cash flows from financing activities: Other (10 ) (11 ) (21 ) (17 ) (3 ) (20 ) Net cash provided by (used in) financing activities 2,513 (11 ) 2,502 (173 ) (3 ) (176 ) Effect of exchange rate changes on cash and cash equivalents — — — (14 ) 14 — Effect of exchange rate changes on cash, cash equivalents and restricted cash — (3 ) (3 ) — (14 ) (14 ) Decrease in cash and cash equivalents (54 ) 54 — (167 ) 167 — Decrease in cash, cash equivalents, and restricted cash — (25 ) (25 ) — (160 ) (160 ) Cash and cash equivalents, January 1 403 (403 ) — 570 (570 ) — Cash, cash equivalents and restricted cash, January 1 — 450 450 — 610 610 Cash and cash equivalents, December 31 349 (349 ) — 403 (403 ) — Cash, cash equivalents and restricted cash, December 31 — 425 425 — 450 450 SDG&E Consolidated Statements of Cash Flows: Cash flows from operating activities: Changes in other assets $ (16 ) $ (4 ) $ (20 ) $ (122 ) $ (3 ) $ (125 ) Net cash provided by operating activities 1,327 (4 ) 1,323 1,664 (3 ) 1,661 Cash flows from investing activities: Increases in restricted cash (49 ) 49 — (39 ) 39 — Decreases in restricted cash 60 (60 ) — 35 (35 ) — Other — 6 6 — 5 5 Net cash used in investing activities (1,319 ) (5 ) (1,324 ) (1,086 ) 9 (1,077 ) Cash flows from financing activities: Other (1) (4 ) (2 ) (6 ) (2 ) (2 ) (4 ) Net cash used in financing activities (20 ) (2 ) (22 ) (566 ) (2 ) (568 ) (Decrease) increase in cash and cash equivalents (12 ) 12 — 12 (12 ) — (Decrease) increase in cash, cash equivalents, and restricted cash — (23 ) (23 ) — 16 16 Cash and cash equivalents, January 1 20 (20 ) — 8 (8 ) — Cash, cash equivalents and restricted cash, January 1 — 43 43 — 27 27 Cash and cash equivalents, December 31 8 (8 ) — 20 (20 ) — Cash, cash equivalents and restricted cash, December 31 — 20 20 — 43 43 (1) Previously labeled “Debt issuance costs.” ASU 2017-01, “Clarifying the Definition of a Business”: ASU 2017-01 narrows the definition of a business and provides a framework to assist entities in determining whether a transaction involves an asset or a business. Specifically, the ASU provides a “screen” for determining when an integrated set of assets and activities (collectively referred to as a “set”) is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted. We early adopted ASU 2017-01 on July 1, 2017. ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard. ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. Entities may apply a full retrospective or modified retrospective approach. Under a modified retrospective approach, entities are required to apply the guidance to any transactions that are not completed as of the adoption date. We adopted the standard in conjunction with our adoption of ASC 606 on January 1, 2018 using the modified retrospective transition method. As we discuss in Note 1, Sempra Renewables expects the formation of a tax equity arrangement to be completed in the first half of 2018. While the arrangement would be in the scope of this ASU, we do not expect it to have a material impact on our financial condition, results of operations or cash flows. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Consolidated Statements of Operations: Operation and maintenance $ 3,117 $ 3,096 $ 2,970 $ 2,976 Other income, net 254 233 132 138 SDG&E Consolidated Statements of Operations: Operation and maintenance $ 1,020 $ 1,024 $ 1,048 $ 1,062 Operating income 713 709 990 976 Other income, net 66 70 50 64 SoCalGas Statements of Operations: Operation and maintenance $ 1,479 $ 1,474 $ 1,385 $ 1,391 Operating income 622 627 557 551 Other income, net 36 31 32 38 ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. For public entities, ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. If an entity early adopts ASU 2017-12 in an interim period, any transition adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. Entities will adopt ASU 2017-12 by applying a modified retrospective approach to the accounting for existing hedging relationships and will prospectively apply the new presentation and disclosure requirements. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018, and it will not materially affect our financial condition, results of operations or cash flows. ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard. NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below) ▪ Issue 6 – distributions received from equity method investments The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Condensed Statements of Cash Flows: Cash flows from operating activities: Net cash (used in) provided by operating activities $ (178 ) $ 175 $ (3 ) $ (255 ) $ 350 $ 95 Cash flows from investing activities: Dividends received from subsidiaries (1) 175 (175 ) — 350 (350 ) — Net cash provided by (used in) investing activities 627 (175 ) 452 (155 ) (350 ) (505 ) (1) Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Condensed Statements of Operations: Operation and maintenance $ (87 ) $ (80 ) $ (81 ) $ (76 ) Other income (expense), net 107 100 (2 ) (7 ) ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard.
Business Combinations	We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date. Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on their respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. None of the goodwill is expected to be deductible in Mexico or the U.S. for income tax purposes. Valuation of IEnova Pipelines’ Assets and Liabilities. Based on the nature of the Mexico regulatory environment and the oversight surrounding the establishment and maintenance of rates that IEnova Pipelines charges for services on its assets, IEnova Pipelines applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Therefore, when determining the fair value of the acquired assets and liabilities assumed, we considered the effect of regulation on a market participant’s view of the highest and best use of the assets, in particular for the fair value of IEnova Pipelines’ PP&E. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s PP&E, and the impact of regulation is considered a fundamental input to measuring the fair value of PP&E in a business combination involving a regulated business. Under this premise, the fair value of the PP&E of a regulated business is generally assumed to be equivalent to carrying value for financial reporting purposes. Management concluded that the carrying value of IEnova Pipelines’ PP&E is representative of fair value. We applied an income approach, specifically the discounted cash flow method, to measure the fair value of debt and derivatives. We valued debt by discounting future debt payments by a market yield, and we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data. For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature. Valuation of Ventika’s Assets and Liabilities. The fair values of the tangible and intangible assets acquired and liabilities assumed were recognized based on their preliminary values at the acquisition date. Significant inputs used to measure the fair values of the acquired PP&E, intangible asset, debt, and derivatives are as follows: ▪ PP&E – We applied an income approach using market-based discounted cash flows. We used the pricing included in the existing PPAs, which was determined to reflect current market rates in the Mexican renewable energy market. ▪ Intangible asset – Ventika is the holder of a renewable energy transmission and consumption permit that allows it to transmit its generated power to various locations within Mexico at beneficial rates and reduces the administrative burden to manage transmitting power to off-takers. With recent renewable energy market reforms in Mexico, these transmission and consumption permits are no longer available, resulting in higher tariffs for generators. We applied an income approach based on a cash flow differential approach that measures the fair value of the transmission rights by comparing the operating expenses under the transmission and consumption permit as compared to under the new, higher tariffs. This acquired intangible asset has an amortization period of 19 years , reflecting the remaining life of the transmission and consumption transmission permit at the time of acquisition. ▪ Debt – Using an income approach, we valued debt by discounting future debt payments by a market yield commensurate with the remaining term of the loans. ▪ Derivatives – Using an income approach, we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data. Additionally, we recognized deferred income taxes on Ventika’s existing NOLs, and for the difference between the fair values and tax bases of the net assets acquired using the Mexican statutory rate. For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature. Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on their respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. None of the goodwill is expected to be deductible in Mexico or in the U.S. for income tax purposes.
Environmental Costs	We record environmental liabilities at undiscounted amounts when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary. At the California Utilities, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates. The environmental issues currently facing us, except for those related to the Aliso Canyon natural gas storage facility leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities at sites for which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS. We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:
Investments in Noncontrolling Interests	We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. We adjust each investment for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss. We evaluate the carrying value of unconsolidated entities for impairment under the U.S. GAAP provisions for equity method investments.
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS We are required by applicable U.S. GAAP to: ▪ recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position; ▪ measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and ▪ recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity. The detailed information presented below covers the employee benefit plans of Sempra Energy and its consolidated subsidiaries. Sempra Energy has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology. IEnova has an unfunded noncontributory defined benefit plan covering all employees. Chilquinta Energía has an unfunded noncontributory defined benefit plan covering all employees hired before October 1, 1981 and an unfunded noncontributory termination indemnity plan covering represented employees. The plans generally provide defined benefits to retirees based on date of hire, years of service and final average earnings. Sempra Energy also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses. Chilquinta Energía also has two noncontributory postretirement benefit plans which cover represented employees – a health care plan and an energy subsidy plan that provides for reduced energy rates. The health care plan includes benefits for retirees’ spouses and dependents. Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans. Net Assets and Liabilities The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year. The 10 -percent corridor accounting method is used at Sempra Energy Consolidated, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10 -percent corridor accounting methods help mitigate volatility of net periodic costs from year to year. We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in Accumulated Other Comprehensive Income (Loss) on the balance sheet. The California Utilities record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on agreements with regulatory agencies. The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their plans as authorized by the CPUC. The annual contributions to the pension plans are limited to a minimum required funding amount as determined by the IRS. The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Until the date of sale, Mobile Gas recorded annual pension and other postretirement net periodic benefit costs based on an estimate of the net periodic cost at the beginning of the year calculated in accordance with U.S. GAAP for pension and PBOP plans, as authorized by the Alabama Public Service Commission. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities. Assumptions for Pension and Other Postretirement Benefit Plans Benefit Obligation and Net Periodic Benefit Cost Except for the IEnova and Chilquinta Energía plans, we develop the discount rate assumptions based on the results of a third party modeling tool that matches each plan’s expected cash flows to interest rates and expected maturity values of individually selected bonds in a hypothetical portfolio. The model controls the level of accumulated surplus that may result from the selection of bonds based solely on their premium yields by limiting the number of years to look back for selection to 3 years for pre-30-year and 6 years for post-30-year benefit payments. Additionally, the model ensures that an adequate number of bonds are selected in the portfolio by limiting the amount of the plan’s benefit payments that can be met by a single bond to 7.5 percent. We selected individual bonds from a universe of Bloomberg AA-rated bonds that: ▪ have an outstanding issue of at least $50 million; ▪ are non-callable (or callable with make-whole provisions); ▪ exclude collateralized bonds; and ▪ exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded . This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics: ▪ The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio. ▪ Recent events have caused significant price volatility to which rating agencies have not reacted. ▪ Lack of liquidity is causing price quotes to vary significantly from broker to broker. We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP. We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. We develop the discount rate assumptions for the plans at Chilquinta Energía based on 10 -year Chilean government bond yields and the expected local long-term rate of inflation. These methods for developing the discount rate are required when there is no deep market for high quality corporate bonds. Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types. We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP. Fair Value of Pension and Other Postretirement Benefit Plan Assets We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ PBOP plans based on the fair value hierarchy, except for certain investments measured at net asset value (NAV). The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts. Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges. Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information. Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Investments in certain fixed income securities are valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks for the remaining fixed income securities. Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets. Private Equity Funds – These funds consist of investments in private equities that are held by limited partnerships following various strategies, including private equity and corporate finance. These partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. The value is determined based on the NAV of the proportionate share of an ownership interest in partners’ capital. Holdings in these types of private equity funds are negligible, as the funds are well past their expected investment term and have distributed the bulk of proceeds from investment sales. Derivative Financial Instruments – Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index future contracts are valued at the last sales price quoted on the exchange on which they primarily trade. While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis. 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 and there were no changes in the valuation techniques used.
Share-based Compensation	SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS We use a Monte-Carlo simulation model to estimate the fair value of our RSAs and our RSUs that vest based on Sempra Energy’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return, and a number of other variables. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases. We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for non-qualified stock options, RSAs and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, in the year that an employee becomes eligible for retirement, the remaining expense related to the employee’s awards is recognized immediately. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS We use a Black-Scholes option-pricing model to estimate the fair value of each non-qualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on the historical volatility of Sempra Energy’s common stock price. We base the average expected life for options on the contractual term of the option and expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected life assumed at the date of the grant.
Derivative Financial Instruments	In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales. INTEREST RATE DERIVATIVES We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy and its other subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes. We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below. In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below. In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Consolidated Statements of Cash Flows. HEDGE ACCOUNTING We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria. We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria. ENERGY DERIVATIVES Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows: ▪ The California Utilities use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas. ▪ SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. ▪ Sempra Mexico, Sempra LNG & Midstream and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its 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 Consolidated Statements of Operations. ▪ From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel and GHG allowances. FOREIGN CURRENCY DERIVATIVES We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar. We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or inflation. In addition, Sempra South American Utilities and its joint ventures use foreign currency derivatives to manage foreign currency rate risk. We discuss these derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4.
Earnings Per Share	Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 potentially dilutive impact from stock options, RSAs and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect.
Concentration of Credit Risk	CONCENTRATION OF CREDIT RISK We maintain credit policies and systems designed to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile and Peru. As they become operational, projects owned or partially owned by Sempra LNG & Midstream, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers, customers and partners to perform under long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects.
Segment Reporting	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 Diego County. ▪ SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California. ▪ Sempra South American Utilities develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru. ▪ Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3. ▪ Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S. ▪ Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In September 2016, Sempra LNG & Midstream sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express. Sempra LNG & Midstream also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015. We discuss these divestitures in Note 3. We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1. Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.

SCHEDULE I, CONDENSED FINANCI29

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT, NEW ACCOUNTING STANDARDS (Policies)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures. ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606. ASU 2015-14 defers the effective date of ASC 606 by one year for all entities and permits early adoption on a limited basis. For public entities, ASC 606 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which will result in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification has no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers will be included in our Notes to Consolidated Financial Statements beginning in the first quarter of 2018. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs ▪ Issue 3 – contingent consideration payments made after a business combination ▪ Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies) ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents. ASU 2016-15 and ASU 2016-18 must be adopted retrospectively. We early adopted ASU 2016-15 and ASU 2016-18 in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Statements of Cash Flows. Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Consolidated Statements of Cash Flows: Cash flows from operating activities: Adjustments to reconcile net income to net cash provided by $ 63 $ (1 ) $ 62 $ 66 $ — $ 66 Changes in other assets 56 (7 ) 49 (162 ) (7 ) (169 ) Net cash provided by operating activities 2,319 (8 ) 2,311 2,905 (7 ) 2,898 Cash flows from investing activities: Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired (1,582 ) 1,582 — (200 ) 200 — Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired — (1,504 ) (1,504 ) — (198 ) (198 ) Increases in restricted cash (139 ) 139 — (100 ) 100 — Decreases in restricted cash 175 (175 ) — 93 (93 ) — Other — 9 9 1 8 9 Net cash used in investing activities (4,886 ) 51 (4,835 ) (2,885 ) 17 (2,868 ) Cash flows from financing activities: Other (10 ) (11 ) (21 ) (17 ) (3 ) (20 ) Net cash provided by (used in) financing activities 2,513 (11 ) 2,502 (173 ) (3 ) (176 ) Effect of exchange rate changes on cash and cash equivalents — — — (14 ) 14 — Effect of exchange rate changes on cash, cash equivalents and restricted cash — (3 ) (3 ) — (14 ) (14 ) Decrease in cash and cash equivalents (54 ) 54 — (167 ) 167 — Decrease in cash, cash equivalents, and restricted cash — (25 ) (25 ) — (160 ) (160 ) Cash and cash equivalents, January 1 403 (403 ) — 570 (570 ) — Cash, cash equivalents and restricted cash, January 1 — 450 450 — 610 610 Cash and cash equivalents, December 31 349 (349 ) — 403 (403 ) — Cash, cash equivalents and restricted cash, December 31 — 425 425 — 450 450 SDG&E Consolidated Statements of Cash Flows: Cash flows from operating activities: Changes in other assets $ (16 ) $ (4 ) $ (20 ) $ (122 ) $ (3 ) $ (125 ) Net cash provided by operating activities 1,327 (4 ) 1,323 1,664 (3 ) 1,661 Cash flows from investing activities: Increases in restricted cash (49 ) 49 — (39 ) 39 — Decreases in restricted cash 60 (60 ) — 35 (35 ) — Other — 6 6 — 5 5 Net cash used in investing activities (1,319 ) (5 ) (1,324 ) (1,086 ) 9 (1,077 ) Cash flows from financing activities: Other (1) (4 ) (2 ) (6 ) (2 ) (2 ) (4 ) Net cash used in financing activities (20 ) (2 ) (22 ) (566 ) (2 ) (568 ) (Decrease) increase in cash and cash equivalents (12 ) 12 — 12 (12 ) — (Decrease) increase in cash, cash equivalents, and restricted cash — (23 ) (23 ) — 16 16 Cash and cash equivalents, January 1 20 (20 ) — 8 (8 ) — Cash, cash equivalents and restricted cash, January 1 — 43 43 — 27 27 Cash and cash equivalents, December 31 8 (8 ) — 20 (20 ) — Cash, cash equivalents and restricted cash, December 31 — 20 20 — 43 43 (1) Previously labeled “Debt issuance costs.” ASU 2017-01, “Clarifying the Definition of a Business”: ASU 2017-01 narrows the definition of a business and provides a framework to assist entities in determining whether a transaction involves an asset or a business. Specifically, the ASU provides a “screen” for determining when an integrated set of assets and activities (collectively referred to as a “set”) is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted. We early adopted ASU 2017-01 on July 1, 2017. ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard. ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. Entities may apply a full retrospective or modified retrospective approach. Under a modified retrospective approach, entities are required to apply the guidance to any transactions that are not completed as of the adoption date. We adopted the standard in conjunction with our adoption of ASC 606 on January 1, 2018 using the modified retrospective transition method. As we discuss in Note 1, Sempra Renewables expects the formation of a tax equity arrangement to be completed in the first half of 2018. While the arrangement would be in the scope of this ASU, we do not expect it to have a material impact on our financial condition, results of operations or cash flows. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Consolidated Statements of Operations: Operation and maintenance $ 3,117 $ 3,096 $ 2,970 $ 2,976 Other income, net 254 233 132 138 SDG&E Consolidated Statements of Operations: Operation and maintenance $ 1,020 $ 1,024 $ 1,048 $ 1,062 Operating income 713 709 990 976 Other income, net 66 70 50 64 SoCalGas Statements of Operations: Operation and maintenance $ 1,479 $ 1,474 $ 1,385 $ 1,391 Operating income 622 627 557 551 Other income, net 36 31 32 38 ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. For public entities, ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. If an entity early adopts ASU 2017-12 in an interim period, any transition adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. Entities will adopt ASU 2017-12 by applying a modified retrospective approach to the accounting for existing hedging relationships and will prospectively apply the new presentation and disclosure requirements. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018, and it will not materially affect our financial condition, results of operations or cash flows. ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard. NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures. ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows. ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs. ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses. For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues: ▪ Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below) ▪ Issue 6 – distributions received from equity method investments The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Condensed Statements of Cash Flows: Cash flows from operating activities: Net cash (used in) provided by operating activities $ (178 ) $ 175 $ (3 ) $ (255 ) $ 350 $ 95 Cash flows from investing activities: Dividends received from subsidiaries (1) 175 (175 ) — 350 (350 ) — Net cash provided by (used in) investing activities 627 (175 ) 452 (155 ) (350 ) (505 ) (1) Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow. ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Condensed Statements of Operations: Operation and maintenance $ (87 ) $ (80 ) $ (81 ) $ (76 ) Other income (expense), net 107 100 (2 ) (7 ) ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard.

SIGNIFICANT ACCOUNTING POLICI30

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Prior Period Adjustments	These reclassifications and related disclosures had no effect on our financial position as of December 31, 2016 and are intended to provide additional clarity into the financial position of Sempra Energy, SDG&E and SoCalGas. The following tables summarize the balance sheet line items affected by these reclassifications: SEMPRA ENERGY CONSOLIDATED – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Regulatory assets $ — $ 348 Greenhouse gas allowances — 40 Regulatory balancing accounts – undercollected 259 — Other 271 142 Other assets: Greenhouse gas allowances — 295 Sundry 815 520 Current liabilities: Regulatory liabilities — 122 Greenhouse gas obligations — 40 Regulatory balancing accounts – overcollected 122 — Other 557 517 Deferred credits and other liabilities: Regulatory liabilities — 2,876 Greenhouse gas obligations — 171 Regulatory liabilities arising from removal obligations 2,697 — Deferred credits and other 1,523 1,173 SDG&E – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Regulatory assets $ 81 $ 340 Greenhouse gas allowances — 16 Regulatory balancing accounts – net undercollected 259 — Other 19 3 Other assets: Regulatory assets — 2,012 Greenhouse gas allowances — 182 Deferred taxes recoverable in rates 1,014 — Other regulatory assets 998 — Sundry 358 176 Current liabilities: Greenhouse gas obligations — 16 Other 82 66 Deferred credits and other liabilities: Regulatory liabilities — 1,725 Greenhouse gas obligations — 72 Regulatory liabilities arising from removal obligations 1,725 — Deferred credits and other 421 349 SOCALGAS – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016 (Dollars in millions) As previously presented As currently presented Current assets: Greenhouse gas allowances $ — $ 24 Other 63 39 Other assets: Regulatory assets — 1,331 Greenhouse gas allowances — 109 Regulatory assets arising from pension obligations 742 — Other regulatory assets 589 — Sundry 399 290 Current liabilities: Regulatory liabilities — 122 Greenhouse gas obligations — 24 Regulatory balancing accounts – net overcollected 122 — Other 195 171 Deferred credits and other liabilities: Regulatory liabilities — 1,151 Greenhouse gas obligations — 96 Regulatory liabilities arising from removal obligations 972 — Deferred credits and other 521 246
Schedule of Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported on the Consolidated Balance Sheets to the sum of such amounts reported on the Consolidated Statements of Cash Flows. RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH (Dollars in millions) At December 31, 2017 2016 Sempra Energy Consolidated: Cash and cash equivalents $ 288 $ 349 Restricted cash, current 62 66 Restricted cash, noncurrent 14 10 Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows $ 364 $ 425 SDG&E: Cash and cash equivalents $ 12 $ 8 Restricted cash, current 6 11 Restricted cash, noncurrent 11 1 Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows $ 29 $ 20
Schedule Of Receivables Collection Allowances	We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below: COLLECTION ALLOWANCES (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Allowances for collection of receivables at January 1 $ 35 $ 32 $ 34 Provisions for uncollectible accounts 16 23 20 Write-offs of uncollectible accounts (18 ) (20 ) (22 ) Allowances for collection of receivables at December 31 $ 33 $ 35 $ 32 SDG&E: Allowances for collection of receivables at January 1 $ 8 $ 9 $ 7 Provisions for uncollectible accounts 8 6 7 Write-offs of uncollectible accounts (7 ) (7 ) (5 ) Allowances for collection of receivables at December 31 $ 9 $ 8 $ 9 SoCalGas: Allowances for collection of receivables at January 1 $ 21 $ 17 $ 17 Provisions for uncollectible accounts 4 14 11 Write-offs of uncollectible accounts (9 ) (10 ) (11 ) Allowances for collection of receivables at December 31 $ 16 $ 21 $ 17
Schedule of inventory	The components of inventories by segment are as follows: INVENTORY BALANCES AT DECEMBER 31 (Dollars in millions) Natural gas LNG Materials and supplies Total 2017 2016 2017 2016 2017 2016 2017 2016 SDG&E $ 4 $ 2 $ — $ — $ 101 $ 78 $ 105 $ 80 SoCalGas (1) 75 11 — — 49 47 124 58 Sempra South American Utilities — — — — 30 27 30 27 Sempra Mexico — — 7 6 2 1 9 7 Sempra Renewables — — — — 5 4 5 4 Sempra LNG & Midstream 30 79 4 3 — — 34 82 Sempra Energy Consolidated $ 109 $ 92 $ 11 $ 9 $ 187 $ 157 $ 307 $ 258 (1) At December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas storage facility leak, which we discuss in Note 15.
Schedule of Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY (Dollars in millions) PP&E at Depreciation rates for 2017 2016 2017 2016 2015 SDG&E: Natural gas operations $ 2,186 $ 1,897 2.40 % 2.40 % 2.52 % Electric distribution 6,975 6,497 3.92 3.86 3.79 Electric transmission (1) 5,626 5,152 2.71 2.66 2.62 Electric generation (2) 2,435 1,932 4.05 4.00 3.89 Other electric (3) 1,114 1,059 5.54 5.66 5.73 Construction work in progress (1) 1,451 1,307 NA NA NA Total SDG&E 19,787 17,844 SoCalGas: Natural gas operations (4) 15,759 14,428 3.63 3.64 3.83 Other non-utility 32 34 5.28 6.55 3.95 Construction work in progress 981 882 NA NA NA Total SoCalGas 16,772 15,344 Estimated Weighted-average Other operating units and parent (5) : useful lives useful life Land and land rights 416 381 22 to 55 years (6) 33 Machinery and equipment: Utility electric distribution operations 1,751 1,519 12 to 60 years 52 Generating plants 2,242 1,874 2 to 100 years 31 LNG terminals 1,133 1,129 43 years 43 Pipelines and storage 4,408 3,242 3 to 55 years 43 Other 269 235 1 to 50 years 13 Construction work in progress 691 1,488 NA NA Other (7) 639 568 1 to 80 years 33 11,549 10,436 Total Sempra Energy Consolidated $ 48,108 $ 43,624 (1) At December 31, 2017 , includes $440 million in electric transmission assets and $29 million in construction work in progress related to SDG&E’s 92 -percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. (2) Includes capital lease assets of $757 million and $258 million at December 31, 2017 and 2016 , respectively. (3) Includes capital lease assets of $22 million and $21 million at December 31, 2017 and 2016 , respectively. (4) Includes capital lease assets of $34 million and $32 million at December 31, 2017 and 2016 , respectively. (5) Includes $145 million and $128 million at December 31, 2017 and 2016 , respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas. (6) Estimated useful lives are for land rights. (7) Includes capital lease assets of $136 million at both December 31, 2017 and 2016 , related to a build-to-suit lease. Accumulated depreciation on our Consolidated Balance Sheets is as follows: ACCUMULATED DEPRECIATION (Dollars in millions) December 31, 2017 2016 SDG&E: Accumulated depreciation: Electric (1) $ 4,193 $ 3,873 Natural gas 756 721 Total SDG&E 4,949 4,594 SoCalGas: Accumulated depreciation of natural gas utility plant in service (2) 5,352 5,079 Accumulated depreciation – other non-utility 14 13 Total SoCalGas 5,366 5,092 Other operating units and parent and other: Accumulated depreciation – other (3) 972 755 Accumulated depreciation of utility electric distribution operations 318 252 1,290 1,007 Total Sempra Energy Consolidated $ 11,605 $ 10,693 (1) Includes accumulated depreciation for capital lease assets of $47 million and $39 million at December 31, 2017 and 2016 , respectively. Includes $241 million at December 31, 2017 related to SDG&E’s 92 -percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities. (2) Includes accumulated depreciation for capital lease assets of $33 million and $31 million at December 31, 2017 and 2016 , respectively. (3) Includes $39 million and $33 million at December 31, 2017 and 2016 , respectively, of accumulated depreciation for utility plant at Ecogas. Depreciation expense on our Consolidated Statements of Operations is as follows: DEPRECIATION EXPENSE (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 1,422 $ 1,236 $ 1,178 SDG&E 621 583 544 SoCalGas 514 474 459
Schedule Of Capitalized Financing Costs	Interest capitalized and AFUDC are as follows: CAPITALIZED FINANCING COSTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 256 $ 236 $ 201 SDG&E 85 62 51 SoCalGas 60 55 49
Schedule Of Goodwill	Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows: GOODWILL (Dollars in millions) Sempra South American Utilities Sempra Mexico Sempra LNG & Midstream Total Balance at December 31, 2015 $ 722 $ 25 $ 72 $ 819 Acquisition of businesses — 1,590 — 1,590 Sale of business — — (72 ) (72 ) Foreign currency translation (1) 27 — — 27 Balance at December 31, 2016 749 1,615 — 2,364 Acquisition of business – measurement period adjustment — (13 ) — (13 ) Foreign currency translation (1) 46 — — 46 Balance at December 31, 2017 $ 795 $ 1,602 $ — $ 2,397 (1) We record the offset of this fluctuation to Other Comprehensive Income (Loss).
Schedule Of Other Intangible Assets	Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows: OTHER INTANGIBLE ASSETS (Dollars in millions) Amortization period (years) December 31, 2017 2016 Development rights 50 $ 322 $ 322 Renewable energy transmission and consumption permit 19 154 154 Storage rights 46 138 138 O&M agreement 23 66 — Other 10 years to indefinite 18 18 698 632 Less accumulated amortization: Development rights (60 ) (53 ) Renewable energy transmission and consumption permit (8 ) — Storage rights (28 ) (25 ) Other (6 ) (6 ) (102 ) (84 ) $ 596 $ 548
Schedule Of Variable Interest Entities	The Consolidated Financial Statements of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The captions in the tables below correspond to SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations. AMOUNTS ASSOCIATED WITH OTAY MESA VIE (Dollars in millions) December 31, 2017 2016 Cash and cash equivalents $ 4 $ 6 Restricted cash 6 11 Inventories 4 3 Other 1 2 Total current assets 15 22 Restricted cash 11 1 Property, plant and equipment, net 321 354 Total assets $ 347 $ 377 Current portion of long-term debt $ 10 $ 10 Fixed-price contracts and other derivatives 10 13 Other 5 5 Total current liabilities 25 28 Long-term debt 284 293 Fixed-price contracts and other derivatives 3 12 Deferred credits and other 7 7 Noncontrolling interest 28 37 Total liabilities and equity $ 347 $ 377 Years ended December 31, 2017 2016 2015 Operating expenses Cost of electric fuel and purchased power $ (79 ) $ (79 ) $ (83 ) Operation and maintenance 17 29 19 Depreciation and amortization 28 35 26 Total operating expenses (34 ) (15 ) (38 ) Operating income 34 15 38 Other income 2 — — Interest expense (22 ) (20 ) (19 ) Income (loss) before income taxes/Net Income (loss) 14 (5 ) 19 (Earnings) losses attributable to noncontrolling interest (14 ) 5 (19 ) Earnings attributable to common shares $ — $ — $ — AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS (Dollars in millions) December 31, 2017 2016 Cash and cash equivalents $ 23 $ 88 Accounts receivable – trade, net 5 3 Inventories 1 — Other 1 — Total current assets 30 91 Sundry 2 — Property, plant and equipment, net 1,412 926 Total assets 1,444 1,017 Accounts payable 42 68 Other 1 7 Total current liabilities 43 75 Asset retirement obligations 40 27 Deferred income taxes 10 — Deferred credits and other 1 — Total deferred credits and other liabilities 94 102 Other noncontrolling interests 631 468 Net assets less other noncontrolling interests $ 719 $ 447 Years ended December 31, 2017 2016 REVENUES Energy-related businesses $ 61 $ 2 EXPENSES Operation and maintenance (9 ) (1 ) Depreciation and amortization (32 ) — Income before income taxes 20 1 Income tax expense (4 ) — Net income 16 1 Losses attributable to noncontrolling interests (1) 23 4 Earnings $ 39 $ 5 (1) Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.
Schedule Of Asset Retirement Obligations	The changes in asset retirement obligations are as follows: CHANGES IN ASSET RETIREMENT OBLIGATIONS (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas 2017 2016 2017 2016 2017 2016 Balance as of January 1 (1) $ 2,553 $ 2,255 $ 830 $ 828 $ 1,659 $ 1,383 Accretion expense 109 101 39 38 66 61 Liabilities incurred and acquired 34 35 17 — — — Deconsolidation and reclassification (2) — (16 ) — — — — Payments (63 ) (47 ) (61 ) (46 ) (2 ) — Revisions (3) 244 225 14 10 230 215 Balance at December 31 (1) $ 2,877 $ 2,553 $ 839 $ 830 $ 1,953 $ 1,659 (1) Current portions of the obligations for Sempra Energy Consolidated and SoCalGas are included in Other Current Liabilities on the Consolidated Balance Sheets. (2) Deconsolidated $12 million due to the September 2016 sale of EnergySouth and reclassified $4 million to Liabilities Held for Sale, as we discuss in Note 3. (3) In 2017, revised estimates were primarily related to underground natural gas storage facilities and wells at SoCalGas. In 2016, revised estimates were related to changes in the cost of removal rates primarily for natural gas assets based on updated cost studies approved in the 2016 GRC FD.
Schedule Of Changes In Accumulated Other Comprehensive Income By Component	The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests, for the years ended December 31: CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT (1) (Dollars in millions) Foreign currency translation adjustments Financial instruments Pension and other postretirement benefits Total accumulated other comprehensive income (loss) Sempra Energy Consolidated: Balance as of December 31, 2014 $ (322 ) $ (90 ) $ (85 ) $ (497 ) OCI before reclassifications (260 ) (57 ) (10 ) (327 ) Amounts reclassified from AOCI — 10 8 18 Net OCI (260 ) (47 ) (2 ) (309 ) Balance as of December 31, 2015 (582 ) (137 ) (87 ) (806 ) OCI before reclassifications 42 (7 ) (15 ) 20 Amounts reclassified from AOCI (2) 13 19 6 38 Net OCI 55 12 (9 ) 58 Balance as of December 31, 2016 (527 ) (125 ) (96 ) (748 ) OCI before reclassifications 107 (4 ) — 103 Amounts reclassified from AOCI — 7 12 19 Net OCI 107 3 12 122 Balance as of December 31, 2017 $ (420 ) $ (122 ) $ (84 ) $ (626 ) SDG&E: Balance as of December 31, 2014 $ (12 ) $ (12 ) OCI before reclassifications 3 3 Amounts reclassified from AOCI 1 1 Net OCI 4 4 Balance as of December 31, 2015 (8 ) (8 ) OCI before reclassifications (1 ) (1 ) Amounts reclassified from AOCI 1 1 Net OCI — — Balance as of December 31, 2016 (8 ) (8 ) OCI before reclassifications (1 ) (1 ) Amounts reclassified from AOCI 1 1 Net OCI — — Balance as of December 31, 2017 $ (8 ) $ (8 ) SoCalGas: Balance as of December 31, 2014 $ (14 ) $ (4 ) $ (18 ) OCI before reclassifications — (1 ) (1 ) Net OCI — (1 ) (1 ) Balance as of December 31, 2015 (14 ) (5 ) (19 ) OCI before reclassifications — (4 ) (4 ) Amounts reclassified from AOCI 1 — 1 Net OCI 1 (4 ) (3 ) Balance as of December 31, 2016 (13 ) (9 ) (22 ) Amounts reclassified from AOCI — 1 1 Net OCI — 1 1 Balance as of December 31, 2017 $ (13 ) $ (8 ) $ (21 ) (1) All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests. (2) Total AOCI includes $20 million associated with the October 2016 sale of noncontrolling interests, discussed below in “Sale of Noncontrolling Interests – Sempra Mexico – Follow-On Offerings,” which does not impact the Consolidated Statement of Comprehensive Income.
Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income	RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Dollars in millions) Details about accumulated other comprehensive income (loss) components Amounts reclassified from accumulated other comprehensive income (loss) Affected line item on Consolidated Statements of Operations Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Financial instruments: Interest rate and foreign exchange instruments (1) $ (4 ) $ 17 $ 18 Interest Expense Interest rate instruments 8 10 12 Equity Earnings, Before Income Tax Interest rate and foreign exchange instruments — 7 — Remeasurement of Equity Method Investment Interest rate and foreign exchange instruments 12 5 13 Equity Earnings, Net of Income Tax Foreign exchange instruments (2 ) — — Revenues: Energy-Related Businesses Commodity contracts not subject to rate recovery 9 (6 ) (14 ) Revenues: Energy-Related Businesses Total before income tax 23 33 29 (6 ) (6 ) (4 ) Income Tax Expense Net of income tax 17 27 25 (10 ) (15 ) (15 ) Earnings Attributable to Noncontrolling Interests $ 7 $ 12 $ 10 Pension and other postretirement benefits: Amortization of actuarial loss (2) $ 18 $ 10 $ 14 Amortization of prior service cost (2) 1 1 — Total before income tax 19 11 14 (7 ) (5 ) (6 ) Income Tax Expense Net of income tax $ 12 $ 6 $ 8 Total reclassifications for the period, net of tax $ 19 $ 18 $ 18 SDG&E: Financial instruments: Interest rate instruments (1) $ 13 $ 12 $ 12 Interest Expense (13 ) (12 ) (12 ) (Earnings) Losses Attributable to Noncontrolling Interest $ — $ — $ — Pension and other postretirement benefits: Amortization of actuarial loss (2) $ 1 $ 1 $ 1 Total reclassifications for the period, net of tax $ 1 $ 1 $ 1 SoCalGas: Financial instruments: Interest rate instruments $ — $ 1 $ 1 Interest Expense — — (1 ) Income Tax Expense Net of income tax $ — $ 1 $ — Pension and other postretirement benefits: Amortization of prior service cost (2) $ 1 $ — $ — Total reclassifications for the period, net of tax $ 1 $ 1 $ — (1) Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. (2) Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).
Schedule Of Noncontrolling Interests	At December 31, 2017 and 2016 , we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Consolidated Balance Sheets: OTHER NONCONTROLLING INTERESTS (Dollars in millions) Percent ownership held by others Equity held by noncontrolling interests December 31, December 31, 2017 2016 2017 2016 SDG&E: Otay Mesa VIE 100 % 100 % $ 28 $ 37 Sempra South American Utilities: Chilquinta Energía subsidiaries (1) 22.9 - 43.4 23.1 - 43.4 24 22 Luz del Sur 16.4 16.4 189 173 Tecsur 9.8 9.8 4 4 Sempra Mexico: IEnova (2) 33.6 33.6 1,532 1,524 Sempra Renewables: Tax equity arrangements – wind (3) NA NA 181 92 Tax equity arrangements – solar (3) NA NA 450 376 Sempra LNG & Midstream: Bay Gas 9.1 9.1 28 27 Liberty Gas Storage, LLC 23.3 23.3 14 14 Southern Gas Transmission Company (4) — 49.0 — 1 Total Sempra Energy $ 2,450 $ 2,270 (1) Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries. (2) IEnova has a subsidiary with a 10-percent noncontrolling interest held by others. The equity held by noncontrolling interests is negligible at December 31, 2017 and 2016. (3) Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages. (4) We sold our assets in Southern Gas Transmission Company in August 2017.
Schedule Of Utilities Revenues	The table below shows the total utilities revenues in Sempra Energy’s Consolidated Statements of Operations for each of the last three years. The revenues include amounts for services rendered but unbilled (approximately one-half month’s deliveries) at the end of each year. TOTAL UTILITIES REVENUES AT SEMPRA ENERGY CONSOLIDATED (1) (Dollars in millions) Years ended December 31, 2017 2016 2015 Electric revenues $ 5,415 $ 5,211 $ 5,158 Natural gas revenues 4,361 4,050 4,096 Total $ 9,776 $ 9,261 $ 9,254 (1) Excludes intercompany revenues.
Schedule of Related Party Transactions	Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows: AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES (Dollars in millions) December 31, 2017 2016 Sempra Energy Consolidated: Total due from various unconsolidated affiliates – current $ 37 $ 26 Sempra South American Utilities (1) : Eletrans – 4% Note (2) $ 103 $ 96 Other related party receivables 1 1 Sempra Mexico (1) : IMG – Note due March 15, 2022 (3) 487 — DEN – Notes due November 14, 2018 (4) — 90 Energía Sierra Juárez – Note (5) 7 14 Total due from unconsolidated affiliates – noncurrent $ 598 $ 201 Total due to various unconsolidated affiliates – current $ (7 ) $ (11 ) Sempra Mexico (1) : Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021 (6) $ (35 ) $ — SDG&E: Sempra Energy (7) $ — $ 3 Various affiliates — 1 Total due from unconsolidated affiliates – current $ — $ 4 Sempra Energy $ (30 ) $ — SoCalGas (4 ) (8 ) Various affiliates (6 ) (7 ) Total due to unconsolidated affiliates – current $ (40 ) $ (15 ) Income taxes due from Sempra Energy (8) $ 27 $ 159 SoCalGas: Total due from unconsolidated affiliates – current – SDG&E $ 4 $ 8 Total due to unconsolidated affiliates – current – Sempra Energy $ (35 ) $ (28 ) Income taxes due from Sempra Energy (8) $ 10 $ 5 (1) Amounts include principal balances plus accumulated interest outstanding. (2) U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, comprising joint ventures of Chilquinta Energía. (3) Mexican peso-denominated revolving line of credit for up to $14.0 billion Mexican pesos or approximately $718 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps ( 9.87 percent at December 31, 2017 ), to finance construction of the natural gas marine pipeline. (4) Four U.S. dollar-denominated loans, at a variable interest rate based on the 30-day LIBOR plus 450 bps ( 5.27 percent at December 31, 2016 ), to finance the Los Ramones Norte pipeline project. In November 2017, IEnova acquired the remaining 50 -percent interest in DEN and DEN became a wholly owned, consolidated subsidiary of IEnova. (5) U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps ( 7.94 percent at December 31, 2017 ) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova. (6) U.S. dollar-denominated loan, at a variable interest rate based on 6-month LIBOR plus 290 bps ( 4.74 percent at December 31, 2017 ). (7) At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent. (8) SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return. Revenues and cost of sales from unconsolidated affiliates are as follows: REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES (Dollars in millions) Years ended December 31, 2017 2016 2015 Revenues: Sempra Energy Consolidated $ 43 $ 25 $ 26 SDG&E 8 7 10 SoCalGas 74 76 75 Cost of Sales: Sempra Energy Consolidated $ 47 $ 72 $ 107 SDG&E 71 64 49
Schedule Of Other Income (Expense)	Other Income, Net on the Consolidated Statements of Operations consists of the following: OTHER INCOME, NET (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Allowance for equity funds used during construction $ 168 $ 116 $ 107 Investment gains (1) 56 23 3 Gains (losses) on interest rate and foreign exchange instruments, net 47 (32 ) (4 ) Foreign currency transaction losses (2) (35 ) (1 ) (7 ) Sale of other investments 3 5 11 Electrical infrastructure relocation income 3 10 7 Interest on regulatory balancing accounts, net 3 4 3 Sundry, net 9 7 6 Total $ 254 $ 132 $ 126 SDG&E: Allowance for equity funds used during construction $ 63 $ 46 $ 37 Interest on regulatory balancing accounts, net 3 3 3 Sundry, net — 1 (4 ) Total $ 66 $ 50 $ 36 SoCalGas: Allowance for equity funds used during construction $ 44 $ 40 $ 36 Interest on regulatory balancing accounts, net — 1 — Sundry, net (8 ) (9 ) (6 ) Total $ 36 $ 32 $ 30 (1) Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Consolidated Statements of Operations. (2) Includes $35 million loss from translation of Mexican peso-denominated loan to IMG JV to U.S. dollars.

NEW ACCOUNTING STANDARDS NEW AC

NEW ACCOUNTING STANDARDS NEW ACCOUNTING STANDARDS (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncement, Early Adoption	Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Consolidated Statements of Cash Flows: Cash flows from operating activities: Adjustments to reconcile net income to net cash provided by $ 63 $ (1 ) $ 62 $ 66 $ — $ 66 Changes in other assets 56 (7 ) 49 (162 ) (7 ) (169 ) Net cash provided by operating activities 2,319 (8 ) 2,311 2,905 (7 ) 2,898 Cash flows from investing activities: Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired (1,582 ) 1,582 — (200 ) 200 — Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired — (1,504 ) (1,504 ) — (198 ) (198 ) Increases in restricted cash (139 ) 139 — (100 ) 100 — Decreases in restricted cash 175 (175 ) — 93 (93 ) — Other — 9 9 1 8 9 Net cash used in investing activities (4,886 ) 51 (4,835 ) (2,885 ) 17 (2,868 ) Cash flows from financing activities: Other (10 ) (11 ) (21 ) (17 ) (3 ) (20 ) Net cash provided by (used in) financing activities 2,513 (11 ) 2,502 (173 ) (3 ) (176 ) Effect of exchange rate changes on cash and cash equivalents — — — (14 ) 14 — Effect of exchange rate changes on cash, cash equivalents and restricted cash — (3 ) (3 ) — (14 ) (14 ) Decrease in cash and cash equivalents (54 ) 54 — (167 ) 167 — Decrease in cash, cash equivalents, and restricted cash — (25 ) (25 ) — (160 ) (160 ) Cash and cash equivalents, January 1 403 (403 ) — 570 (570 ) — Cash, cash equivalents and restricted cash, January 1 — 450 450 — 610 610 Cash and cash equivalents, December 31 349 (349 ) — 403 (403 ) — Cash, cash equivalents and restricted cash, December 31 — 425 425 — 450 450 SDG&E Consolidated Statements of Cash Flows: Cash flows from operating activities: Changes in other assets $ (16 ) $ (4 ) $ (20 ) $ (122 ) $ (3 ) $ (125 ) Net cash provided by operating activities 1,327 (4 ) 1,323 1,664 (3 ) 1,661 Cash flows from investing activities: Increases in restricted cash (49 ) 49 — (39 ) 39 — Decreases in restricted cash 60 (60 ) — 35 (35 ) — Other — 6 6 — 5 5 Net cash used in investing activities (1,319 ) (5 ) (1,324 ) (1,086 ) 9 (1,077 ) Cash flows from financing activities: Other (1) (4 ) (2 ) (6 ) (2 ) (2 ) (4 ) Net cash used in financing activities (20 ) (2 ) (22 ) (566 ) (2 ) (568 ) (Decrease) increase in cash and cash equivalents (12 ) 12 — 12 (12 ) — (Decrease) increase in cash, cash equivalents, and restricted cash — (23 ) (23 ) — 16 16 Cash and cash equivalents, January 1 20 (20 ) — 8 (8 ) — Cash, cash equivalents and restricted cash, January 1 — 43 43 — 27 27 Cash and cash equivalents, December 31 8 (8 ) — 20 (20 ) — Cash, cash equivalents and restricted cash, December 31 — 20 20 — 43 43 (1) Previously labeled “Debt issuance costs.”
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Consolidated Statements of Operations: Operation and maintenance $ 3,117 $ 3,096 $ 2,970 $ 2,976 Other income, net 254 233 132 138 SDG&E Consolidated Statements of Operations: Operation and maintenance $ 1,020 $ 1,024 $ 1,048 $ 1,062 Operating income 713 709 990 976 Other income, net 66 70 50 64 SoCalGas Statements of Operations: Operation and maintenance $ 1,479 $ 1,474 $ 1,385 $ 1,391 Operating income 622 627 557 551 Other income, net 36 31 32 38 The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Condensed Statements of Cash Flows: Cash flows from operating activities: Net cash (used in) provided by operating activities $ (178 ) $ 175 $ (3 ) $ (255 ) $ 350 $ 95 Cash flows from investing activities: Dividends received from subsidiaries (1) 175 (175 ) — 350 (350 ) — Net cash provided by (used in) investing activities 627 (175 ) 452 (155 ) (350 ) (505 ) (1) Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Condensed Statements of Operations: Operation and maintenance $ (87 ) $ (80 ) $ (81 ) $ (76 ) Other income (expense), net 107 100 (2 ) (7 )

ACQUISTION AND DIVESTITURE AC32

ACQUISTION AND DIVESTITURE ACTIVITY (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Business Acquisitions Table	The following table summarizes the total fair value of the 2016 business combinations at Sempra Mexico, described below, and the final purchase price allocations of the assets acquired and liabilities assumed at the dates of acquisition: PURCHASE PRICE ALLOCATIONS (Dollars in millions) IEnova Pipelines Ventika At September 26, 2016 (1) At December 14, 2016 (2) Fair value of business combination: Cash consideration (fair value of total consideration) $ 1,144 $ 310 Fair value of equity interest in IEnova Pipelines immediately prior to acquisition 1,144 — Total fair value of business combination $ 2,288 $ 310 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 66 $ — Restricted cash — 68 Accounts receivable 39 14 Other current assets 6 1 Other intangible assets — 154 Deferred income taxes — 36 Regulatory assets 33 — Property, plant and equipment 1,248 673 Other noncurrent assets 1 3 Short-term debt — (125 ) Accounts payable (11 ) (1 ) Due to unconsolidated affiliates (3 ) — Current portion of long-term debt (49 ) (7 ) Fixed-price contracts and other derivatives, current (6 ) (4 ) Other current liabilities (20 ) (8 ) Long-term debt (315 ) (478 ) Asset retirement obligations (5 ) (2 ) Deferred income taxes (127 ) (120 ) Fixed-price contracts and other derivatives, noncurrent (19 ) (10 ) Other noncurrent liabilities (11 ) — Total identifiable net assets 827 194 Goodwill 1,461 116 Total fair value of business combination $ 2,288 $ 310 (1) During the fourth quarter of 2016, we received additional information regarding IEnova Pipelines’ deferred income taxes as of the acquisition date, primarily related to basis differences in IEnova Pipelines’ PP&E. As a result, we recorded measurement period adjustments that resulted in a net increase to goodwill of $86 million , an increase in deferred income tax liabilities of $119 million and $33 million of regulatory assets related to deferred income taxes on AFUDC. (2) During the fourth quarter of 2017, we received additional information regarding Ventika’s deferred income taxes as of the acquisition date, primarily related to net operating loss carryforwards. As a result, we recorded a measurement period adjustment that resulted in a decrease to goodwill and an increase in deferred income tax assets of $13 million .
Schedule of Proforma Information Table	The following table presents unaudited pro forma information for the years ended December 31, 2016 and 2015, combining the historical results of operations of Sempra Energy, IEnova Pipelines and Ventika as though the acquisitions occurred on January 1, 2015. The pro forma information is not necessarily indicative of results that would have been achieved had the businesses been combined during the periods presented or the results that we will experience going forward. UNAUDITED PRO FORMA INFORMATION – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Years ended December 31, 2016 2015 Revenues $ 10,463 $ 10,473 Net income 1,145 1,938 Earnings 1,058 1,641
Schedule Of Assets Held for Sale and Deconsolidation of Subsidiaries Table	At December 31, 2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows: ASSETS HELD FOR SALE AT DECEMBER 31, 2017 (Dollars in millions) TdM Inventories $ 10 Other current assets 59 Property, plant and equipment, net 56 Other noncurrent assets 2 Total assets held for sale $ 127 Accounts payable $ 5 Other current liabilities 38 Asset retirement obligations 5 Other noncurrent liabilities 1 Total liabilities held for sale $ 49

INVESTMENTS IN UNCONSOLIDATED33

INVESTMENTS IN UNCONSOLIDATED ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
Schedule Of Equity Method And Other Investments	We provide the carrying value of our investments and earnings (losses) on these investments below: EQUITY METHOD AND OTHER INVESTMENT BALANCES (Dollars in millions) December 31, 2017 2016 Sempra South American Utilities: Eletrans (1) $ 16 $ (8 ) Sempra Mexico: DEN — 42 Energía Sierra Juárez (2) 39 38 IMG (3) 221 100 TAG (4) 364 — Sempra Renewables: Wind: Auwahi Wind 42 41 Broken Bow 2 Wind 32 35 Cedar Creek 2 Wind 72 75 Flat Ridge 2 Wind 255 271 Fowler Ridge 2 Wind 44 43 Mehoopany Wind 89 92 Solar: California solar partnership 107 113 Copper Mountain Solar 2 35 33 Copper Mountain Solar 3 44 42 Mesquite Solar 1 81 86 Other 12 13 Sempra LNG & Midstream: Cameron LNG JV (5) 997 997 Parent and other: RBS Sempra Commodities 67 67 Total equity method investments 2,517 2,080 Other 10 17 Total $ 2,527 $ 2,097 (1) Reflects losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the CLF relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018. (2) The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014. (3) The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees, which we discuss below. (4) The carrying value of our equity method investment is $ 130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill. (5) The carrying value of our equity method investment is $237 million and $190 million higher than the underlying equity in the net assets of the investee at December 31, 2017 and 2016 , respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations. EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Earnings (losses) recorded before income tax: Sempra Renewables: Wind: Auwahi Wind $ 5 $ 4 $ 4 Broken Bow 2 Wind (2 ) (2 ) (2 ) Cedar Creek 2 Wind (2 ) (2 ) (6 ) Flat Ridge 2 Wind (13 ) (7 ) (12 ) Fowler Ridge 2 Wind 4 4 4 Mehoopany Wind (1 ) — (1 ) Solar: California solar partnership 7 7 6 Copper Mountain Solar 2 5 6 7 Copper Mountain Solar 3 8 8 8 Mesquite Solar 1 18 17 16 Other — (1 ) — Sempra LNG & Midstream: Cameron LNG JV 5 (2 ) 5 Rockies Express Pipeline — (26 ) 79 Parent and other: RBS Sempra Commodities — — (4 ) $ 34 $ 6 $ 104 Earnings (losses) recorded net of income tax (1) : Sempra South American Utilities: Eletrans $ 4 $ 3 $ (4 ) Sempra Mexico: DEN (13 ) 5 — Energía Sierra Juárez — 6 6 IEnova Pipelines — 64 83 IMG 45 — — TAG 6 — — $ 42 $ 78 $ 85 (1) As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our ETR .
Schedule of Summarized Financial Information	We present summarized financial information below, aggregated for all of our equity method investments for the periods in which we were invested in the entity. The amounts below represent the aggregate financial position and results of operations of 100 percent of each of Sempra Energy’s equity method investments. SUMMARIZED FINANCIAL INFORMATION (Dollars in millions) Years ended December 31, 2017 (1) 2016 (2) 2015 Gross revenues $ 846 $ 1,079 $ 1,533 Operating expense (590 ) (726 ) (845 ) Income from operations 256 353 688 Interest expense (217 ) (127 ) (312 ) Net income/Earnings (3) 116 252 440 At December 31, 2017 (1) 2016 (2) Current assets $ 974 $ 704 Noncurrent assets 14,087 9,970 Current liabilities 797 629 Noncurrent liabilities 9,809 6,627 (1) On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50 -percent interest in DEN, increasing its ownership percentage to 100 percent . At December 31, 2017, DEN is no longer an equity method investment. (2) On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50 -percent interest in IEnova Pipelines, increasing its ownership percentage to 100 percent , and on May 9, 2016, Sempra LNG & Midstream sold its 25 -percent interest in Rockies Express. At December 31, 2016, IEnova Pipelines and Rockies Express are no longer equity method investments. (3) Except for our investments in South America and Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

DEBT AND CREDIT FACILITIES (Tab

DEBT AND CREDIT FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities	PRIMARY U.S. COMMITTED LINES OF CREDIT (Dollars in millions) At December 31, 2017 Total facility Commercial paper outstanding (1) Available unused credit Sempra Energy (2) $ 1,000 $ — $ 1,000 Sempra Global (3) 2,335 (931 ) 1,404 California Utilities (4) : SDG&E 750 (253 ) 497 SoCalGas 750 (116 ) 634 Less: subject to a combined limit of $1 billion for both utilities (500 ) — (500 ) 1,000 (369 ) 631 Total $ 4,335 $ (1,300 ) $ 3,035 (1) Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit. (2) The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017. (3) Sempra Energy guarantees Sempra Global’s obligations under the credit facility. (4) The facility also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017. CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO (U.S. dollar equivalent in millions) At December 31, 2017 Denominated in Total facility Amount Available unused credit Sempra South American Utilities (1) : Peru (2) Peruvian sol $ 465 $ (169 ) (3) $ 296 Chile Chilean peso 115 — 115 Sempra Mexico: IEnova (4) U.S. dollar 1,170 (137 ) 1,033 Total $ 1,750 $ (306 ) $ 1,444 (1) The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021. (2) The Peruvian facilities require a debt to equity ratio of no more than 170 percent , with which we were in compliance at December 31, 2017. (3) Includes bank guarantees of $18 million . (4) Five-year revolver expiring in August 2020 with a syndicate of eight lenders.
Schedule Of Long-term Debt	The following tables show the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 SDG&E First mortgage bonds (collateralized by plant assets): Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017 $ — $ 140 1.65% July 1, 2018 (1) 161 161 3% August 15, 2021 350 350 1.914% payable 2015 through February 2022 161 197 3.6% September 1, 2023 450 450 2.5% May 15, 2026 500 500 6% June 1, 2026 250 250 5.875% January and February 2034 (1) 176 176 5.35% May 15, 2035 250 250 6.125% September 15, 2037 250 250 4% May 1, 2039 (1) 75 75 6% June 1, 2039 300 300 5.35% May 15, 2040 250 250 4.5% August 15, 2040 500 500 3.95% November 15, 2041 250 250 4.3% April 1, 2042 250 250 3.75% June 1, 2047 400 — 4,573 4,349 Other long-term debt: OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007), payable 2013 through April 2019 (collateralized by OMEC plant assets) 295 305 Capital lease obligations: Purchased-power contracts 731 239 Other 1 1 1,027 545 5,600 4,894 Current portion of long-term debt (220 ) (191 ) Unamortized discount on long-term debt (11 ) (11 ) Unamortized debt issuance costs (34 ) (34 ) Total SDG&E 5,335 4,658 SoCalGas First mortgage bonds (collateralized by plant assets): 5.45% April 15, 2018 250 250 1.55% June 15, 2018 250 250 3.15% September 15, 2024 500 500 3.2% June 15, 2025 350 350 2.6% June 15, 2026 500 500 5.75% November 15, 2035 250 250 5.125% November 15, 2040 300 300 3.75% September 15, 2042 350 350 4.45% March 15, 2044 250 250 3,000 3,000 Other long-term debt (uncollateralized): 1.875% Notes payable 2016 through May 2026 (1) 4 4 5.67% Notes January 18, 2028 5 5 Capital lease obligations 1 — 10 9 3,010 3,009 Current portion of long-term debt (501 ) — Unamortized discount on long-term debt (7 ) (7 ) Unamortized debt issuance costs (17 ) (20 ) Total SoCalGas 2,485 2,982 LONG-TERM DEBT (CONTINUED) (Dollars in millions) December 31, 2017 2016 Sempra Energy Other long-term debt (uncollateralized): 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease (2) 138 137 Sempra South American Utilities Other long-term debt (uncollateralized): Chilquinta Energía – 4.25% Series B Bonds October 30, 2030 205 185 Luz del Sur Bank loans 5.18% to 6.7% payable 2016 through December 2018 53 75 Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029 415 346 Other bonds at 3.77% to 4.61% payable 2020 through May 2022 6 7 Capital lease obligations 6 6 Sempra Mexico Other long-term debt (uncollateralized unless otherwise noted): Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency swaps effective 2013) 66 63 6.3% Notes February 2, 2023 (4.12% after cross-currency swap) 198 189 Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014), payable 2016 through December 2026, collateralized by plant assets 314 352 3.75% Notes January 14, 2028 300 — Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates (weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets 468 481 4.875% Notes January 14, 2048 540 — Sempra Renewables Other long-term debt (collateralized by project assets): Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028 except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012 (1) 77 84 Sempra LNG & Midstream Other long-term debt (uncollateralized unless otherwise noted): Notes at 2.87% to 3.51% October 1, 2026 (1) 20 20 8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee — 6 9,405 7,548 Current portion of long-term debt (706 ) (722 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized premium on long-term debt 4 4 Unamortized debt issuance costs (65 ) (31 ) Total other Sempra Energy 8,625 6,789 Total Sempra Energy Consolidated $ 16,445 $ 14,429 (1) Callable long-term debt not subject to make-whole provisions. (2) We discuss this lease in Note 15. On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses): NOTES ISSUED IN LONG-TERM DEBT OFFERING (Dollars in millions) Title of each class of securities Aggregate principal amount Maturity Interest payments Floating Rate (1) Notes due 2019 $ 500 July 15, 2019 Quarterly Floating Rate (2) Notes due 2021 700 January 15, 2021 Quarterly 2.400% Senior Notes due 2020 500 February 1, 2020 Semi-annually 2.900% Senior Notes due 2023 500 February 1, 2023 Semi-annually 3.400% Senior Notes due 2028 1,000 February 1, 2028 Semi-annually 3.800% Senior Notes due 2038 1,000 February 1, 2038 Semi-annually 4.000% Senior Notes due 2048 800 February 1, 2048 Semi-annually (1) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points. (2) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points. The following table shows the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease 138 137 6,737 5,734 Current portion of long-term debt (500 ) (600 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized debt issuance costs (26 ) (24 ) Total long-term debt $ 6,198 $ 5,100
Schedule of Maturities of Long-term Debt	MATURITIES OF LONG-TERM DEBT (1) (Dollars in millions) SDG&E SoCalGas Other Sempra Energy Total Sempra Energy Consolidated 2018 $ 207 $ 500 $ 705 $ 1,412 2019 321 — 1,098 1,419 2020 36 — 997 1,033 2021 385 — 961 1,346 2022 18 — 629 647 Thereafter 3,901 2,509 4,872 11,282 Total $ 4,868 $ 3,009 $ 9,262 $ 17,139 (1) Excludes capital lease obligations, build-to-suit lease, market value adjustments for interest rate swaps, discounts, premiums and debt issuance costs.
Schedule Of Callable Long Term Debt	At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2017 is callable subject to premiums: CALLABLE LONG-TERM DEBT (Dollars in millions) SDG&E SoCalGas Other Total Not subject to make-whole provisions $ 412 $ 4 $ 97 $ 513 Subject to make-whole provisions 4,161 3,005 7,058 14,224

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	Reconciliation of net U.S. statutory federal income tax rates to the ETRs is as follows: RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: U.S. federal statutory income tax rate 35 % 35 % 35 % Effects of the TCJA 55 — — Utility depreciation 6 4 5 Foreign exchange and inflation effects (1) 3 (2 ) (2 ) State income taxes, net of federal income tax benefit 1 1 1 Utility repairs expenditures (6 ) (4 ) (5 ) Tax credits (4 ) (3 ) (4 ) Self-developed software expenditures (4 ) (3 ) (3 ) Non-U.S. earnings taxed at lower statutory income tax rates (2) (3 ) (3 ) (2 ) Allowance for equity funds used during construction (3 ) (2 ) (2 ) Resolution of prior years’ income tax items (2 ) — (3 ) Share-based compensation — (2 ) — Other, net 3 — — Effective income tax rate 81 % 21 % 20 % SDG&E: U.S. federal statutory income tax rate 35 % 35 % 35 % Depreciation 7 5 4 Effects of the TCJA 5 — — State income taxes, net of federal income tax benefit 3 5 5 Repairs expenditures (8 ) (4 ) (4 ) Self-developed software expenditures (6 ) (3 ) (3 ) Allowance for equity funds used during construction (4 ) (2 ) (2 ) Resolution of prior years’ income tax items (4 ) (1 ) (2 ) Share-based compensation — (1 ) — Other, net (1 ) (1 ) (1 ) Effective income tax rate 27 % 33 % 32 % SoCalGas: U.S. federal statutory income tax rate 35 % 35 % 35 % Depreciation 9 9 8 State income taxes, net of federal income tax benefit 3 2 4 Repairs expenditures (8 ) (9 ) (10 ) Self-developed software expenditures (5 ) (6 ) (6 ) Allowance for equity funds used during construction (3 ) (2 ) (2 ) Resolution of prior years’ income tax items (2 ) 2 (3 ) Share-based compensation — (1 ) — Other, net — (1 ) (1 ) Effective income tax rate 29 % 29 % 25 % (1) Primarily due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of significant appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova. (2) Related to operations in Mexico, Chile and Peru.
Schedule of Impact of Changes in Legislation	EFFECTS OF THE TAX CUTS AND JOBS ACT OF 2017 (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas Consolidated Balance Sheets: Decrease in net deferred income tax liabilities due to remeasurement $ (2,220 ) $ (1,400 ) $ (972 ) Increase in net regulatory liabilities from remeasurement of deferred income tax assets and liabilities $ 2,402 $ 1,428 $ 974 Consolidated Statements of Operations: Income tax expense related to remeasurement of deferred income tax assets and liabilities $ 182 $ 28 $ 2 Income tax expense related to deemed repatriation 328 — — U.S. state and non-U.S. withholding tax expense related to expected future repatriation of foreign earnings 360 — — Total increase in income tax expense $ 870 $ 28 $ 2
Schedule Of Geographic Components Of Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries	The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy Consolidated are as follows: GEOGRAPHIC COMPONENTS (Dollars in millions) Pretax book income Years ended December 31, 2017 2016 2015 U.S. $ 878 $ 773 $ 1,189 Non-U.S. 707 1,057 515 Total $ 1,585 $ 1,830 $ 1,704 U.S. pretax book income decreased in 2016 compared to 2015 at the California Utilities primarily due to the reallocation of 2012-2015 income tax benefits generated from income tax repairs deductions to ratepayers pursuant to the 2016 GRC FD, as we discuss in Note 14; at Sempra LNG & Midstream for the loss on permanent release of pipeline capacity, as we discuss in Note 15; and the impairment charge related to the investment in Rockies Express, as we discuss in Note 3. U.S. pretax income remained lower in 2017 due to the write-off of SDG&E’s wildfire regulatory asset, as we discuss in Note 15. Non-U.S. pretax book income was lower in 2017 and 2015 compared to 2016 primarily due to the noncash gain in 2016 associated with the remeasurement of our equity interest in IEnova Pipelines, as we discuss in Note 3.
Schedule Of Components Of Income Tax Expense	The components of income tax expense are as follows: INCOME TAX EXPENSE (BENEFIT) (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Current: U.S. federal $ — $ — $ 3 U.S. state — 1 (24 ) Non-U.S. 116 171 123 Total 116 172 102 Deferred: U.S. federal 536 78 242 U.S. state 297 9 34 Non-U.S. 327 135 (32 ) Total 1,160 222 244 Deferred investment tax credits — (5 ) (5 ) Total income tax expense $ 1,276 $ 389 $ 341 SDG&E: Current: U.S. federal $ 100 $ — $ 12 U.S. state 65 22 77 Total 165 22 89 Deferred: U.S. federal 29 223 233 U.S. state (41 ) 38 (35 ) Total (12 ) 261 198 Deferred investment tax credits 2 (3 ) (3 ) Total income tax expense $ 155 $ 280 $ 284 SoCalGas: Current: U.S. federal $ — $ — $ (1 ) U.S. state 23 40 12 Total 23 40 11 Deferred: U.S. federal 144 123 122 U.S. state (5 ) (18 ) 7 Total 139 105 129 Deferred investment tax credits (2 ) (2 ) (2 ) Total income tax expense $ 160 $ 143 $ 138
Schedule Of Components Of Deferred Tax Assets And Liabilities	We show the components of deferred income taxes, which reflect the effects of the TCJA, at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below: DEFERRED INCOME TAXES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) December 31, 2017 2016 Deferred income tax liabilities: Differences in financial and tax bases of fixed assets, investments and other assets (1) $ 4,233 $ 6,111 U.S. state and non-U.S. withholding tax on repatriation of foreign earnings 360 — Regulatory balancing accounts 376 783 Property taxes 37 63 Other deferred income tax liabilities 117 143 Total deferred income tax liabilities 5,123 7,100 Deferred income tax assets: Tax credits 1,066 431 Net operating losses 968 2,304 Compensation-related items 199 252 Postretirement benefits 251 434 Other deferred income tax assets 115 87 Accrued expenses not yet deductible 60 112 Deferred income tax assets before valuation allowances 2,659 3,620 Less: valuation allowances 133 31 Total deferred income tax assets 2,526 3,589 Net deferred income tax liability (2) $ 2,597 $ 3,511 (1) In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries. (2) At December 31, 2017 and 2016, includes $170 million and $234 million , respectively, recorded as a noncurrent asset and $2,767 million and $3,745 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets. DEFERRED INCOME TAXES – SDG&E AND SOCALGAS (Dollars in millions) SDG&E SoCalGas December 31, December 31, 2017 2016 2017 2016 Deferred income tax liabilities: Differences in financial and tax bases of utility plant and other assets $ 1,472 $ 2,549 $ 987 $ 1,699 Regulatory balancing accounts 113 379 271 411 Property taxes 26 42 12 21 Other 10 10 1 4 Total deferred income tax liabilities 1,621 2,980 1,271 2,135 Deferred income tax assets: Net operating losses — — 58 83 Tax credits 7 27 15 17 Postretirement benefits 43 98 152 244 Compensation-related items 5 8 25 32 State income taxes 14 — 7 19 Accrued expenses not yet deductible 3 7 12 20 Other 19 11 7 11 Total deferred income tax assets 91 151 276 426 Net deferred income tax liability $ 1,530 $ 2,829 $ 995 $ 1,709
Summary of Tax Credit Carryforwards	The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017. NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS (Dollars in millions) Unused amount at December 31, 2017 Year expiration begins Sempra Energy Consolidated: U.S. federal: NOLs (1) $ 3,145 2031 General business tax credits (1) 389 2032 Foreign tax credits (2) 631 2024 U.S. state (2) : NOLs 2,295 2019 General business tax credits 51 2018 Non-U.S. (2) NOLs 607 2018 SoCalGas: U.S. federal (1) : NOLs $ 334 2032 General business tax credits 12 2031 (1) We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis. (2) We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.
Summary of Operating Loss Carryforwards	The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017. NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS (Dollars in millions) Unused amount at December 31, 2017 Year expiration begins Sempra Energy Consolidated: U.S. federal: NOLs (1) $ 3,145 2031 General business tax credits (1) 389 2032 Foreign tax credits (2) 631 2024 U.S. state (2) : NOLs 2,295 2019 General business tax credits 51 2018 Non-U.S. (2) NOLs 607 2018 SoCalGas: U.S. federal (1) : NOLs $ 334 2032 General business tax credits 12 2031 (1) We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis. (2) We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.
Summary of Income Tax Contingencies	Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31: RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS (Dollars in millions) 2017 2016 2015 Sempra Energy Consolidated: Balance at January 1 $ 90 $ 87 $ 117 Increase in prior period tax positions 22 2 10 Decrease in prior period tax positions (15 ) (2 ) — Increase in current period tax positions 4 6 8 Settlements with taxing authorities (12 ) (3 ) (48 ) Balance at December 31 $ 89 $ 90 $ 87 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (77 ) $ (87 ) $ (83 ) increase the effective tax rate (1) 20 36 32 SDG&E: Balance at January 1 $ 22 $ 20 $ 14 Increase in prior period tax positions 9 — 5 Decrease in prior period tax positions (11 ) — — Increase in current period tax positions — 2 2 Settlements with taxing authorities (10 ) — (1 ) Balance at December 31 $ 10 $ 22 $ 20 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (7 ) $ (19 ) $ (16 ) increase the effective tax rate (1) 1 13 11 SoCalGas: Balance at January 1 $ 29 $ 27 $ 19 Increase in prior period tax positions 3 — 2 Decrease in prior period tax positions — (2 ) — Increase in current period tax positions 4 4 6 Settlements with taxing authorities (1 ) — — Balance at December 31 $ 35 $ 29 $ 27 Of December 31 balance, amounts related to tax positions that if recognized in future years would decrease the effective tax rate (1) $ (26 ) $ (29 ) $ (27 ) increase the effective tax rate (1) 20 24 21 (1) Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.
Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible	It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following: POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS (Dollars in millions) At December 31, 2017 2016 2015 Sempra Energy Consolidated: Expiration of statutes of limitations on tax assessments $ — $ (2 ) $ (2 ) Potential resolution of audit issues with various U.S. federal, state and local and non-U.S. taxing authorities (8 ) (36 ) (32 ) $ (8 ) $ (38 ) $ (34 ) SDG&E: Expiration of statutes of limitations on tax assessments $ — $ (1 ) $ (1 ) Potential resolution of audit issues with various U.S. federal, state and local taxing authorities (6 ) (10 ) (8 ) $ (6 ) $ (11 ) $ (9 ) SoCalGas: Potential resolution of audit issues with various U.S. federal, state and local taxing authorities $ (2 ) $ (25 ) $ (22 )

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule Of Defined Benefit Plans, Change In Benefit Obligation And Fair Value Of Plan Assets	The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2017 and 2016 , and a statement of the funded status at December 31, 2017 and 2016 : PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 3,679 $ 3,649 $ 922 $ 963 Service cost 117 107 21 20 Interest cost 151 160 39 42 Contributions from plan participants — — 20 20 Actuarial loss (gain) 286 116 6 (81 ) Benefit payments (182 ) (217 ) (63 ) (61 ) Divestiture of EnergySouth — (61 ) — (6 ) Plan amendments 1 — — — Special termination benefits — — 18 26 Curtailments (1 ) — — — Settlements (194 ) (75 ) — (1 ) Net obligation at December 31 3,857 3,679 963 922 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 2,459 2,484 1,057 1,003 Actual return on plan assets 421 207 185 94 Employer contributions 155 104 10 6 Contributions from plan participants — — 20 20 Benefit payments (182 ) (217 ) (63 ) (61 ) Divestiture of EnergySouth — (44 ) — (4 ) Settlements (194 ) (75 ) — (1 ) Fair value of plan assets at December 31 2,659 2,459 1,209 1,057 Funded status at December 31 $ (1,198 ) $ (1,220 ) $ 246 $ 135 Net recorded (liability) asset at December 31 $ (1,198 ) $ (1,220 ) $ 246 $ 135 PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SAN DIEGO GAS & ELECTRIC COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 935 $ 965 $ 190 $ 165 Service cost 29 29 5 5 Interest cost 38 41 8 7 Contributions from plan participants — — 7 7 Actuarial loss (gain) 50 7 (9 ) 6 Benefit payments (83 ) (25 ) (16 ) (14 ) Special termination benefits — — — 14 Settlements — (75 ) — — Transfer of liability from (to) other plans 2 (7 ) — — Net obligation at December 31 971 935 185 190 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 714 752 169 161 Actual return on plan assets 120 59 30 13 Employer contributions 22 3 5 2 Contributions from plan participants — — 7 7 Benefit payments (83 ) (25 ) (16 ) (14 ) Settlements — (75 ) — — Transfer of assets from other plans 3 — — — Fair value of plan assets at December 31 776 714 195 169 Funded status at December 31 $ (195 ) $ (221 ) $ 10 $ (21 ) Net recorded (liability) asset at December 31 $ (195 ) $ (221 ) $ 10 $ (21 ) PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS SOUTHERN CALIFORNIA GAS COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 CHANGE IN PROJECTED BENEFIT OBLIGATION Net obligation at January 1 $ 2,343 $ 2,255 $ 691 $ 752 Service cost 76 67 14 14 Interest cost 98 101 29 32 Contributions from plan participants — — 13 13 Actuarial loss (gain) 216 77 16 (86 ) Benefit payments (73 ) (158 ) (44 ) (45 ) Special termination benefits — — 18 11 Settlements (175 ) — — — Transfer of liability from other plans 1 1 — — Net obligation at December 31 2,486 2,343 737 691 CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 1,579 1,537 870 822 Actual return on plan assets 269 128 151 79 Employer contributions 93 72 3 1 Contributions from plan participants — — 13 13 Benefit payments (73 ) (158 ) (44 ) (45 ) Settlements (175 ) — — — Transfer of assets from other plans 1 — — — Fair value of plan assets at December 31 1,694 1,579 993 870 Funded status at December 31 $ (792 ) $ (764 ) $ 256 $ 179 Net recorded (liability) asset at December 31 $ (792 ) $ (764 ) $ 256 $ 179
Schedule Of Defined Benefit Plans, Amounts Recognized In Balance Sheet	The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31: PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31 (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Noncurrent assets $ — $ — $ 266 $ 179 Current liabilities (69 ) (56 ) (1 ) — Noncurrent liabilities (1,129 ) (1,164 ) (19 ) (44 ) Net recorded (liability) asset $ (1,198 ) $ (1,220 ) $ 246 $ 135 SDG&E: Noncurrent assets $ — $ — $ 10 $ — Current liabilities (13 ) (10 ) — — Noncurrent liabilities (182 ) (211 ) — (21 ) Net recorded (liability) asset $ (195 ) $ (221 ) $ 10 $ (21 ) SoCalGas: Noncurrent assets $ — $ — $ 256 $ 179 Current liabilities (3 ) (2 ) — — Noncurrent liabilities (789 ) (762 ) — — Net recorded (liability) asset $ (792 ) $ (764 ) $ 256 $ 179
Schedule Of Defined Benefit Plans, Amounts In Accumulated Other Comprehensive Income	Amounts recorded in AOCI at December 31, 2017 and 2016 , net of income tax effects and amounts recorded as regulatory assets, are as follows: AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Net actuarial (loss) gain $ (84 ) $ (95 ) $ 4 $ 3 Prior service cost (4 ) (4 ) — — Total $ (88 ) $ (99 ) $ 4 $ 3 SDG&E: Net actuarial loss $ (8 ) $ (8 ) SoCalGas: Net actuarial loss $ (6 ) $ (6 ) Prior service cost (2 ) (3 ) Total $ (8 ) $ (9 )
Schedule Of Defined Benefit Plans, Accumulated Benefit Obligation	The accumulated benefit obligation for defined benefit pension plans at December 31, 2017 and 2016 was as follows: ACCUMULATED BENEFIT OBLIGATION (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas 2017 2016 2017 2016 2017 2016 Accumulated benefit obligation $ 3,551 $ 3,465 $ 930 $ 904 $ 2,241 $ 2,167
Schedule Of Defined Benefit Plans, Pension Plans With Benefit Obligations In Excess Of Plan Assets	The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31: OBLIGATIONS OF FUNDED PENSION PLANS (Dollars in millions) 2017 2016 Sempra Energy Consolidated: Projected benefit obligation $ 3,623 $ 3,431 Accumulated benefit obligation 3,334 3,227 Fair value of plan assets 2,659 2,459 SDG&E: Projected benefit obligation $ 939 $ 902 Accumulated benefit obligation 900 874 Fair value of plan assets 776 714 SoCalGas: Projected benefit obligation $ 2,462 $ 2,320 Accumulated benefit obligation 2,220 2,148 Fair value of plan assets 1,694 1,579
Schedule of Net Benefit Costs	The following three tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31: NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 117 $ 107 $ 114 $ 21 $ 20 $ 26 Interest cost 151 160 154 39 42 44 Expected return on assets (161 ) (166 ) (173 ) (66 ) (69 ) (68 ) Amortization of: Prior service cost (credit) 11 11 11 1 — (4 ) Actuarial loss (gain) 36 30 38 (4 ) (1 ) — Settlement and curtailment charges 38 16 4 — — — Special termination benefits — — — 18 26 — Regulatory adjustment (42 ) (57 ) (110 ) — (11 ) 12 Total net periodic benefit cost 150 101 38 9 7 10 CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss (gain) — 26 17 (2 ) (2 ) (4 ) Prior service cost 1 — 4 — — — Amortization of actuarial loss (18 ) (10 ) (14 ) — — — Amortization of prior service cost (1 ) (1 ) — — — — Total recognized in OCI (18 ) 15 7 (2 ) (2 ) (4 ) Total recognized in net periodic benefit cost and OCI $ 132 $ 116 $ 45 $ 7 $ 5 $ 6 NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SAN DIEGO GAS & ELECTRIC COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 29 $ 29 $ 29 $ 5 $ 5 $ 7 Interest cost 38 41 39 8 7 8 Expected return on assets (47 ) (49 ) (54 ) (11 ) (12 ) (11 ) Amortization of: Prior service cost 1 1 8 3 3 3 Actuarial loss (gain) 9 10 2 — (1 ) — Settlement charge — 16 — — — — Special termination benefits — — — — 14 — Regulatory adjustment (8 ) (45 ) (20 ) — (14 ) — Total net periodic benefit cost 22 3 4 5 2 7 CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss (gain) 2 1 (6 ) — — — Amortization of actuarial loss (1 ) (1 ) (1 ) — — — Total recognized in OCI 1 — (7 ) — — — Total recognized in net periodic benefit cost and OCI $ 23 $ 3 $ (3 ) $ 5 $ 2 $ 7 NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI SOUTHERN CALIFORNIA GAS COMPANY (Dollars in millions) Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 NET PERIODIC BENEFIT COST Service cost $ 76 $ 67 $ 74 $ 14 $ 14 $ 17 Interest cost 98 101 98 29 32 34 Expected return on assets (103 ) (103 ) (106 ) (53 ) (56 ) (56 ) Amortization of: Prior service cost (credit) 9 9 9 (3 ) (4 ) (7 ) Actuarial loss (gain) 19 11 21 (3 ) — — Settlement charge 30 — — — — — Special termination benefits — — — 18 11 — Regulatory adjustment (34 ) (12 ) (90 ) — 3 12 Total net periodic benefit cost 95 73 6 2 — — CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI Net loss — 4 — — — — Prior service cost — 2 2 — — — Amortization of prior service cost (1 ) — — — — — Total recognized in OCI (1 ) 6 2 — — — Total recognized in net periodic benefit cost and OCI $ 94 $ 79 $ 8 $ 2 $ — $ —
Schedule of Assumptions Used	The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows: WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION AT DECEMBER 31 Pension benefits Other postretirement benefits 2017 2016 2017 2016 Sempra Energy Consolidated: Discount rate 3.65 % 4.08 % 3.70 % 4.19 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SDG&E: Discount rate 3.64 % 4.08 % 3.65 % 4.15 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SoCalGas: Discount rate 3.65 % 4.10 % 3.70 % 4.20 % Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST YEARS ENDED DECEMBER 31 Pension benefits Other postretirement benefits 2017 2016 2015 2017 2016 2015 Sempra Energy Consolidated: Discount rate 4.08 % 4.46 % 4.09 % 4.19 % 4.49 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.47 6.98 6.98 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SDG&E: Discount rate 4.08 % 4.35 % 4.00 % 4.15 % 4.50 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.91 6.90 6.91 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 SoCalGas: Discount rate 4.10 % 4.50 % 4.15 % 4.20 % 4.50 % 4.15 % Expected return on plan assets 7.00 7.00 7.00 6.37 7.00 7.00 Rate of compensation increase 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00 2.00-10.00
Schedule of Health Care Cost Trend Rates	Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans: ASSUMED HEALTH CARE COST TREND RATES AT DECEMBER 31 Other postretirement benefit plans (1) Pre-65 retirees Retirees aged 65 years and older 2017 2016 2015 2017 2016 2015 Health care cost trend rate assumed for next year 7.00 % 8.00 % 8.10 % 5.00 % 5.50 % 5.50 % Rate to which the cost trend rate is assumed to decline (the ultimate trend) 5.00 % 5.00 % 5.00 % 4.50 % 4.50 % 4.50 % Year the rate reaches the ultimate trend 2022 2022 2022 2022 2022 2022 (1) Excludes Mobile Gas plan. For Mobile Gas, which we deconsolidated on September 12, 2016, the health care cost trend rate assumed for next year for all retirees was 8.10 percent in 2015; the ultimate trend was 5.00 percent in 2015; and the year the rate reaches the ultimate trend was 2022 in 2015. For Chilquinta Energía, the health care cost trend rate assumed for next year, and the ultimate trend, was 3.00 percent in each of 2017, 2016 and 2015.
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A one-percent change in assumed health care cost trend rates would have had the following effects in 2017: EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas 1% 1% 1% 1% 1% 1% increase decrease increase decrease increase decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 5 $ (4 ) $ 1 $ — $ 4 $ (3 ) Effect on the health care component of the accumulated other postretirement benefit obligations 53 (44 ) 3 (2 ) 48 (40 )
Schedule Of Defined Benefit Plans, Fair Value Of Plan Assets By Level In Fair Value Hierarchy	The fair values of our pension plan assets by asset category are as follows: FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Total Sempra Energy Consolidated: Equity securities: Domestic $ 946 $ — $ 946 International 538 — 538 Registered investment companies 102 — 102 Fixed income securities: Domestic government bonds 242 27 269 International government bonds — 12 12 Domestic corporate bonds — 338 338 International corporate bonds — 64 64 Registered investment companies — 6 6 Other — 1 1 Total investment assets in the fair value hierarchy $ 1,828 $ 448 2,276 Investments measured at NAV: Common/collective trusts 384 Private equity funds 4 Total investment assets (1) $ 2,664 SDG&E’s proportionate share of investment assets $ 777 SoCalGas’ proportionate share of investment assets $ 1,697 Fair value at December 31, 2016 Level 1 Level 2 Total Sempra Energy Consolidated: Equity securities: Domestic $ 884 $ — $ 884 International 522 — 522 Registered investment companies 127 — 127 Fixed income securities: Domestic government bonds 214 32 246 International government bonds — 9 9 Domestic corporate bonds — 346 346 International corporate bonds — 94 94 Registered investment companies — 14 14 Total investment assets in the fair value hierarchy $ 1,747 $ 495 2,242 Investments measured at NAV: Common/collective trusts 223 Private equity funds 4 Total investment assets (2) $ 2,469 SDG&E’s proportionate share of investment assets $ 717 SoCalGas’ proportionate share of investment assets $ 1,585 (1) Excludes cash and cash equivalents of $13 million and accounts payable of $18 million . (2) Excludes cash and cash equivalents of $14 million and accounts payable of $24 million . The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SoCalGas’ PBOP plans and SDG&E’s PBOP plan trusts are as follows: FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Total SDG&E: Equity securities: Domestic $ 46 $ — $ 46 International 26 — 26 Registered investment companies 52 — 52 Fixed income securities: Domestic government bonds 12 1 13 International government bonds — 1 1 Domestic corporate bonds — 17 17 International corporate bonds — 3 3 Registered investment companies — 17 17 Total investment assets in the fair value hierarchy 136 39 175 Investments measured at NAV – Common/collective trusts 20 Total investment assets (1) 195 SoCalGas: Equity securities: Domestic 78 — 78 International 44 — 44 Registered investment companies 41 — 41 Fixed income securities: Domestic government bonds 125 13 138 International government bonds — 7 7 Domestic corporate bonds — 164 164 International corporate bonds — 28 28 Registered investment companies — 85 85 Total investment assets in the fair value hierarchy 288 297 585 Investments measured at NAV – Common/collective trusts 406 Total investment assets (2) 991 Other Sempra Energy: Equity securities: Domestic 7 — 7 International 5 — 5 Registered investment companies 1 — 1 Fixed income securities: Domestic government bonds 1 1 2 Domestic corporate bonds — 2 2 International corporate bonds — 1 1 Total investment assets in the fair value hierarchy 14 4 18 Investments measured at NAV – Common/collective trusts 2 Private equity funds 1 Total other Sempra Energy investment assets 21 Total Sempra Energy Consolidated investment assets in the fair value hierarchy $ 438 $ 340 Total Sempra Energy Consolidated investment assets (3) $ 1,207 (1) Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts. (2) Excludes cash and cash equivalents of $4 million and accounts payable of $2 million held in SoCalGas PBOP plan trusts. (3) Excludes cash and cash equivalents of $5 million and accounts payable of $3 million at Sempra Energy Consolidated. FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS (Dollars in millions) Fair value at December 31, 2016 Level 1 Level 2 Total SDG&E: Equity securities: Domestic $ 41 $ — $ 41 International 24 — 24 Registered investment companies 46 — 46 Fixed income securities: Domestic government bonds 10 1 11 Domestic corporate bonds — 16 16 International corporate bonds — 3 3 Registered investment companies — 17 17 Total investment assets in the fair value hierarchy 121 37 158 Investments measured at NAV – Common/collective trusts 11 Total investment assets (1) 169 SoCalGas: Equity securities: Domestic 130 — 130 International 77 — 77 Registered investment companies 46 — 46 Fixed income securities: Domestic government bonds 52 8 60 International government bonds — 2 2 Domestic corporate bonds — 94 94 International corporate bonds — 28 28 Registered investment companies — 47 47 Total investment assets in the fair value hierarchy 305 179 484 Investments measured at NAV – Common/collective trusts 386 Total investment assets (2) 870 Other Sempra Energy: Equity securities: Domestic 6 — 6 International 3 — 3 Fixed income securities: Domestic government bonds 1 — 1 International government bonds — 1 1 Domestic corporate bonds — 2 2 International corporate bonds — 1 1 Registered investment companies — 1 1 Total investment assets in the fair value hierarchy 10 5 15 Investments measured at NAV – Common/collective trusts 3 Total other Sempra Energy investment assets 18 Total Sempra Energy Consolidated investment assets in the fair value hierarchy $ 436 $ 221 Total Sempra Energy Consolidated investment assets (3) $ 1,057 (1) Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts. (2) Excludes cash and cash equivalents of $4 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts. (3) Excludes cash and cash equivalents of $5 million and accounts payable of $5 million at Sempra Energy Consolidated.
Schedule Of Defined Benefit Plans, Estimated Future Employer Contributions In Next Fiscal Year	We expect to contribute the following amounts to our pension and PBOP plans in 2018 : EXPECTED CONTRIBUTIONS (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas Pension plans $ 226 $ 48 $ 113 Other postretirement benefit plans 9 3 2
Schedule of Expected Benefit Payments	The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets. EXPECTED BENEFIT PAYMENTS (Dollars in millions) Sempra Energy Consolidated SDG&E SoCalGas Pension benefits Other postretirement benefits Pension benefits Other postretirement benefits Pension benefits Other postretirement benefits 2018 $ 351 $ 52 $ 90 $ 10 $ 192 $ 38 2019 304 52 76 10 188 39 2020 294 54 74 10 179 40 2021 285 53 71 11 173 40 2022 273 53 68 11 172 40 2023-2027 1,217 262 314 52 782 197
Schedule Of Defined Benefit Plans Contributions	EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS (Dollars in millions) 2017 2016 2015 Sempra Energy Consolidated $ 41 $ 42 $ 43 SDG&E 14 15 17 SoCalGas 22 22 21

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Schedule Of Share-based Compensation Expense	Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows: SHARE-BASED COMPENSATION EXPENSE (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated: Share-based compensation expense, before income taxes $ 78 $ 46 $ 48 Income tax benefit (31 ) (18 ) (19 ) $ 47 $ 28 $ 29 Capitalized share-based compensation cost $ 9 $ 7 $ 6 Excess income tax benefit $ — $ (34 ) $ — SDG&E: Share-based compensation expense, before income taxes $ 13 $ 7 $ 8 Income tax benefit (5 ) (3 ) (3 ) $ 8 $ 4 $ 5 Capitalized share-based compensation cost $ 5 $ 4 $ 4 Excess income tax benefit $ — $ (7 ) $ — SoCalGas: Share-based compensation expense, before income taxes $ 17 $ 8 $ 10 Income tax benefit (7 ) (3 ) (4 ) $ 10 $ 5 $ 6 Capitalized share-based compensation cost $ 4 $ 3 $ 2 Excess income tax benefit $ — $ (4 ) $ —
Schedule Of Non-qualified Stock Options	The following table shows a summary of non-qualified stock options at December 31, 2017 and activity for the year then ended: NON-QUALIFIED STOCK OPTIONS Common shares under option Weighted- average exercise price Weighted- average remaining contractual term (in years) Aggregate intrinsic value (in millions) Outstanding at January 1, 2017 360,255 $ 52.46 Exercised (164,454 ) $ 55.04 Outstanding at December 31, 2017 195,801 $ 50.30 1.5 $ 11 Vested at December 31, 2017 195,801 $ 50.30 1.5 $ 11 Exercisable at December 31, 2017 195,801 $ 50.30 1.5 $ 11
Schedule Of Restricted Stock Awards And Units Valuation Assumptions	Below are key assumptions for awards granted in 2017, 2016 and 2015 for Sempra Energy: KEY ASSUMPTIONS FOR AWARDS GRANTED Years ended December 31, 2017 2016 2015 Risk-free rate of return 1.5 % 1.3 % 1.1 % Stock price volatility 17 16 14
Schedule Of Restricted Stock Units	We provide below a summary of Sempra Energy’s RSUs as of December 31, 2017 and the activity during the year. RESTRICTED STOCK UNITS Performance-based restricted stock units Service-based restricted stock units Units Weighted- average grant-date fair value Units Weighted- average Nonvested at January 1, 2017 1,954,322 $ 88.58 305,736 $ 94.68 Granted 424,760 $ 110.54 93,619 $ 101.88 Vested (637,577 ) $ 57.42 (108,880 ) $ 79.61 Forfeited (39,888 ) $ 103.17 (4,580 ) $ 97.84 Nonvested at December 31, 2017 (1) 1,701,617 $ 105.84 285,895 $ 98.81 Expected to vest at December 31, 2017 1,670,885 $ 105.38 282,106 $ 98.65 (1) Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, except for those issued in connection with the creation of Cameron LNG JV, up to an additional 50 percent ( 100 percent for awards granted during or after 2014) of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.

DERIVATIVE FINANCIAL INSTRUME38

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Volumes Table	We summarize net energy derivative volumes at December 31, 2017 and 2016 as follows: NET ENERGY DERIVATIVE VOLUMES (Quantities in millions) December 31, Commodity Unit of measure 2017 2016 California Utilities: SDG&E: Natural gas MMBtu 39 48 Electricity MWh 3 4 Congestion revenue rights MWh 59 48 SoCalGas – natural gas MMBtu — 1 Energy-Related Businesses: Sempra LNG & Midstream – natural gas MMBtu 3 31 Sempra Mexico – natural gas MMBtu 4 —
Notional Amounts Of Interest Rate Derivatives Table	At December 31, 2017 and 2016 , the net notional amounts of our foreign currency derivatives, excluding joint ventures, were: FOREIGN CURRENCY DERIVATIVES (Dollars in millions) December 31, 2017 December 31, 2016 Notional amount Maturities Notional amount Maturities Sempra Energy Consolidated: Cross-currency swaps $ 408 2018-2023 $ 408 2017-2023 Other foreign currency derivatives (1) 345 2018-2019 86 2017-2018 (1) In the first quarter of 2018, we entered into foreign currency derivatives with notional amounts totaling $650 million that expire between December 2018 and January 2019. At December 31, 2017 and 2016 , the net notional amounts of our interest rate derivatives, excluding joint ventures, were: INTEREST RATE DERIVATIVES (Dollars in millions) December 31, 2017 December 31, 2016 Notional debt Maturities Notional debt Maturities Sempra Energy Consolidated: Cash flow hedges (1) $ 861 2018-2032 $ 924 2017-2032 SDG&E: Cash flow hedge (1) 295 2018-2019 305 2017-2019 (1) Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.
Derivative Instruments on the Consolidated Balance Sheet Table	The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets at December 31, 2017 and 2016 , including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions. DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (Dollars in millions) December 31, 2017 Current assets: Fixed-price contracts and other derivatives (1) Other assets: Sundry Current liabilities: Fixed-price contracts and other derivatives (2) Deferred credits and other liabilities: Fixed-price contracts and other derivatives Sempra Energy Consolidated: Derivatives designated as hedging instruments: Interest rate and foreign exchange instruments (3) $ 5 $ 2 $ (51 ) $ (165 ) Derivatives not designated as hedging instruments: Foreign exchange instruments — — (1 ) — Commodity contracts not subject to rate recovery 81 8 (72 ) (6 ) Associated offsetting commodity contracts (67 ) (5 ) 67 5 Commodity contracts subject to rate recovery 28 101 (65 ) (120 ) Associated offsetting commodity contracts — (1 ) — 1 Associated offsetting cash collateral — — 19 4 Net amounts presented on the balance sheet 47 105 (103 ) (281 ) Additional cash collateral for commodity contracts not subject to rate recovery 2 — — — Additional cash collateral for commodity contracts subject to rate recovery 17 — — — Total (4) $ 66 $ 105 $ (103 ) $ (281 ) SDG&E: Derivatives designated as hedging instruments: Interest rate instruments (3) $ — $ — $ (10 ) $ (3 ) Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery 26 101 (63 ) (120 ) Associated offsetting commodity contracts — (1 ) — 1 Associated offsetting cash collateral — — 19 4 Net amounts presented on the balance sheet 26 100 (54 ) (118 ) Additional cash collateral for commodity contracts subject to rate recovery 16 — — — Total (4) $ 42 $ 100 $ (54 ) $ (118 ) SoCalGas: Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery $ 2 $ — $ (2 ) $ — Net amounts presented on the balance sheet 2 — (2 ) — Additional cash collateral for commodity contracts subject to rate recovery 1 — — — Total $ 3 $ — $ (2 ) $ — (1) Included in Current Assets: Other for SoCalGas. (2) Included in Current Liabilities: Other for SoCalGas. (3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. (4) Normal purchase contracts previously measured at fair value are excluded. DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (Dollars in millions) December 31, 2016 Current assets: Fixed-price contracts and other derivatives (1) Other assets: Sundry Current liabilities: Fixed-price contracts and other derivatives (2) Deferred credits and other liabilities: Fixed-price contracts and other derivatives Sempra Energy Consolidated: Derivatives designated as hedging instruments: Interest rate and foreign exchange instruments (3) $ 7 $ 2 $ (24 ) $ (228 ) Commodity contracts not subject to rate recovery — — (14 ) — Derivatives not designated as hedging instruments: Commodity contracts not subject to rate recovery 248 36 (254 ) (28 ) Associated offsetting commodity contracts (242 ) (27 ) 242 27 Associated offsetting cash collateral — (1 ) 16 1 Commodity contracts subject to rate recovery 37 73 (57 ) (150 ) Associated offsetting commodity contracts (9 ) (1 ) 9 1 Associated offsetting cash collateral — — 5 13 Net amounts presented on the balance sheet 41 82 (77 ) (364 ) Additional cash collateral for commodity contracts not subject to rate recovery 10 — — — Additional cash collateral for commodity contracts subject to rate recovery 32 — — — Total (4) $ 83 $ 82 $ (77 ) $ (364 ) SDG&E: Derivatives designated as hedging instruments: Interest rate instruments (3) $ — $ — $ (13 ) $ (12 ) Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery 33 73 (51 ) (150 ) Associated offsetting commodity contracts (6 ) (1 ) 6 1 Associated offsetting cash collateral — — 3 13 Net amounts presented on the balance sheet 27 72 (55 ) (148 ) Additional cash collateral for commodity contracts not subject to rate recovery 1 — — — Additional cash collateral for commodity contracts subject to rate recovery 30 — — — Total (4) $ 58 $ 72 $ (55 ) $ (148 ) SoCalGas: Derivatives not designated as hedging instruments: Commodity contracts subject to rate recovery $ 4 $ — $ (6 ) $ — Associated offsetting commodity contracts (3 ) — 3 — Associated offsetting cash collateral — — 2 — Net amounts presented on the balance sheet 1 — (1 ) — Additional cash collateral for commodity contracts not subject to rate recovery 1 — — — Additional cash collateral for commodity contracts subject to rate recovery 2 — — — Total $ 4 $ — $ (1 ) $ — (1) Included in Current Assets: Other for SoCalGas. (2) Included in Current Liabilities: Other for SoCalGas. (3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. (4) Normal purchase contracts previously measured at fair value are excluded.
Fair Value Hedge Impact on the Consolidated Statement of Operations Table	effects of derivative instruments designated as fair value hedges on the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. There were no fair value hedges outstanding during the year ended December 31, 2017. FAIR VALUE HEDGE IMPACTS (Dollars in millions) Pretax gain (loss) on derivatives recognized in earnings Years ended December 31, Location 2016 2015 Sempra Energy Consolidated: Interest rate instruments Interest Expense $ 3 $ 6 Interest rate instruments Other Income, Net (2 ) (5 ) Total (1) $ 1 $ 1 (1) There was no hedge ineffectiveness in 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.
Cash Flow Hedge Impact on the Consolidated Statements Of Operations Table	CASH FLOW HEDGE IMPACTS (Dollars in millions) Pretax gain (loss) recognized in OCI Pretax gain (loss) reclassified from AOCI into earnings Years ended December 31, Years ended December 31, 2017 2016 2015 Location 2017 2016 2015 Sempra Energy Consolidated: Interest rate and foreign exchange instruments (1) $ 19 $ (8 ) $ (18 ) Interest Expense $ 4 $ (17 ) $ (18 ) Interest rate instruments (25 ) (9 ) (80 ) Equity Earnings, Before Income Tax (8 ) (10 ) (12 ) Interest rate and foreign exchange instruments — — — Remeasurement of Equity Method Investment — (7 ) — Interest rate and foreign exchange instruments (9 ) 5 (20 ) Equity Earnings, Net of Income Tax (12 ) (5 ) (13 ) Foreign exchange instruments 4 4 — Revenues: Energy- Related Businesses 2 — — Commodity contracts not subject to rate recovery 3 (13 ) 12 Revenues: Energy- Related Businesses (9 ) 6 14 Total (2) $ (8 ) $ (21 ) $ (106 ) $ (23 ) $ (33 ) $ (29 ) SDG&E: Interest rate instruments (1)(3) $ (2 ) $ (2 ) $ (6 ) Interest Expense $ (13 ) $ (12 ) $ (12 ) SoCalGas: Interest rate instruments $ — $ — $ — Interest Expense $ — $ (1 ) $ (1 ) (1) Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. (2) There was $5 million , $4 million and $2 million of losses from ineffectiveness related to these cash flow hedges in 2017 , 2016 and 2015 , respectively. (3) There was negligible hedge ineffectiveness related to these cash flow hedges in 2017 , 2016 and 2015 .
Undesignated Derivative Impact on the Consolidated Statements of Operations	The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were: UNDESIGNATED DERIVATIVE IMPACTS (Dollars in millions) Pretax gain (loss) on derivatives recognized in earnings Years ended December 31, Location 2017 2016 2015 Sempra Energy Consolidated: Interest rate and foreign exchange instruments Other Income, Net $ 49 $ (32 ) $ (4 ) Foreign exchange instruments Equity Earnings, Net of Income Tax 1 3 (4 ) Commodity contracts not subject to rate recovery Revenues: Energy-Related Businesses 16 (18 ) 42 Commodity contracts not subject to rate recovery Operation and Maintenance — 1 (1 ) Commodity contracts subject to rate recovery Cost of Electric Fuel and Purchased Power 54 (53 ) (126 ) Commodity contracts subject to rate recovery Cost of Natural Gas (2 ) (4 ) 1 Total $ 118 $ (103 ) $ (92 ) SDG&E: Commodity contracts subject to rate recovery Cost of Electric Fuel and Purchased Power $ 54 $ (53 ) $ (126 ) SoCalGas: Commodity contracts not subject to rate recovery Operation and Maintenance $ — $ 1 $ (1 ) Commodity contracts subject to rate recovery Cost of Natural Gas (2 ) (4 ) 1 Total $ (2 ) $ (3 ) $ —

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Recurring Fair Value Measures Table	RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 491 $ 5 $ — $ 496 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 45 9 — 54 Municipal bonds — 250 — 250 Other securities — 217 — 217 Total debt securities 45 476 — 521 Total nuclear decommissioning trusts (1) 536 481 — 1,017 Interest rate and foreign exchange instruments — 7 — 7 Commodity contracts not subject to rate recovery 5 12 — 17 Effect of netting and allocation of collateral (2) 2 — — 2 Commodity contracts subject to rate recovery — 2 126 128 Effect of netting and allocation of collateral (2) 12 — 5 17 Total $ 555 $ 502 $ 131 $ 1,188 Liabilities: Interest rate and foreign exchange instruments $ — $ 217 $ — $ 217 Commodity contracts not subject to rate recovery — 6 — 6 Commodity contracts subject to rate recovery 23 7 154 184 Effect of netting and allocation of collateral (2) (23 ) — — (23 ) Total $ — $ 230 $ 154 $ 384 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 508 $ — $ — $ 508 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 36 16 — 52 Municipal bonds — 206 — 206 Other securities — 141 — 141 Total debt securities 36 363 — 399 Total nuclear decommissioning trusts (1) 544 363 — 907 Interest rate and foreign exchange instruments — 9 — 9 Commodity contracts not subject to rate recovery — 15 — 15 Effect of netting and allocation of collateral (2) 2 7 — 9 Commodity contracts subject to rate recovery 1 3 96 100 Effect of netting and allocation of collateral (2) 27 — 5 32 Total $ 574 $ 397 $ 101 $ 1,072 Liabilities: Interest rate and foreign exchange instruments $ — $ 252 $ — $ 252 Commodity contracts not subject to rate recovery 16 11 — 27 Effect of netting and allocation of collateral (2) (17 ) — — (17 ) Commodity contracts subject to rate recovery 19 8 170 197 Effect of netting and allocation of collateral (2) (18 ) — — (18 ) Total $ — $ 271 $ 170 $ 441 (1) Excludes cash balances and cash equivalents. (2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset. RECURRING FAIR VALUE MEASURES – SDG&E (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 491 $ 5 $ — $ 496 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 45 9 — 54 Municipal bonds — 250 — 250 Other securities — 217 — 217 Total debt securities 45 476 — 521 Total nuclear decommissioning trusts (1) 536 481 — 1,017 Commodity contracts subject to rate recovery — — 126 126 Effect of netting and allocation of collateral (2) 11 — 5 16 Total $ 547 $ 481 $ 131 $ 1,159 Liabilities: Interest rate instruments $ — $ 13 $ — $ 13 Commodity contracts subject to rate recovery 23 5 154 182 Effect of netting and allocation of collateral (2) (23 ) — — (23 ) Total $ — $ 18 $ 154 $ 172 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trusts: Equity securities $ 508 $ — $ — $ 508 Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 36 16 — 52 Municipal bonds — 206 — 206 Other securities — 141 — 141 Total debt securities 36 363 — 399 Total nuclear decommissioning trusts (1) 544 363 — 907 Commodity contracts not subject to rate recovery — — — — Effect of netting and allocation of collateral (2) 1 — — 1 Commodity contracts subject to rate recovery 1 2 96 99 Effect of netting and allocation of collateral (2) 25 — 5 30 Total $ 571 $ 365 $ 101 $ 1,037 Liabilities: Interest rate instruments $ — $ 25 $ — $ 25 Commodity contracts subject to rate recovery 17 7 170 194 Effect of netting and allocation of collateral (2) (16 ) — — (16 ) Total $ 1 $ 32 $ 170 $ 203 (1) Excludes cash balances and cash equivalents. (2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset. RECURRING FAIR VALUE MEASURES – SOCALGAS (Dollars in millions) Fair value at December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Commodity contracts subject to rate recovery $ — $ 2 $ — $ 2 Effect of netting and allocation of collateral (1) 1 — — 1 Total $ 1 $ 2 $ — $ 3 Liabilities: Commodity contracts subject to rate recovery $ — $ 2 $ — $ 2 Total $ — $ 2 $ — $ 2 Fair value at December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Commodity contracts not subject to rate recovery $ — $ — $ — $ — Effect of netting and allocation of collateral (1) 1 — — 1 Commodity contracts subject to rate recovery — 1 — 1 Effect of netting and allocation of collateral (1) 2 — — 2 Total $ 3 $ 1 $ — $ 4 Liabilities: Commodity contracts subject to rate recovery $ 2 $ 1 $ — $ 3 Effect of netting and allocation of collateral (1) (2 ) — — — (2 ) Total $ — $ 1 $ — $ 1 (1 ) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Recurring Fair Value Measures Level 3 Rollforward Table	The following table sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E: LEVEL 3 RECONCILIATIONS (1) (Dollars in millions) Years ended December 31, 2017 2016 2015 Balance at January 1 $ (74 ) $ 19 $ 107 Realized and unrealized gains (losses) 34 (120 ) (134 ) Allocated transmission instruments 6 8 12 Settlements 6 19 34 Balance at December 31 $ (28 ) $ (74 ) $ 19 Change in unrealized gains (losses) relating to instruments still held at December 31 $ 30 $ (101 ) $ (27 ) (1) Excludes the effect of contractual ability to settle contracts under master netting agreements.
Schedule of Auction Price Inputs	For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, are in the following ranges: CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS Settlement year Price per MWh 2018 $ (7.25 ) to $ 11.99 2017 (11.88 ) to 6.93 2016 (23.81 ) to 10.23
Fair Value of Financial Instruments Table	The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets at December 31, 2017 and 2016 : FAIR VALUE OF FINANCIAL INSTRUMENTS (Dollars in millions) December 31, 2017 Carrying Fair value amount Level 1 Level 2 Level 3 Total Sempra Energy Consolidated: Long-term amounts due from unconsolidated affiliates (1) $ 604 $ — $ 528 $ 96 $ 624 Long-term amounts due to unconsolidated affiliates 35 — 32 — 32 Total long-term debt (2)(3) 17,138 817 17,134 458 18,409 SDG&E: Total long-term debt (3)(4) $ 4,868 $ — $ 5,073 $ 295 $ 5,368 SoCalGas: Total long-term debt (5) $ 3,009 $ — $ 3,192 $ — $ 3,192 December 31, 2016 Carrying Fair value amount Level 1 Level 2 Level 3 Total Sempra Energy Consolidated: Long-term amounts due from unconsolidated affiliates (1) $ 184 $ — $ 91 $ 84 $ 175 Total long-term debt (2)(3) 15,068 — 15,455 492 15,947 SDG&E: Total long-term debt (3)(4) $ 4,654 $ — $ 4,727 $ 305 $ 5,032 SoCalGas: Total long-term debt (5) $ 3,009 $ — $ 3,131 $ — $ 3,131 (1) Excluding accumulated interest outstanding of $29 million and $17 million at December 31, 2017 and 2016 , respectively, and excluding foreign currency translation of $35 million on a Mexican peso-denominated loan at December 31, 2017. (2) Before reductions for unamortized discount (net of premium) and debt issuance costs of $143 million and $109 million at December 31, 2017 and 2016 , respectively, and excluding build-to-suit and capital lease obligations of $877 million and $383 million at December 31, 2017 and 2016 , respectively. We discuss our long-term debt in Note 5. (3) Level 3 instruments include $295 million and $305 million at December 31, 2017 and 2016 , respectively, related to Otay Mesa VIE. (4) Before reductions for unamortized discount and debt issuance costs of $45 million at December 31, 2017 and 2016 , respectively, and excluding capital lease obligations of $732 million and $240 million at December 31, 2017 and 2016 , respectively. (5) Before reductions for unamortized discount and debt issuance costs of $24 million and $27 million at December 31, 2017 and 2016 , respectively, and excluding capital lease obligations of $1 million at December 31, 2017.
Fair Value Measurements, Nonrecurring Table	The following table summarizes significant inputs impacting our non-recurring fair value measures: NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Estimated fair value Valuation technique Fair value hierarchy % of fair value measurement Inputs used to develop measurement Range of inputs Investment in IEnova Pipelines $ 1,144 (1) Market approach Level 2 100% Equity sale price 100% TdM $ 145 (2) Market approach Level 2 100% Purchase price offers 100% TdM $ 62 (3) Market approach Level 2 100% Purchase price offer 100% Investment in $ 440 (4) Market approach Level 2 100% Equity sale price 100% (1) At measurement date of September 26, 2016, immediately prior to acquiring a 100 -percent ownership interest in IEnova Pipelines. (2) At measurement date of September 29, 2016. (3) At measurement date of June 30, 2017. At December 31, 2017, TdM has a carrying value of $78 million , reflecting subsequent business activity, and is classified as held for sale. (4) At measurement date of March 29, 2016. On May 9, 2016, Sempra LNG & Midstream sold its equity interest in Rockies Express.

PREFERRED STOCK (Tables)

PREFERRED STOCK (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule Of Preferred Stock	At December 31, 2017 and 2016 , SoCalGas has the following preferred stock outstanding: PREFERRED STOCK OUTSTANDING (Dollars in millions, except per share amounts) December 31, 2017 2016 $25 par value, authorized 1,000,000 shares: 6% Series, 79,011 shares outstanding $ 3 $ 3 6% Series A, 783,032 shares outstanding 19 19 SoCalGas - Total preferred stock 22 22 Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises (2 ) (2 ) Sempra Energy - Total preferred stock of subsidiary $ 20 $ 20

SEMPRA ENERGY - SHAREHOLDERS'41

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule Of Earnings Per Share Computations	The following table provides EPS computations for the years ended December 31, 2017 , 2016 and 2015 . Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 AND DIVIDENDS DECLARED (Dollars in millions, except per share amounts; shares in thousands) Years ended December 31, 2017 2016 2015 Numerator: Earnings/Income attributable to common shares $ 256 $ 1,370 $ 1,349 Denominator: Weighted-average common shares outstanding for basic EPS (1) 251,545 250,217 248,249 Dilutive effect of stock options, RSAs and RSUs (2) 755 938 2,674 Weighted-average common shares outstanding for diluted EPS 252,300 251,155 250,923 EPS: Basic $ 1.02 $ 5.48 $ 5.43 Diluted $ 1.01 $ 5.46 $ 5.37 Dividends declared per share of common stock (3) $ 3.29 $ 3.02 $ 2.80 (1) Includes average fully vested RSUs held in our Deferred Compensation Plan of 609 in 2017, 568 in 2016 and 491 in 2015. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued. (2) Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8, dilutive RSUs may vary widely from period-to-period. (3) Our board of directors has the discretion to determine the payment and amount of future dividends.
Schedule Of Common Stock Activity	The following table provides common stock activity for the years ended December 31, 2017 , 2016 and 2015 . COMMON STOCK ACTIVITY Years ended December 31, 2017 2016 2015 Common shares outstanding, January 1 250,152,514 248,298,080 246,330,884 RSUs vesting (1) 362,022 1,363,555 1,499,062 Stock options exercised 164,454 167,742 227,815 Savings plan issuance 567,428 653,607 652,631 Common stock investment plan (2) 254,047 266,056 249,665 Issuance of RSUs held in our Deferred Compensation Plan 7,811 — — Shares repurchased (3) (149,299 ) (596,526 ) (661,977 ) Common shares outstanding, December 31 251,358,977 250,152,514 248,298,080 (1) Includes dividend equivalents. (2) Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares. (3) From time to time, we purchase shares of our common stock or units from long-term incentive plan participants who elect to sell to us a sufficient number of vested RSAs or RSUs to meet minimum statutory tax withholding requirements.

SAN ONOFRE NUCLEAR GENERATING42

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Nuclear Decommissioning Trusts	The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10. NUCLEAR DECOMMISSIONING TRUSTS (Dollars in millions) Cost Gross unrealized gains Gross unrealized losses Estimated fair value At December 31, 2017: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies (1) $ 54 $ — $ — $ 54 Municipal bonds (1) 245 7 (2 ) 250 Other securities (2) 215 3 (1 ) 217 Total debt securities 514 10 (3 ) 521 Equity securities 171 326 (1 ) 496 Cash and cash equivalents 16 — — 16 Total $ 701 $ 336 $ (4 ) $ 1,033 At December 31, 2016: Debt securities: Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies $ 52 $ — $ — $ 52 Municipal bonds 203 4 (1 ) 206 Other securities 141 2 (2 ) 141 Total debt securities 396 6 (3 ) 399 Equity securities 143 366 (1 ) 508 Cash and cash equivalents 119 — — 119 Total $ 658 $ 372 $ (4 ) $ 1,026 (1) Maturity dates are 2018-2048. (2) Maturity dates are 2018-2064.
Schedule of Securities Sold	The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales. SALES OF SECURITIES (Dollars in millions) Years ended December 31, 2017 2016 2015 Proceeds from sales (1) $ 1,314 $ 1,134 $ 577 Gross realized gains 157 111 29 Gross realized losses (14 ) (29 ) (15 ) (1) Excludes securities that are held to maturity.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets [Table Text Block]	We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below. REGULATORY ASSETS (LIABILITIES) (Dollars in millions) December 31, 2017 2016 SDG&E: Fixed-price contracts and other derivatives $ 96 $ 141 Costs related to SONGS plant closure (1) — 183 Costs related to wildfire litigation — 353 Deferred income taxes (refundable) recoverable in rates (281 ) 1,014 Pension and other postretirement benefit plan obligations 153 210 Removal obligations (1,846 ) (1,725 ) Unamortized loss on reacquired debt 9 12 Environmental costs 29 48 Legacy meters (1) — 16 Sunrise Powerlink fire mitigation 119 118 Regulatory balancing accounts (2) Commodity – electric 82 35 Gas transportation 22 61 Safety and reliability 48 20 Public purpose programs (70 ) (106 ) Other balancing accounts 233 249 Other regulatory liabilities (70 ) (2 ) Total SDG&E (1,476 ) 627 SoCalGas: Pension and other postretirement benefit plan obligations 513 563 Employee benefit costs 45 45 Removal obligations (924 ) (972 ) Deferred income taxes (refundable) recoverable in rates (437 ) 417 Unamortized loss on reacquired debt 8 10 Environmental costs 22 22 Workers’ compensation 12 10 Regulatory balancing accounts (2) Commodity – gas, including transportation 151 207 Safety and reliability 266 230 Public purpose programs (274 ) (270 ) Other balancing accounts (114 ) (204 ) Other regulatory (liabilities) assets (64 ) 8 Total SoCalGas (796 ) 66 Sempra Mexico: Deferred income taxes recoverable in rates 83 71 Total Sempra Energy Consolidated $ (2,189 ) $ 764 (1) Regulatory assets earning a rate of return. (2) At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million . At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million , respectively.
Schedule of Regulatory Liabilities [Table Text Block]	We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below. REGULATORY ASSETS (LIABILITIES) (Dollars in millions) December 31, 2017 2016 SDG&E: Fixed-price contracts and other derivatives $ 96 $ 141 Costs related to SONGS plant closure (1) — 183 Costs related to wildfire litigation — 353 Deferred income taxes (refundable) recoverable in rates (281 ) 1,014 Pension and other postretirement benefit plan obligations 153 210 Removal obligations (1,846 ) (1,725 ) Unamortized loss on reacquired debt 9 12 Environmental costs 29 48 Legacy meters (1) — 16 Sunrise Powerlink fire mitigation 119 118 Regulatory balancing accounts (2) Commodity – electric 82 35 Gas transportation 22 61 Safety and reliability 48 20 Public purpose programs (70 ) (106 ) Other balancing accounts 233 249 Other regulatory liabilities (70 ) (2 ) Total SDG&E (1,476 ) 627 SoCalGas: Pension and other postretirement benefit plan obligations 513 563 Employee benefit costs 45 45 Removal obligations (924 ) (972 ) Deferred income taxes (refundable) recoverable in rates (437 ) 417 Unamortized loss on reacquired debt 8 10 Environmental costs 22 22 Workers’ compensation 12 10 Regulatory balancing accounts (2) Commodity – gas, including transportation 151 207 Safety and reliability 266 230 Public purpose programs (274 ) (270 ) Other balancing accounts (114 ) (204 ) Other regulatory (liabilities) assets (64 ) 8 Total SoCalGas (796 ) 66 Sempra Mexico: Deferred income taxes recoverable in rates 83 71 Total Sempra Energy Consolidated $ (2,189 ) $ 764 (1) Regulatory assets earning a rate of return. (2) At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million . At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million , respectively.
Schedule Of Approved Increase Decrease To Annual Revenue Requirement	Following is a summary of the 2016 earnings impacts from the 2016 GRC FD: EARNINGS IMPACTS IN 2016 FROM THE 2016 GRC FD (Dollars in millions) SoCalGas SDG&E Pretax After-tax earnings (charge) Pretax After-tax Adjustments to revenue related to tax repairs deductions: 2015 memorandum account balance $ (72 ) $ (43 ) $ (37 ) $ (22 ) True-up of 2012-2014 estimates to actuals (11 ) (6 ) (15 ) (9 ) Total $ (83 ) $ (49 ) $ (52 ) $ (31 )
Schedule Of CPUC Cost of Capital Authorized	In October 2017, the CPUC approved the embedded cost of debt presented in the filed advice letters, resulting in a revised return on rate base for SDG&E from 7.79 percent to 7.55 percent and for SoCalGas from 8.02 percent to 7.34 percent , effective January 1, 2018, as depicted in the table below: AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC SDG&E SoCalGas Authorized weighting Return on rate base Weighted rate base Authorized weighting Return on Weighted 45.25 % 4.59 % 2.08 % Long-Term Debt 45.60 % 4.33 % 1.97 % 2.75 6.22 0.17 Preferred Stock 2.40 6.00 0.14 52.00 10.20 5.30 Common Equity 52.00 10.05 5.23 100.00 % 7.55 % 100.00 % 7.34 % As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below: IMPACT OF THE EMBEDDED COST OF DEBT SDG&E SoCalGas Cost of debt Return on rate base Cost of Return on Current 5.00 % 7.79 % 5.77 % 8.02 % Authorized, effective January 1, 2018 4.59 % 7.55 % 4.33 % 7.34 % Differences (41 ) bps (24 ) bps (144 ) bps (68 ) bps
Schedule Of FERC Cost Of Capital Table	SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows: SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC Weighting Return on rate base Weighted return on rate base Long-Term Debt 43.44 % 4.21 % 1.83 % Common Equity 56.56 10.05 5.68 100.00 % 7.51 %

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule Of Estimated Future Payments Under Natural Gas Contracts	At December 31, 2017 , the future estimated payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows: FUTURE ESTIMATED PAYMENTS – SEMPRA ENERGY CONSOLIDATED (Dollars in millions) Storage and transportation Natural gas (1) Total (1) 2018 $ 231 $ 61 $ 292 2019 146 — 146 2020 48 — 48 2021 46 1 47 2022 44 1 45 Thereafter 127 — 127 Total estimated payments $ 642 $ 63 $ 705 (1) Excludes amounts related to the LNG purchase agreement discussed below. FUTURE ESTIMATED PAYMENTS – SOCALGAS (Dollars in millions) Transportation Natural gas Total 2018 $ 108 $ — $ 108 2019 59 — 59 2020 29 — 29 2021 27 1 28 2022 27 1 28 Thereafter 81 — 81 Total estimated payments $ 331 $ 2 $ 333
Schedule Of Payments Under Natural Gas Contracts	Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra Energy Consolidated and SoCalGas were as follows: PAYMENTS UNDER NATURAL GAS CONTRACTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 1,429 $ 1,169 $ 1,200 SoCalGas 1,213 966 975
Schedule Of L N G Commitment Amounts	At December 31, 2017 , the following LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered: LNG COMMITMENT AMOUNTS (Dollars in millions) 2018 $ 302 2019 383 2020 391 2021 403 2022 411 Thereafter 2,935 Total $ 4,825
Schedule Of Estimated Future Payments Under Purchased Power Contracts	At December 31, 2017 , the future estimated payments under long-term purchased-power contracts are as follows: FUTURE ESTIMATED PAYMENTS – PURCHASED-POWER CONTRACTS (Dollars in millions) Sempra Energy Consolidated SDG&E 2018 $ 702 $ 577 2019 690 571 2020 631 510 2021 633 510 2022 598 496 Thereafter 5,726 5,457 Total estimated payments (1)(2) $ 8,980 $ 8,121 (1) Excludes purchase agreements accounted for as capital leases and amounts related to Otay Mesa VIE, as it is consolidated by Sempra Energy and SDG&E. (2) Includes $5.4 billion of expected payments under purchase agreements accounted for as operating leases at SDG&E, comprising renewable energy PPAs for which there are no future minimum operating lease payments.
Schedule Of Payments Under Purchased Power Contracts	Total payments under purchased-power contracts were as follows: PAYMENTS UNDER PURCHASED-POWER CONTRACTS (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 1,694 $ 1,667 $ 1,573 SDG&E 781 752 715
Schedule Of Operating Leases Rent Expense	Rent expense for operating leases was as follows: RENT EXPENSE – OPERATING LEASES (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated $ 109 $ 77 $ 78 SDG&E 28 28 27 SoCalGas 43 38 39
Schedule Of Operating Leases Future Minimum Payments Due	At December 31, 2017 , the rental commitments payable in future years under all noncancelable operating leases, including estimated payments, are as follows: FUTURE RENTAL PAYMENTS – OPERATING LEASES (Dollars in millions) 2018 2019 2020 2021 2022 Thereafter Total Sempra Energy Consolidated: Future minimum lease payments $ 85 $ 57 $ 51 $ 48 $ 42 $ 300 $ 583 Future estimated rental payments 13 12 12 12 13 46 108 Total future rental commitments $ 98 $ 69 $ 63 $ 60 $ 55 $ 346 $ 691 SDG&E: Future minimum lease payments $ 22 $ 21 $ 20 $ 19 $ 18 $ 54 $ 154 Future estimated rental payments 2 2 2 2 2 3 13 Total future rental commitments $ 24 $ 23 $ 22 $ 21 $ 20 $ 57 $ 167 SoCalGas: Future minimum lease payments $ 29 $ 25 $ 20 $ 19 $ 13 $ 36 $ 142 Future estimated rental payments 11 10 10 10 11 43 95 Total future rental commitments $ 40 $ 35 $ 30 $ 29 $ 24 $ 79 $ 237
Schedule Of Capital Leases Future Minimum Payments Present Value Of Net Minimum Payments	At December 31, 2017 , the future minimum lease payments and present value of the net minimum lease payments under these capital leases for both Sempra Energy Consolidated and SDG&E are as follows: FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENTS (Dollars in millions) 2018 $ 192 2019 210 2020 210 2021 210 2022 210 Thereafter 3,299 Total minimum lease payments (1) 4,331 Less: estimated executory costs (502 ) Less: interest (2) (2,548 ) Present value of net minimum lease payments (3) $ 1,281 (1) This amount will be recorded over the lives of the leases as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates. (2) Amount necessary to reduce net minimum lease payments to present value at the inception of the leases. (3) Includes $13 million in Current Portion of Long-Term Debt and $718 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2017 . The remaining present value of net minimum lease payments of $550 million will be recorded as a capital lease obligation when construction of the power plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2018.
Schedule Of Environmental Remediation Costs Capitalized In Period	The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations: CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES (Dollars in millions) Years ended December 31, 2017 2016 2015 Sempra Energy Consolidated (1) $ 92 $ 53 $ 64 SDG&E 46 17 24 SoCalGas 45 35 39 (1) In cases of non-wholly owned affiliates, includes only our share.
Schedule Of Environmental Remediation Costs, Status Of Remediation Sites	The table below shows the status at December 31, 2017 of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP: STATUS OF ENVIRONMENTAL SITES # Sites complete (1) # Sites in process SDG&E: Manufactured-gas sites 3 — Third-party waste-disposal sites 2 1 SoCalGas: Manufactured-gas sites 39 3 Third-party waste-disposal sites 5 2 (1) There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring .
Schedule of Environmental Loss Contingencies by Site	The following table shows our accrued liabilities for environmental matters at December 31, 2017 : ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS (Dollars in millions) Manufactured- gas sites Waste disposal sites (PRP) (1) Other Total (2) SDG&E (3) $ — $ 2 $ 2 $ 4 SoCalGas (4) 22 1 1 24 Other — 1 — 1 Total Sempra Energy $ 22 $ 4 $ 3 $ 29 (1) Sites for which we have been identified as a PRP. (2) Includes $9 million , $1 million and $8 million classified as current liabilities, and $20 million , $3 million and $16 million classified as noncurrent liabilities on Sempra Energy’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively. (3) Does not include SDG&E’s liability for SONGS marine environment mitigation. (4) Does not include SoCalGas’ liability for environmental matters for the natural gas leak at the Aliso Canyon natural gas storage facility. We discuss matters related to the leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”
Schedule Of Build To Suit Lease Future Minimum Payments Due	At December 31, 2017 , the future minimum lease payments on the lease are as follows: FUTURE MINIMUM PAYMENTS – BUILD-TO-SUIT LEASE (Dollars in millions) 2018 $ 10 2019 10 2020 11 2021 11 2022 11 Thereafter 234 Total minimum lease payments $ 287

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 4. Amounts labeled as “All other” in the following tables consist primarily of parent organizations. SEGMENT INFORMATION (Dollars in millions) Years ended December 31, 2017 2016 2015 REVENUES SDG&E $ 4,476 $ 4,253 $ 4,219 SoCalGas 3,785 3,471 3,489 Sempra South American Utilities 1,567 1,556 1,544 Sempra Mexico 1,196 725 669 Sempra Renewables 94 34 36 Sempra LNG & Midstream 540 508 653 Adjustments and eliminations (1 ) — (2 ) Intersegment revenues (1) (450 ) (364 ) (377 ) Total $ 11,207 $ 10,183 $ 10,231 INTEREST EXPENSE SDG&E $ 203 $ 195 $ 204 SoCalGas 102 97 84 Sempra South American Utilities 38 38 32 Sempra Mexico 97 13 23 Sempra Renewables 15 4 3 Sempra LNG & Midstream 39 43 72 All other 284 282 263 Intercompany eliminations (119 ) (119 ) (120 ) Total $ 659 $ 553 $ 561 INTEREST INCOME SoCalGas $ 1 $ 1 $ 4 Sempra South American Utilities 28 21 19 Sempra Mexico 23 6 7 Sempra Renewables 7 5 4 Sempra LNG & Midstream 56 71 75 Intercompany eliminations (69 ) (78 ) (80 ) Total $ 46 $ 26 $ 29 DEPRECIATION AND AMORTIZATION SDG&E $ 670 $ 646 $ 604 SoCalGas 515 476 461 Sempra South American Utilities 54 49 50 Sempra Mexico 156 77 70 Sempra Renewables 38 6 6 Sempra LNG & Midstream 42 47 49 All other 15 11 10 Total $ 1,490 $ 1,312 $ 1,250 INCOME TAX EXPENSE (BENEFIT) SDG&E $ 155 $ 280 $ 284 SoCalGas 160 143 138 Sempra South American Utilities 80 80 67 Sempra Mexico 227 188 11 Sempra Renewables (226 ) (38 ) (49 ) Sempra LNG & Midstream (119 ) (80 ) 28 All other 999 (184 ) (138 ) Total $ 1,276 $ 389 $ 341 SEGMENT INFORMATION (CONTINUED) (Dollars in millions) Years ended December 31 or at December 31, 2017 2016 2015 EARNINGS (LOSSES) SDG&E $ 407 $ 570 $ 587 SoCalGas (2) 396 349 419 Sempra South American Utilities 186 156 175 Sempra Mexico 169 463 213 Sempra Renewables 252 55 63 Sempra LNG & Midstream 150 (107 ) 44 All other (1,304 ) (116 ) (152 ) Total $ 256 $ 1,370 $ 1,349 ASSETS SDG&E $ 17,844 $ 17,719 $ 16,515 SoCalGas 14,159 13,424 12,104 Sempra South American Utilities 4,060 3,591 3,235 Sempra Mexico 8,554 7,542 3,783 Sempra Renewables 2,898 3,644 1,441 Sempra LNG & Midstream 4,872 5,564 5,566 All other 915 475 734 Intersegment receivables (2,848 ) (4,173 ) (2,228 ) Total $ 50,454 $ 47,786 $ 41,150 EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT SDG&E $ 1,555 $ 1,399 $ 1,133 SoCalGas 1,367 1,319 1,352 Sempra South American Utilities 244 194 154 Sempra Mexico 248 330 302 Sempra Renewables 497 835 81 Sempra LNG & Midstream 20 117 87 All other 18 20 47 Total $ 3,949 $ 4,214 $ 3,156 GEOGRAPHIC INFORMATION Long-lived assets (3) : United States $ 31,487 $ 28,351 $ 26,132 Mexico 5,363 4,814 3,160 South America 2,180 1,863 1,652 Total $ 39,030 $ 35,028 $ 30,944 Revenues (4) : United States $ 8,547 $ 8,004 $ 8,119 South America 1,567 1,556 1,544 Mexico 1,093 623 568 Total $ 11,207 $ 10,183 $ 10,231 (1) Revenues for reportable segments include intersegment revenues of $7 million , $74 million , $103 million and $266 million for 2017 , $6 million , $76 million , $102 million and $180 million for 2016 , and $9 million , $75 million , $101 million and $192 million for 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively. (2) After preferred dividends. (3) Includes net PP&E and investments. (4) Amounts are based on where the revenue originated, after intercompany eliminations.

QUARTERLY FINANCIAL DATA (UNA46

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Schedule Of Quarterly Financial Data Table	SDG&E (Dollars in millions) Quarters ended March 31 June 30 September 30 December 31 2017: Operating revenues $ 1,057 $ 1,058 $ 1,236 $ 1,125 Operating expenses 779 817 1,290 877 Operating income (loss) $ 278 $ 241 $ (54 ) $ 248 Net income (loss) $ 157 $ 153 $ (19 ) $ 130 (Earnings) losses attributable to noncontrolling interest (2 ) (4 ) (9 ) 1 Earnings (losses) attributable to common shares $ 155 $ 149 $ (28 ) $ 131 2016: Operating revenues $ 991 $ 992 $ 1,209 $ 1,061 Operating expenses 755 822 886 800 Operating income $ 236 $ 170 $ 323 $ 261 Net income $ 137 $ 87 $ 194 $ 147 (Earnings) losses attributable to noncontrolling interest (1 ) 13 (11 ) 4 Earnings attributable to common shares $ 136 $ 100 $ 183 $ 151 SOCALGAS (Dollars in millions) Quarters ended March 31 June 30 September 30 December 31 2017: Operating revenues $ 1,241 $ 770 $ 684 $ 1,090 Operating expenses 926 675 674 888 Operating income $ 315 $ 95 $ 10 $ 202 Net income $ 203 $ 59 $ 7 $ 128 Dividends on preferred stock — (1 ) — — Earnings attributable to common shares $ 203 $ 58 $ 7 $ 128 2016: Operating revenues $ 1,033 $ 617 $ 686 $ 1,135 Operating expenses 739 628 648 899 Operating income (loss) $ 294 $ (11 ) $ 38 $ 236 Net income $ 199 $ — $ — $ 151 Dividends on preferred stock — (1 ) — — Earnings (losses) attributable to common shares $ 199 $ (1 ) $ — $ 151 We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below: SEMPRA ENERGY (In millions, except per share amounts) Quarters ended March 31 June 30 September 30 December 31 2017: Revenues $ 3,031 $ 2,533 $ 2,679 $ 2,964 Expenses and other income $ 2,276 $ 2,118 $ 2,664 $ 2,564 Net income (loss) $ 452 $ 248 $ 102 $ (451 ) Earnings (losses) attributable to Sempra Energy $ 441 $ 259 $ 57 $ (501 ) Basic per-share amounts (1) : Net income (loss) $ 1.80 $ 0.99 $ 0.41 $ (1.80 ) Earnings (losses) attributable to Sempra Energy $ 1.76 $ 1.03 $ 0.23 $ (1.99 ) Weighted-average common shares outstanding 251.1 251.4 251.7 251.9 Diluted per-share amounts (1)(2) : Net income (loss) $ 1.79 $ 0.98 $ 0.41 $ (1.80 ) Earnings (losses) attributable to Sempra Energy $ 1.75 $ 1.03 $ 0.22 $ (1.99 ) Weighted-average common shares outstanding 252.2 252.8 253.4 251.9 2016: Revenues $ 2,622 $ 2,156 $ 2,535 $ 2,870 Expenses and other income $ 2,167 $ 2,268 $ 1,553 $ 2,365 Net income $ 364 $ 27 $ 719 $ 409 Earnings attributable to Sempra Energy $ 353 $ 16 $ 622 $ 379 Basic per-share amounts (1) : Net income $ 1.46 $ 0.11 $ 2.87 $ 1.63 Earnings attributable to Sempra Energy $ 1.41 $ 0.06 $ 2.48 $ 1.51 Weighted-average common shares outstanding 249.7 250.1 250.4 250.6 Diluted per-share amounts (1) : Net income $ 1.45 $ 0.11 $ 2.85 $ 1.62 Earnings attributable to Sempra Energy $ 1.40 $ 0.06 $ 2.46 $ 1.51 Weighted-average common shares outstanding 251.5 252.0 252.4 251.6 (1) Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year. (2) In the quarter ended December 31, 2017, the total weighted-average number of potentially dilutive securities was 0.8 million . However, these securities were not included in the computation of U.S. GAAP losses per common share since to do so would have decreased the loss per share.

SUBSEQUENT EVENTS (Tables)

SUBSEQUENT EVENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Schedule of Conversion Rates of Convertible Debt Issued	The following table illustrates the conversion rate per share of the mandatory convertible preferred stock, subject to certain anti-dilution adjustments: CONVERSION RATES Applicable market value per share of Conversion rate (number of shares of our common stock to be received upon conversion of each share of mandatory convertible preferred stock) Greater than $131.075 (which is the threshold appreciation price) 0.7629 shares (approximately equal to $100.00 divided by the threshold appreciation price) Equal to or less than $131.075 but greater than or equal to $107.00 Between 0.7629 and 0.9345 shares, determined by dividing $100.00 by the applicable market value of our common stock Less than $107.00 (which is the initial price) 0.9345 shares (approximately equal to $100.00 divided by the initial price)
Schedule of Debt Issued	The following tables show the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 SDG&E First mortgage bonds (collateralized by plant assets): Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017 $ — $ 140 1.65% July 1, 2018 (1) 161 161 3% August 15, 2021 350 350 1.914% payable 2015 through February 2022 161 197 3.6% September 1, 2023 450 450 2.5% May 15, 2026 500 500 6% June 1, 2026 250 250 5.875% January and February 2034 (1) 176 176 5.35% May 15, 2035 250 250 6.125% September 15, 2037 250 250 4% May 1, 2039 (1) 75 75 6% June 1, 2039 300 300 5.35% May 15, 2040 250 250 4.5% August 15, 2040 500 500 3.95% November 15, 2041 250 250 4.3% April 1, 2042 250 250 3.75% June 1, 2047 400 — 4,573 4,349 Other long-term debt: OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007), payable 2013 through April 2019 (collateralized by OMEC plant assets) 295 305 Capital lease obligations: Purchased-power contracts 731 239 Other 1 1 1,027 545 5,600 4,894 Current portion of long-term debt (220 ) (191 ) Unamortized discount on long-term debt (11 ) (11 ) Unamortized debt issuance costs (34 ) (34 ) Total SDG&E 5,335 4,658 SoCalGas First mortgage bonds (collateralized by plant assets): 5.45% April 15, 2018 250 250 1.55% June 15, 2018 250 250 3.15% September 15, 2024 500 500 3.2% June 15, 2025 350 350 2.6% June 15, 2026 500 500 5.75% November 15, 2035 250 250 5.125% November 15, 2040 300 300 3.75% September 15, 2042 350 350 4.45% March 15, 2044 250 250 3,000 3,000 Other long-term debt (uncollateralized): 1.875% Notes payable 2016 through May 2026 (1) 4 4 5.67% Notes January 18, 2028 5 5 Capital lease obligations 1 — 10 9 3,010 3,009 Current portion of long-term debt (501 ) — Unamortized discount on long-term debt (7 ) (7 ) Unamortized debt issuance costs (17 ) (20 ) Total SoCalGas 2,485 2,982 LONG-TERM DEBT (CONTINUED) (Dollars in millions) December 31, 2017 2016 Sempra Energy Other long-term debt (uncollateralized): 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease (2) 138 137 Sempra South American Utilities Other long-term debt (uncollateralized): Chilquinta Energía – 4.25% Series B Bonds October 30, 2030 205 185 Luz del Sur Bank loans 5.18% to 6.7% payable 2016 through December 2018 53 75 Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029 415 346 Other bonds at 3.77% to 4.61% payable 2020 through May 2022 6 7 Capital lease obligations 6 6 Sempra Mexico Other long-term debt (uncollateralized unless otherwise noted): Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency swaps effective 2013) 66 63 6.3% Notes February 2, 2023 (4.12% after cross-currency swap) 198 189 Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014), payable 2016 through December 2026, collateralized by plant assets 314 352 3.75% Notes January 14, 2028 300 — Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates (weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets 468 481 4.875% Notes January 14, 2048 540 — Sempra Renewables Other long-term debt (collateralized by project assets): Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028 except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012 (1) 77 84 Sempra LNG & Midstream Other long-term debt (uncollateralized unless otherwise noted): Notes at 2.87% to 3.51% October 1, 2026 (1) 20 20 8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee — 6 9,405 7,548 Current portion of long-term debt (706 ) (722 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized premium on long-term debt 4 4 Unamortized debt issuance costs (65 ) (31 ) Total other Sempra Energy 8,625 6,789 Total Sempra Energy Consolidated $ 16,445 $ 14,429 (1) Callable long-term debt not subject to make-whole provisions. (2) We discuss this lease in Note 15. On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses): NOTES ISSUED IN LONG-TERM DEBT OFFERING (Dollars in millions) Title of each class of securities Aggregate principal amount Maturity Interest payments Floating Rate (1) Notes due 2019 $ 500 July 15, 2019 Quarterly Floating Rate (2) Notes due 2021 700 January 15, 2021 Quarterly 2.400% Senior Notes due 2020 500 February 1, 2020 Semi-annually 2.900% Senior Notes due 2023 500 February 1, 2023 Semi-annually 3.400% Senior Notes due 2028 1,000 February 1, 2028 Semi-annually 3.800% Senior Notes due 2038 1,000 February 1, 2038 Semi-annually 4.000% Senior Notes due 2048 800 February 1, 2048 Semi-annually (1) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points. (2) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points. The following table shows the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease 138 137 6,737 5,734 Current portion of long-term debt (500 ) (600 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized debt issuance costs (26 ) (24 ) Total long-term debt $ 6,198 $ 5,100

SCHEDULE I, CONDENSED FINANCI48

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Statements of Operations	SEMPRA ENERGY CONDENSED STATEMENTS OF OPERATIONS (Dollars in millions, except per share amounts) Years ended December 31, 2017 2016 2015 Interest expense $ (293 ) $ (277 ) $ (261 ) Operation and maintenance (87 ) (81 ) (66 ) Other income (expense), net 107 (2 ) 7 Income tax benefit 33 181 150 Loss before equity in earnings of subsidiaries (240 ) (179 ) (170 ) Equity in earnings of subsidiaries, net of income taxes 496 1,549 1,519 Net income/earnings $ 256 $ 1,370 $ 1,349 Basic earnings per common share $ 1.02 $ 5.48 $ 5.43 Weighted-average number of shares outstanding (thousands) 251,545 250,217 248,249 Diluted earnings per common share $ 1.01 $ 5.46 $ 5.37 Weighted-average number of shares outstanding (thousands) 252,300 251,155 250,923
Schedule Of Condensed Statements Of Comprehensive Income	SEMPRA ENERGY CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Dollars in millions) Years ended December 31, Pretax amount Income tax benefit (expense) Net-of-tax amount 2017: Net income $ 223 $ 33 $ 256 Other comprehensive income (loss): Foreign currency translation adjustments 107 — 107 Financial instruments 2 1 3 Pension and other postretirement benefits 20 (8 ) 12 Total other comprehensive income 129 (7 ) 122 Comprehensive income $ 352 $ 26 $ 378 2016: Net income $ 1,189 $ 181 $ 1,370 Other comprehensive income (loss): Foreign currency translation adjustments 42 — 42 Financial instruments (6 ) 11 5 Pension and other postretirement benefits (13 ) 4 (9 ) Total other comprehensive income 23 15 38 Comprehensive income $ 1,212 $ 196 $ 1,408 2015: Net income $ 1,199 $ 150 $ 1,349 Other comprehensive income (loss): Foreign currency translation adjustments (260 ) — (260 ) Financial instruments (80 ) 33 (47 ) Pension and other postretirement benefits (3 ) 1 (2 ) Total other comprehensive loss (343 ) 34 (309 ) Comprehensive income $ 856 $ 184 $ 1,040
Schedule Of Condensed Balance Sheets	SEMPRA ENERGY CONDENSED BALANCE SHEETS (Dollars in millions) December 31, December 31, Assets: Cash and cash equivalents $ 104 $ 12 Due from affiliates 83 73 Income taxes receivable 272 — Other current assets 6 2 Total current assets 465 87 Investments in subsidiaries 17,924 17,329 Due from affiliates 2 — Deferred income taxes 1,802 2,570 Other assets 656 592 Total assets $ 20,849 $ 20,578 Liabilities and shareholders’ equity: Current portion of long-term debt $ 500 $ 600 Due to affiliates 280 359 Income taxes payable — 153 Other current liabilities 396 374 Total current liabilities 1,176 1,486 Long-term debt 6,198 5,100 Due to affiliates 300 517 Other long-term liabilities 505 524 Commitments and contingencies (Note 4) Shareholders’ equity 12,670 12,951 Total liabilities and shareholders’ equity $ 20,849 $ 20,578
Schedule of Condensed Statements of Cash Flows	SEMPRA ENERGY CONDENSED STATEMENTS OF CASH FLOWS (Dollars in millions) Years ended December 31, 2017 2016 (1) 2015 (1) Net cash provided by (used in) operating activities $ 89 $ (3 ) $ 95 Expenditures for property, plant and equipment (11 ) (5 ) (43 ) Purchase of trust assets — — (5 ) Decrease (increase) in loans to affiliates, net — 457 (457 ) Expenditures for Merger-related transaction costs (12 ) — — Net cash (used in) provided by investing activities (23 ) 452 (505 ) Common stock dividends paid (755 ) (686 ) (628 ) Issuances of common stock 47 51 52 Repurchases of common stock (15 ) (56 ) (74 ) Issuances of long-term debt 1,595 499 1,248 Payments on long-term debt (600 ) (750 ) — (Decrease) increase in loans from affiliates, net (239 ) 504 (230 ) Tax benefit related to share-based compensation — — 52 Other (7 ) (3 ) (9 ) Net cash provided by (used in) financing activities 26 (441 ) 411 Increase in cash and cash equivalents 92 8 1 Cash and cash equivalents, January 1 12 4 3 Cash and cash equivalents, December 31 $ 104 $ 12 $ 4 SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES Accrued Merger-related transaction costs $ 31 $ — $ — Financing of build-to-suit property — — 61 Common dividends issued in stock 53 53 55 Dividends declared but not paid 207 189 174 (1) As adjusted for the retrospective adoption of ASU 2016-15, which we discuss in Note 2.
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Consolidated Statements of Operations: Operation and maintenance $ 3,117 $ 3,096 $ 2,970 $ 2,976 Other income, net 254 233 132 138 SDG&E Consolidated Statements of Operations: Operation and maintenance $ 1,020 $ 1,024 $ 1,048 $ 1,062 Operating income 713 709 990 976 Other income, net 66 70 50 64 SoCalGas Statements of Operations: Operation and maintenance $ 1,479 $ 1,474 $ 1,385 $ 1,391 Operating income 622 627 557 551 Other income, net 36 31 32 38 The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows: IMPACT FROM ADOPTION OF ASU 2016-15 (Dollars in millions) Years ended December 31, 2016 2015 As previously reported Effect of adoption As adjusted As previously reported Effect of adoption As adjusted Sempra Energy Condensed Statements of Cash Flows: Cash flows from operating activities: Net cash (used in) provided by operating activities $ (178 ) $ 175 $ (3 ) $ (255 ) $ 350 $ 95 Cash flows from investing activities: Dividends received from subsidiaries (1) 175 (175 ) — 350 (350 ) — Net cash provided by (used in) investing activities 627 (175 ) 452 (155 ) (350 ) (505 ) (1) Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow. In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016: EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07 (Dollars in millions) Years ended December 31, 2017 2016 As reported Recast As reported Recast Sempra Energy Condensed Statements of Operations: Operation and maintenance $ (87 ) $ (80 ) $ (81 ) $ (76 ) Other income (expense), net 107 100 (2 ) (7 )
Schedule Of Long-term Debt	The following tables show the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 SDG&E First mortgage bonds (collateralized by plant assets): Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017 $ — $ 140 1.65% July 1, 2018 (1) 161 161 3% August 15, 2021 350 350 1.914% payable 2015 through February 2022 161 197 3.6% September 1, 2023 450 450 2.5% May 15, 2026 500 500 6% June 1, 2026 250 250 5.875% January and February 2034 (1) 176 176 5.35% May 15, 2035 250 250 6.125% September 15, 2037 250 250 4% May 1, 2039 (1) 75 75 6% June 1, 2039 300 300 5.35% May 15, 2040 250 250 4.5% August 15, 2040 500 500 3.95% November 15, 2041 250 250 4.3% April 1, 2042 250 250 3.75% June 1, 2047 400 — 4,573 4,349 Other long-term debt: OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007), payable 2013 through April 2019 (collateralized by OMEC plant assets) 295 305 Capital lease obligations: Purchased-power contracts 731 239 Other 1 1 1,027 545 5,600 4,894 Current portion of long-term debt (220 ) (191 ) Unamortized discount on long-term debt (11 ) (11 ) Unamortized debt issuance costs (34 ) (34 ) Total SDG&E 5,335 4,658 SoCalGas First mortgage bonds (collateralized by plant assets): 5.45% April 15, 2018 250 250 1.55% June 15, 2018 250 250 3.15% September 15, 2024 500 500 3.2% June 15, 2025 350 350 2.6% June 15, 2026 500 500 5.75% November 15, 2035 250 250 5.125% November 15, 2040 300 300 3.75% September 15, 2042 350 350 4.45% March 15, 2044 250 250 3,000 3,000 Other long-term debt (uncollateralized): 1.875% Notes payable 2016 through May 2026 (1) 4 4 5.67% Notes January 18, 2028 5 5 Capital lease obligations 1 — 10 9 3,010 3,009 Current portion of long-term debt (501 ) — Unamortized discount on long-term debt (7 ) (7 ) Unamortized debt issuance costs (17 ) (20 ) Total SoCalGas 2,485 2,982 LONG-TERM DEBT (CONTINUED) (Dollars in millions) December 31, 2017 2016 Sempra Energy Other long-term debt (uncollateralized): 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease (2) 138 137 Sempra South American Utilities Other long-term debt (uncollateralized): Chilquinta Energía – 4.25% Series B Bonds October 30, 2030 205 185 Luz del Sur Bank loans 5.18% to 6.7% payable 2016 through December 2018 53 75 Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029 415 346 Other bonds at 3.77% to 4.61% payable 2020 through May 2022 6 7 Capital lease obligations 6 6 Sempra Mexico Other long-term debt (uncollateralized unless otherwise noted): Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency swaps effective 2013) 66 63 6.3% Notes February 2, 2023 (4.12% after cross-currency swap) 198 189 Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014), payable 2016 through December 2026, collateralized by plant assets 314 352 3.75% Notes January 14, 2028 300 — Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates (weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets 468 481 4.875% Notes January 14, 2048 540 — Sempra Renewables Other long-term debt (collateralized by project assets): Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028 except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012 (1) 77 84 Sempra LNG & Midstream Other long-term debt (uncollateralized unless otherwise noted): Notes at 2.87% to 3.51% October 1, 2026 (1) 20 20 8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee — 6 9,405 7,548 Current portion of long-term debt (706 ) (722 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized premium on long-term debt 4 4 Unamortized debt issuance costs (65 ) (31 ) Total other Sempra Energy 8,625 6,789 Total Sempra Energy Consolidated $ 16,445 $ 14,429 (1) Callable long-term debt not subject to make-whole provisions. (2) We discuss this lease in Note 15. On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses): NOTES ISSUED IN LONG-TERM DEBT OFFERING (Dollars in millions) Title of each class of securities Aggregate principal amount Maturity Interest payments Floating Rate (1) Notes due 2019 $ 500 July 15, 2019 Quarterly Floating Rate (2) Notes due 2021 700 January 15, 2021 Quarterly 2.400% Senior Notes due 2020 500 February 1, 2020 Semi-annually 2.900% Senior Notes due 2023 500 February 1, 2023 Semi-annually 3.400% Senior Notes due 2028 1,000 February 1, 2028 Semi-annually 3.800% Senior Notes due 2038 1,000 February 1, 2038 Semi-annually 4.000% Senior Notes due 2048 800 February 1, 2048 Semi-annually (1) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points. (2) Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points. The following table shows the detail and maturities of long-term debt outstanding: LONG-TERM DEBT (Dollars in millions) December 31, 2017 2016 2.3% Notes April 1, 2017 $ — $ 600 6.15% Notes June 15, 2018 500 500 9.8% Notes February 15, 2019 500 500 1.625% Notes October 7, 2019 500 500 2.4% Notes March 15, 2020 500 500 2.85% Notes November 15, 2020 400 400 Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 850 — 2.875% Notes October 1, 2022 500 500 4.05% Notes December 1, 2023 500 500 3.55% Notes June 15, 2024 500 500 3.75% Notes November 15, 2025 350 350 3.25% Notes June 15, 2027 750 — 6% Notes October 15, 2039 750 750 Fair value adjustments for interest rate swaps, net (1 ) (3 ) Build-to-suit lease 138 137 6,737 5,734 Current portion of long-term debt (500 ) (600 ) Unamortized discount on long-term debt (13 ) (10 ) Unamortized debt issuance costs (26 ) (24 ) Total long-term debt $ 6,198 $ 5,100

SIGNIFICANT ACCOUNTING POLICI49

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - PRINCIPLES OF CONSOLIDATION (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets, Current [Abstract]
Regulatory assets	$ 325	$ 348	[1]
Greenhouse gas allowances	299	40	[1]
Regulatory balancing accounts – undercollected		0
Other	136	142	[1]
Other Assets [Abstract]
Regulatory assets	1,517	3,414	[1]
Greenhouse gas allowances	93	295	[1]
Sundry	792	520	[1]
Liabilities, Current [Abstract]
Regulatory liabilities	109	122	[1]
Greenhouse gas obligations	299	40	[1]
Regulatory balancing accounts – overcollected		0
Other	545	517	[1]
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities	3,922	2,876	[1]
Greenhouse gas obligations	0	171	[1]
Regulatory liabilities arising from removal obligations		0
Deferred credits and other	1,136	1,173	[1]
As previously reported [Member]
Assets, Current [Abstract]
Regulatory assets		0
Greenhouse gas allowances		0
Regulatory balancing accounts – undercollected		259
Other		271
Other Assets [Abstract]
Greenhouse gas allowances		0
Sundry		815
Liabilities, Current [Abstract]
Regulatory liabilities		0
Greenhouse gas obligations		0
Regulatory balancing accounts – overcollected		122
Other		557
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities		0
Greenhouse gas obligations		0
Regulatory liabilities arising from removal obligations		2,697
Deferred credits and other		1,523
San Diego Gas and Electric Company [Member]
Assets, Current [Abstract]
Regulatory assets	316	340	[1]
Greenhouse gas allowances	116	16	[1]
Regulatory balancing accounts – undercollected		0
Other	4	3	[1]
Other Assets [Abstract]
Regulatory assets	451	2,012	[1]
Greenhouse gas allowances	83	182	[1]
Deferred taxes recoverable in rates		0
Other regulatory assets		0
Sundry	328	176	[1]
Liabilities, Current [Abstract]
Regulatory liabilities	18	0	[1]
Greenhouse gas obligations	116	16	[1]
Other	46	66	[1]
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities	2,225	1,725	[1]
Greenhouse gas obligations	0	72	[1]
Regulatory liabilities arising from removal obligations		0
Deferred credits and other	334	349	[1]
San Diego Gas and Electric Company [Member] | As previously reported [Member]
Assets, Current [Abstract]
Regulatory assets		81
Greenhouse gas allowances		0
Regulatory balancing accounts – undercollected		259
Other		19
Other Assets [Abstract]
Regulatory assets		0
Greenhouse gas allowances		0
Deferred taxes recoverable in rates		1,014
Other regulatory assets		998
Sundry		358
Liabilities, Current [Abstract]
Greenhouse gas obligations		0
Other		82
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities		0
Greenhouse gas obligations		0
Regulatory liabilities arising from removal obligations		1,725
Deferred credits and other		421
Southern California Gas Company [Member]
Assets, Current [Abstract]
Regulatory assets	9	8	[1]
Greenhouse gas allowances	179	24	[1]
Other	38	39	[1]
Other Assets [Abstract]
Regulatory assets	983	1,331	[1]
Greenhouse gas allowances	9	109	[1]
Regulatory assets arising from pension obligations		0
Other regulatory assets		0
Sundry	364	290	[1]
Liabilities, Current [Abstract]
Regulatory liabilities	91	122	[1]
Greenhouse gas obligations	179	24	[1]
Regulatory balancing accounts – overcollected		0
Other	205	171	[1]
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities	1,697	1,151	[1]
Greenhouse gas obligations	0	96	[1]
Regulatory liabilities arising from removal obligations		0
Deferred credits and other	$ 253	246	[1]
Southern California Gas Company [Member] | As previously reported [Member]
Assets, Current [Abstract]
Greenhouse gas allowances		0
Other		63
Other Assets [Abstract]
Regulatory assets		0
Greenhouse gas allowances		0
Regulatory assets arising from pension obligations		742
Other regulatory assets		589
Sundry		399
Liabilities, Current [Abstract]
Regulatory liabilities		0
Greenhouse gas obligations		0
Regulatory balancing accounts – overcollected		122
Other		195
Deferred Credits and Other Liabilities [Abstract]
Regulatory liabilities		0
Greenhouse gas obligations		0
Regulatory liabilities arising from removal obligations		972
Deferred credits and other		$ 521
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI50

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - CASH, CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[2]	Dec. 31, 2014	[2]
Presentation Of Restricted Cash [Line Items]
Restricted cash	$ 76	$ 76
Cash and cash equivalents	288	349	[1]
Restricted cash, current	62	66	[1]
Restricted cash, noncurrent	14	10	[1]
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	364	425	[2]	$ 450		$ 610
SDG&E [Member]
Presentation Of Restricted Cash [Line Items]
Restricted cash	17	12
Sempra Mexico [Member]
Presentation Of Restricted Cash [Line Items]
Restricted cash	56	61
Sempra Renewables [Member]
Presentation Of Restricted Cash [Line Items]
Restricted cash	3	3
San Diego Gas and Electric Company [Member]
Presentation Of Restricted Cash [Line Items]
Cash and cash equivalents	12	8	[1]
Restricted cash, current	6	11	[1]
Restricted cash, noncurrent	11	1	[1]
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$ 29	$ 20	[2]	$ 43		$ 27
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.
[2]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SIGNIFICANT ACCOUNTING POLICI51

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - COLLECTION ALLOWANCES (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance balance at January 1	$ 35	$ 32	$ 34
Provisions for uncollectible accounts	16	23	20
Write-offs of uncollectible accounts	(18)	(20)	(22)
Allowance balance at December 31	33	35	32
San Diego Gas and Electric Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance balance at January 1	8	9	7
Provisions for uncollectible accounts	8	6	7
Write-offs of uncollectible accounts	(7)	(7)	(5)
Allowance balance at December 31	9	8	9
Southern California Gas Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance balance at January 1	21	17	17
Provisions for uncollectible accounts	4	14	11
Write-offs of uncollectible accounts	(9)	(10)	(11)
Allowance balance at December 31	$ 16	$ 21	$ 17

SIGNIFICANT ACCOUNTING POLICI52

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - INVENTORIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2017
Inventory [Line Items]
Natural gas	$ 92		$ 109
LNG	9		11
Materials and supplies	157		187
Inventories	258	[1]	307
SDG&E [Member]
Inventory [Line Items]
Natural gas	2		4
LNG	0		0
Materials and supplies	78		101
Inventories	80		105
SoCalGas [Member]
Inventory [Line Items]
LIFO liquidation	33
Natural gas	11		75
LNG	0		0
Materials and supplies	47		49
Inventories	58		124
Sempra South American Utilities [Member]
Inventory [Line Items]
Natural gas	0		0
LNG	0		0
Materials and supplies	27		30
Inventories	27		30
Sempra Mexico [Member]
Inventory [Line Items]
Natural gas	0		0
LNG	6		7
Materials and supplies	1		2
Inventories	7		9
Sempra Renewables [Member]
Inventory [Line Items]
Natural gas	0		0
LNG	0		0
Materials and supplies	4		5
Inventories	4		5
Sempra LNG & Midstream [Member]
Inventory [Line Items]
Natural gas	79		30
LNG	3		4
Materials and supplies	0		0
Inventories	$ 82		$ 34
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI53

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 48,108	$ 43,624	[1]
Depreciation	1,422	1,236		$ 1,178
Accumulated depreciation	11,605	10,693	[1]
San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	19,787	17,844	[1]
Depreciation	621	583		544
Accumulated depreciation	4,949	4,594	[1]
Southern California Gas Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	16,772	15,344	[1]
Depreciation	514	474		$ 459
Accumulated depreciation	5,366	5,092	[1]
Natural gas operations [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,186	$ 1,897
Depreciation rates (percentage)	2.40%	2.40%		2.52%
Accumulated depreciation	$ 756	$ 721
Natural gas operations [Member] | Southern California Gas Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 15,759	$ 14,428
Depreciation rates (percentage)	3.63%	3.64%		3.83%
Capital leased assets	$ 34	$ 32
Accumulated depreciation	5,352	5,079
Accumulated depreciation of capital leased assets	33	31
Electric distribution [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 6,975	$ 6,497
Depreciation rates (percentage)	3.92%	3.86%		3.79%
Accumulated depreciation	$ 4,193	$ 3,873
Accumulated depreciation of capital leased assets	47	39
Electric transmission [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,626	$ 5,152
Depreciation rates (percentage)	2.71%	2.66%		2.62%
Electric generation [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,435	$ 1,932
Depreciation rates (percentage)	4.05%	4.00%		3.89%
Capital leased assets	$ 757	$ 258
Other electric [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,114	$ 1,059
Depreciation rates (percentage)	5.54%	5.66%		5.73%
Capital leased assets	$ 22	$ 21
Other non-utility [Member] | Southern California Gas Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 32	$ 34
Depreciation rates (percentage)	5.28%	6.55%		3.95%
Accumulated depreciation	$ 14	$ 13
Other non-utility [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	972	755
Construction work in progress [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,451	1,307
Construction work in progress [Member] | Southern California Gas Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	981	882
Land and land rights [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 416	381
Land and land rights [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	22 years
Land and land rights [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	55 years
Land and land rights [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	33 years
Utility electric distribution operations [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,751	1,519
Accumulated depreciation	$ 318	252
Utility electric distribution operations [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	12 years
Utility electric distribution operations [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	60 years
Utility electric distribution operations [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	52 years
Generating plants [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,242	1,874
Generating plants [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
Generating plants [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	100 years
Generating plants [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	31 years
LNG terminals [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,133	1,129
LNG terminals [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	43 years
LNG terminals [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	43 years
LNG terminals [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	43 years
Pipelines and storage [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 4,408	3,242
Pipelines and storage [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Pipelines and storage [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	55 years
Pipelines and storage [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	43 years
Other [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 269	235
Other [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	1 year
Other [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	50 years
Other [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	13 years
Construction work in progress [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 691	1,488
Other [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	639	568
Capital leased assets	$ 136	136
Other [Member] | Minimum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	1 year
Other [Member] | Maximum [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	80 years
Other [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	33 years
Plant, pipeline and other distribution assets of ecogas [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	$ 39	33
Plant, pipeline and other distribution assets of ecogas [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	145	128
Total Other Operating Units And Parent [Member] | Other Operating Units and Parent [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	11,549	10,436
Accumulated depreciation	1,290	$ 1,007
Southwest Powerlink (SWPL) transmission line [Member] | Electric transmission [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 440
Ownership interest	92.00%
Accumulated depreciation	$ 241
Southwest Powerlink (SWPL) transmission line [Member] | Construction work in progress [Member] | San Diego Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 29
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI54

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - CAPITALIZED FINANCING COSTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Financing Costs Disclosure [Line Items]
Total capitalized financing costs	$ 256	$ 236	$ 201
San Diego Gas and Electric Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
Total capitalized financing costs	85	62	51
Southern California Gas Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
Total capitalized financing costs	$ 60	$ 55	$ 49

SIGNIFICANT ACCOUNTING POLICI55

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - GOODWILL (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 2,364,000,000	[1]	$ 819,000,000
Acquisition of businesses			1,590,000,000
Sale of business			(72,000,000)
Acquisition of business – measurement period adjustment	(13,000,000)
Foreign currency translation	46,000,000		27,000,000
Goodwill, ending balance	2,397,000,000		2,364,000,000	[1]
Sempra South American Utilities [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	749,000,000		722,000,000
Acquisition of businesses			0
Sale of business			0
Acquisition of business – measurement period adjustment	0
Foreign currency translation	46,000,000		27,000,000
Goodwill, ending balance	795,000,000		749,000,000
Sempra Mexico [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	1,615,000,000		25,000,000
Acquisition of businesses			1,590,000,000
Sale of business			0
Acquisition of business – measurement period adjustment	(13,000,000)
Foreign currency translation	0		0
Goodwill, ending balance	1,602,000,000		1,615,000,000
Sempra LNG & Midstream [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	0		72,000,000
Acquisition of businesses			0
Sale of business			(72,000,000)
Acquisition of business – measurement period adjustment	0
Foreign currency translation	0		0
Goodwill, ending balance	$ 0		$ 0
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI56

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	$ 698	$ 632
Accumulated amortization	(102)	(84)
Finite-lived intangible assets, Net	596	548
Intangible assets amortization expense	18	11	$ 10
Future intangible asset amortization expense per year	21
Development rights [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	322	322
Accumulated amortization	$ (60)	(53)
Amortization period	50 years
Renewable energy and consumption permit [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	$ 154	154
Accumulated amortization	$ (8)	0
Amortization period	19 years
Storage rights [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	$ 138	138
Accumulated amortization	$ (28)	(25)
Amortization period	46 years
O&M agreement [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	$ 66	0
Amortization period	23 years
Other [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible assets, Gross	$ 18	18
Accumulated amortization	$ (6)	$ (6)
Other [Member] | Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization period	10 years

SIGNIFICANT ACCOUNTING POLICI57

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - VARIABLE INTEREST ENTITIES (Details) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)		Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Investments [Abstract]
Equity method investment	$ 2,517				$ 2,080					$ 2,517	$ 2,080
Assets [Abstract]
Cash and cash equivalents	288				349	[1]				288	349	[1]
Restricted cash	62				66	[1]				62	66	[1]
Inventories	307				258	[1]				307	258	[1]
Other	136				142	[1]				136	142	[1]
Total current assets	3,341				3,110	[1]				3,341	3,110	[1]
Sundry	792				520	[1]				792	520	[1]
Restricted cash	14				10	[1]				14	10	[1]
Property, plant and equipment, net	36,503				32,931	[1]				36,503	32,931	[1]
Total assets	50,454				47,786	[1]				50,454	47,786	[1]	$ 41,150
Liabilities [Abstract]
Current portion of long-term debt	1,427				913	[1]				1,427	913	[1]
Fixed-price contracts and other derivatives	109				83	[1]				109	83	[1]
Other	545				517	[1]				545	517	[1]
Total current liabilities	6,635				5,927	[1]				6,635	5,927	[1]
Asset retirement obligations	2,732				2,431	[1]				2,732	2,431	[1]
Deferred income taxes	2,767				3,745	[1]				2,767	3,745	[1]
Long-term debt	16,445				14,429	[1]				16,445	14,429	[1]
Fixed-price contracts and other derivatives	316				405	[1]				316	405	[1]
Equity [Abstract]
Other noncontrolling interests	2,450				2,270	[1]				2,450	2,270	[1]
Total liabilities and equity	50,454				47,786	[1]				50,454	47,786	[1]
Net assets less other noncontrolling interests	12,670				12,951	[1]				12,670	12,951	[1]
Operating Expenses [Abstract]
Energy-related businesses										1,431	922		977
Operation and maintenance										(3,117)	(2,970)		(2,886)
Depreciation and amortization										(1,490)	(1,312)	[2]	(1,250)	[2]
Income before income taxes										1,585	1,830		1,704
Other income, net										254	132		126
Interest expense										(659)	(553)		(561)
Income tax expense										(1,276)	(389)		(341)
Net income										351	1,519	[2]	1,448	[2]
(Earnings) losses attributable to noncontrolling interest										(94)	(148)		(98)
Earnings attributable to common shares	(501)	$ 57	$ 259	$ 441	379		$ 622	$ 16	$ 353	256	1,370		1,349
San Diego Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Gross long-term debt	4,573				4,349					4,573	4,349
Assets [Abstract]
Cash and cash equivalents	12				8	[1]				12	8	[1]
Restricted cash	6				11	[1]				6	11	[1]
Inventories	105				80	[1]				105	80	[1]
Other	4				3	[1]				4	3	[1]
Total current assets	1,100				1,072	[1]				1,100	1,072	[1]
Sundry	328				176	[1]				328	176	[1]
Restricted cash	11				1	[1]				11	1	[1]
Property, plant and equipment, net	14,838				13,250	[1]				14,838	13,250	[1]
Total assets	17,844				17,719	[1]				17,844	17,719	[1]
Liabilities [Abstract]
Current portion of long-term debt	220				191	[1]				220	191	[1]
Fixed-price contracts and other derivatives	60				61	[1]				60	61	[1]
Other	46				66	[1]				46	66	[1]
Total current liabilities	1,622				1,168	[1]				1,622	1,168	[1]
Asset retirement obligations	762				751	[1]				762	751	[1]
Deferred income taxes	1,530				2,829	[1]				1,530	2,829	[1]
Long-term debt	5,335				4,658	[1]				5,335	4,658	[1]
Fixed-price contracts and other derivatives	153				189	[1]				153	189	[1]
Equity [Abstract]
Other noncontrolling interests	28				37	[1]				28	37	[1]
Total liabilities and equity	17,844				17,719	[1]				17,844	17,719	[1]
Net assets less other noncontrolling interests	5,598				5,641	[1]				5,598	5,641	[1]
Operating Expenses [Abstract]
Income before income taxes										576	845		890
Operating income										713	990		1,058
Other income, net										66	50		36
Interest expense										(203)	(195)		(204)
Income tax expense										(155)	(280)		(284)
Net income										421	565	[2]	606	[2]
(Earnings) losses attributable to noncontrolling interest										$ (14)	5		(19)
San Diego Gas and Electric Company [Member] | Otay Mesa VIE [Member]
Variable Interest Entity [Line Items]
Generating capacity (in mw) | MW										605
Put option	280									$ 280
Investments [Abstract]
Equity of Variable interest entity	28				37					28	37
Assets [Abstract]
Cash and cash equivalents	4				6					4	6
Restricted cash	6				11					6	11
Inventories	4				3					4	3
Other	1				2					1	2
Total current assets	15				22					15	22
Restricted cash	11				1					11	1
Property, plant and equipment, net	321				354					321	354
Total assets	347				377					347	377
Liabilities [Abstract]
Current portion of long-term debt	10				10					10	10
Fixed-price contracts and other derivatives	10				13					10	13
Other	5				5					5	5
Total current liabilities	25				28					25	28
Long-term debt	284				293					284	293
Fixed-price contracts and other derivatives	3				12					3	12
Deferred credits and other	7				7					7	7
Equity [Abstract]
Other noncontrolling interests	28				37					28	37
Total liabilities and equity	347				377					347	377
Operating Expenses [Abstract]
Cost of electric fuel and purchased power										(79)	(79)		(83)
Operation and maintenance										(17)	(29)		(19)
Depreciation and amortization										(28)	(35)		(26)
Total operating expenses										(34)	(15)		(38)
Operating income										34	15		38
Other income, net										2	0		0
Interest expense										(22)	(20)		(19)
Net income										14	(5)		19
(Earnings) losses attributable to noncontrolling interest										(14)	5		(19)
Earnings attributable to common shares										0	0		$ 0
Sempra Renewables [Member]
Assets [Abstract]
Inventories	5				4					5	4
Sempra Renewables [Member] | Noncontrolling Tax Equity Investors [Member]
Assets [Abstract]
Cash and cash equivalents	23				88					23	88
Accounts receivable – trade, net	5				3					5	3
Inventories	1				0					1	0
Other	1				0					1	0
Total current assets	30				91					30	91
Sundry	2				0					2	0
Property, plant and equipment, net	1,412				926					1,412	926
Total assets	1,444				1,017					1,444	1,017
Liabilities [Abstract]
Accounts payable	42				68					42	68
Other	1				7					1	7
Total current liabilities	43				75					43	75
Asset retirement obligations	40				27					40	27
Deferred income taxes	10				0					10	0
Deferred credits and other	1				0					1	0
Total liabilities	94				102					94	102
Equity [Abstract]
Other noncontrolling interests	631				468					631	468
Net assets less other noncontrolling interests	719				447					719	447
Operating Expenses [Abstract]
Energy-related businesses										61	2
Operation and maintenance										(9)	(1)
Depreciation and amortization										(32)	0
Income before income taxes										20	1
Income tax expense										(4)	0
Net income										16	1
(Earnings) losses attributable to noncontrolling interest										(23)	(4)
Earnings attributable to common shares										39	5
Sempra LNG & Midstream [Member]
Assets [Abstract]
Inventories	34				82					34	82
Sempra LNG & Midstream [Member] | Cameron LNG Holdings [Member]
Investments [Abstract]
Equity method investment	997									997
Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member] | San Diego Gas and Electric Company [Member] | Otay Mesa VIE [Member]
Variable Interest Entity [Line Items]
Gross long-term debt	$ 295				$ 305					$ 295	$ 305
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.
[2]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SIGNIFICANT ACCOUNTING POLICI58

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 2,553	$ 2,255
Accretion expense	109	101
Liabilities incurred and acquired	34	35
Deconsolidation and reclassification	0	(16)
Payments	(63)	(47)
Revisions	244	225
Ending Balance	2,877	2,553
Asset retirement obligations deconsolidated		12
Asset retirement obligations reclassified		4
San Diego Gas and Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	830	828
Accretion expense	39	38
Liabilities incurred and acquired	17	0
Deconsolidation and reclassification	0	0
Payments	(61)	(46)
Revisions	14	10
Ending Balance	839	830
Southern California Gas Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	1,659	1,383
Accretion expense	66	61
Liabilities incurred and acquired	0	0
Deconsolidation and reclassification	0	0
Payments	(2)	0
Revisions	230	215
Ending Balance	$ 1,953	$ 1,659

SIGNIFICANT ACCOUNTING POLICI59

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	$ 12,951
Amounts reclassified from AOCI		19	$ 18		$ 18
Ending Balance		12,670	12,951	[1]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Sale of noncontrolling interests, net of offering costs		196	1,701
San Diego Gas and Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	5,641
Amounts reclassified from AOCI		1	1		1
Ending Balance		5,598	5,641	[1]
Southern California Gas Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]	3,510
Amounts reclassified from AOCI		1	1		0
Ending Balance		3,907	3,510	[1]
Foreign currency translation adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(527)	(582)		(322)
OCI before reclassifications		107	42		(260)
Amounts reclassified from AOCI		0	13		0
Total other comprehensive income (loss)		107	55		(260)
Ending Balance		(420)	(527)		(582)
Financial instruments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(125)	(137)		(90)
OCI before reclassifications		(4)	(7)		(57)
Amounts reclassified from AOCI		7	19		10
Total other comprehensive income (loss)		3	12		(47)
Ending Balance		(122)	(125)		(137)
Financial instruments [Member] | Southern California Gas Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(13)	(14)		(14)
OCI before reclassifications			0		0
Amounts reclassified from AOCI		0	1
Total other comprehensive income (loss)		0	1		0
Ending Balance		(13)	(13)		(14)
Pension and other postretirement benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(96)	(87)		(85)
OCI before reclassifications		0	(15)		(10)
Amounts reclassified from AOCI		12	6		8
Total other comprehensive income (loss)		12	(9)		(2)
Ending Balance		(84)	(96)		(87)
Pension and other postretirement benefits [Member] | San Diego Gas and Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(8)	(8)		(12)
OCI before reclassifications		(1)	(1)		3
Amounts reclassified from AOCI		1	1		1
Total other comprehensive income (loss)		0	0		4
Ending Balance		(8)	(8)		(8)
Pension and other postretirement benefits [Member] | Southern California Gas Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(9)	(5)		(4)
OCI before reclassifications			(4)		(1)
Amounts reclassified from AOCI		1	0
Total other comprehensive income (loss)		1	(4)		(1)
Ending Balance		(8)	(9)		(5)
Accumulated other comprehensive income (loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(748)	(806)		(497)
OCI before reclassifications		103	20		(327)
Amounts reclassified from AOCI		19	38		18
Total other comprehensive income (loss)		122	58		(309)
Ending Balance		(626)	(748)		(806)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Sale of noncontrolling interests, net of offering costs			20
Accumulated other comprehensive income (loss) [Member] | San Diego Gas and Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(8)	(8)		(12)
OCI before reclassifications		(1)	(1)		3
Amounts reclassified from AOCI		1	1		1
Total other comprehensive income (loss)		0	0		4
Ending Balance		(8)	(8)		(8)
Accumulated other comprehensive income (loss) [Member] | Southern California Gas Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(22)	(19)		(18)
OCI before reclassifications			(4)		(1)
Amounts reclassified from AOCI		1	1
Total other comprehensive income (loss)		1	(3)		(1)
Ending Balance		$ (21)	$ (22)		$ (19)
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI60

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - RECLASSIFICATION FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									$ (659)	$ (553)	$ (561)
Gain on sale of assets									3	134	70
Equity earnings, before income tax									34	6	104
Remeasurement of equity method investment									0	617	0
Equity earnings, net of income tax									42	78	85
Other income, net									254	132	126
Energy-related businesses									1,431	922	977
Income before income taxes									1,585	1,830	1,704
Income tax (expense) benefit									(1,276)	(389)	(341)
(Earnings) losses attributable to noncontrolling interest									(94)	(148)	(98)
Net income/Earnings	$ (501)	$ 57	$ 259	$ 441	$ 379	$ 622	$ 16	$ 353	256	1,370	1,349
Reclassification from AOCI, Net of taxes									19	18	18
San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									(203)	(195)	(204)
Other income, net									66	50	36
Income before income taxes									576	845	890
Income tax (expense) benefit									(155)	(280)	(284)
(Earnings) losses attributable to noncontrolling interest									(14)	5	(19)
Reclassification from AOCI, Net of taxes									1	1	1
Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									(102)	(97)	(84)
Other income, net									36	32	30
Income before income taxes									557	493	558
Income tax (expense) benefit									(160)	(143)	(138)
Reclassification from AOCI, Net of taxes									1	1	0
Financial instruments attributable to parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									7	19	10
Financial instruments attributable to parent [Member] | Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									0	1
Amortization of actuarial loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, before taxes									18	10	14
Amortization of actuarial loss [Member] | San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									1	1	1
Amortization of prior service cost [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, before taxes									1	1	0
Amortization of prior service cost [Member] | Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									1	0	0
Pension and other postretirement benefits [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, before taxes									19	11	14
Reclassification from AOCI, Taxes									(7)	(5)	(6)
Reclassification from AOCI, Net of taxes									12	6	8
Pension and other postretirement benefits [Member] | San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									1	1	1
Pension and other postretirement benefits [Member] | Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Net of taxes									1	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes									23	33	29
Income tax (expense) benefit									(6)	(6)	(4)
Net of income tax									17	27	25
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member] | Interest rate and foreign exchange instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									(4)	17	18
Remeasurement of equity method investment									0	7	0
Equity earnings, net of income tax									12	5	13
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member] | Interest rate instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Equity earnings, before income tax									8	10	12
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member] | Interest rate instruments [Member] | San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									13	12	12
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member] | Foreign exchange instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Energy-related businesses									(2)	0	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Energy-related businesses									9	(6)	(14)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to Noncontrolling interests [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Earnings) losses attributable to noncontrolling interest									(10)	(15)	(15)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to Noncontrolling interests [Member] | San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Earnings) losses attributable to noncontrolling interest									(13)	(12)	(12)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income/Earnings									7	12	10
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to parent [Member] | San Diego Gas and Electric Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income/Earnings									0	0	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to parent [Member] | Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) benefit									0	0	(1)
Net income/Earnings									0	1	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Financial instruments attributable to parent [Member] | Interest rate instruments [Member] | Southern California Gas Company [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense									$ 0	$ 1	$ 1

SIGNIFICANT ACCOUNTING POLICI61

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - NONCONTROLLING INTERESTS (Details) $ / shares in Units, MXN in Millions, $ in Millions	Oct. 13, 2016USD ($)$ / sharesMXN / $shares	Oct. 13, 2016MXNshares	Dec. 31, 2016USD ($)facility	Dec. 31, 2017USD ($)companyfacility	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Oct. 19, 2016	Oct. 18, 2016
Noncontrolling Interest [Line Items]
Impact of issuance on equity					$ 196	$ 1,701
IEnova [Member]
Noncontrolling Interest [Line Items]
Price of shares issued (in pesos per share) | $ / shares	$ 80
Additional shares purchased | shares	83,125,000
Cash consideration (fair value of total consideration)	$ 351
Shares issued | shares	380,000,000	380,000,000
Proceeds from sale of shares	$ 1,570	MXN 29,860
Exchange rate (in pesos) | MXN / $	18.96
Ownership interest							66.40%	81.10%
IEnova [Member] | Bridge Loan [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	$ 1,150
IEnova [Member] | Related Party Debt [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	100
IEnova [Member] | Revolving Credit Facility [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	250
Ventika [Member] | IEnova [Member]
Noncontrolling Interest [Line Items]
Cash consideration (fair value of total consideration)	$ 50
Shareholders' equity [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						281
Shareholders' equity [Member] | IEnova [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						281
Non-controlling interests [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity					$ 196	1,420
Non-controlling interests [Member] | IEnova [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						$ 948
Sempra Renewables [Member] | Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of Tax Equity Limited Liability Companies Formed | company				2
Proceeds from sale of noncontrolling interests			$ 474
Solar Power Projects [Member] | Sempra Renewables [Member] | Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of facilities acquired | facility			3	4
Proceeds from sale of noncontrolling interests				$ 104
Wind Generation Projects [Member] | Sempra Renewables [Member] | Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of facilities acquired | facility				1
Proceeds from sale of noncontrolling interests				$ 92

SIGNIFICANT ACCOUNTING POLICI62

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - OTHER NONCONTROLLING INTERESTS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Other noncontrolling interests	$ 2,450	$ 2,270
SDG&E [Member] | Otay Mesa VIE [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	100.00%	100.00%
Other noncontrolling interests	$ 28	$ 37
Sempra South American Utilities [Member] | Chilquinta Energia subsidiaries [Member]
Noncontrolling Interest [Line Items]
Other noncontrolling interests	$ 24	$ 22
Sempra South American Utilities [Member] | Chilquinta Energia subsidiaries [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	22.90%	23.10%
Sempra South American Utilities [Member] | Chilquinta Energia subsidiaries [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	43.40%	43.40%
Sempra South American Utilities [Member] | Luz Del Sur [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	16.40%	16.40%
Other noncontrolling interests	$ 189	$ 173
Sempra South American Utilities [Member] | Tecsur [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	9.80%	9.80%
Other noncontrolling interests	$ 4	$ 4
Sempra Mexico [Member] | IEnova [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	33.60%	33.60%	33.60%	18.90%
Other noncontrolling interests	$ 1,532	$ 1,524
Sempra Renewables [Member] | Tax equity arrangement – wind [Member]
Noncontrolling Interest [Line Items]
Other noncontrolling interests	181	92
Sempra Renewables [Member] | Tax equity arrangement – solar [Member]
Noncontrolling Interest [Line Items]
Other noncontrolling interests	$ 450	$ 376
Sempra LNG & Midstream [Member] | Bay Gas Storage Company [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	9.10%	9.10%
Other noncontrolling interests	$ 28	$ 27
Sempra LNG & Midstream [Member] | Liberty Gas Storage [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	23.30%	23.30%
Other noncontrolling interests	$ 14	$ 14
Sempra LNG & Midstream [Member] | Southern Gas Transmission [Member]
Noncontrolling Interest [Line Items]
Ownership percentage held by noncontrolling owners	0.00%	49.00%
Other noncontrolling interests	$ 0	$ 1

SIGNIFICANT ACCOUNTING POLICI63

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - REVENUES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues Disclosure [Abstract]
Electric revenues	$ 5,415	$ 5,211	$ 5,158
Natural gas revenues	4,361	4,050	4,096
Total Utilities Revenues at Sempra Energy Consolidated	$ 9,776	$ 9,261	$ 9,254

SIGNIFICANT ACCOUNTING POLICI64

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - FOREIGN CURRENCY TRANSLATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Foreign currency transaction losses	$ 35	$ 1	$ 7

SIGNIFICANT ACCOUNTING POLICI65

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - TRANSACTIONS WITH AFFILIATES (Details) $ in Millions, MXN in Billions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)		Dec. 31, 2017MXN	Nov. 15, 2017
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - current	$ 37	$ 26	[1]
Due from unconsolidated affiliates - noncurrent	598	201	[1]
Due to unconsolidated affiliates, noncurrent	(35)	0	[1]
Due to unconsolidated affiliates - current	$ (7)	$ (11)	[1]
Joint venture with PEMEX [Member]
Related Party Transaction [Line Items]
Related party transaction rate		5.27%
ESJ joint venture [Member]
Related Party Transaction [Line Items]
Related party transaction rate	7.94%
TAG Pipeline Norte [Member]
Related Party Transaction [Line Items]
Related party transaction rate	4.74%
LIBOR [Member] | Joint venture with PEMEX [Member]
Related Party Transaction [Line Items]
Variable percentage rate		450.00%
LIBOR [Member] | ESJ joint venture [Member]
Related Party Transaction [Line Items]
Variable percentage rate	637.50%
LIBOR [Member] | TAG Pipeline Norte [Member]
Related Party Transaction [Line Items]
Variable percentage rate	290.00%
Sempra South American Utilities [Member] | Eletrans [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - noncurrent	$ 103	$ 96
Sempra South American Utilities [Member] | Other related parties [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - noncurrent	1	1
Sempra Mexico [Member] | IMG [Member]
Related Party Transaction [Line Items]
Committed lines of credit, maximum borrowing capacity	718			MXN 14
Due from unconsolidated affiliates - noncurrent	487	0
Sempra Mexico [Member] | Joint venture with PEMEX [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - noncurrent	0	90
Sempra Mexico [Member] | ESJ joint venture [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - noncurrent	7	14
Sempra Mexico [Member] | TAG Pipeline Norte [Member]
Related Party Transaction [Line Items]
Due to unconsolidated affiliates, noncurrent	$ (35)	0
Sempra Mexico [Member] | Interbank Equilibrium Rate [Member] | IMG [Member]
Related Party Transaction [Line Items]
Variable percentage rate	220.00%
Related party transaction rate	9.87%
San Diego Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 750
Due from unconsolidated affiliates - current	0	4	[1]
Due to unconsolidated affiliates - current	(40)	(15)	[1]
San Diego Gas and Electric Company [Member] | Due to/from Sempra Energy [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - current	0	3
Due to unconsolidated affiliates - current	(30)	0
Income taxes due from (to) Sempra Energy	27	$ 159
Related party transaction rate		0.68%
Loan to unconsolidated affiliate, principal		$ 31
San Diego Gas and Electric Company [Member] | Due to/from Various Affiliates [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - current	0	1
Due to unconsolidated affiliates - current	(6)	(7)
San Diego Gas and Electric Company [Member] | Due to/from SoCalGas [Member]
Related Party Transaction [Line Items]
Due to unconsolidated affiliates - current	(4)	(8)
Southern California Gas Company [Member]
Related Party Transaction [Line Items]
Committed lines of credit, maximum borrowing capacity	750
Due from unconsolidated affiliates - current	4	8	[1]
Due to unconsolidated affiliates - current	(35)	(28)	[1]
Southern California Gas Company [Member] | Due to/from Sempra Energy [Member]
Related Party Transaction [Line Items]
Due to unconsolidated affiliates - current	(35)	(28)
Income taxes due from (to) Sempra Energy	10	5
Southern California Gas Company [Member] | Due to/from SDGE [Member]
Related Party Transaction [Line Items]
Due from unconsolidated affiliates - current	$ 4	$ 8
Ductos Energéticos del Norte [Member] | IEnova [Member] | Sempra Mexico [Member]
Related Party Transaction [Line Items]
Acquired percentage interest					50.00%
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICI66

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - AFFILIATES REVENUE AND COST OF SALES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Related Party Transaction [Line Items]
Related party revenue	$ 43	$ 25	$ 26
Related party cost of sales	47	72	107
San Diego Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Related party revenue	8	7	10
Related party cost of sales	71	64	49
Southern California Gas Company [Member]
Related Party Transaction [Line Items]
Related party revenue	$ 74	$ 76	$ 75
Energia Sierra Juarez Wind Project [Member] | San Diego Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Power purchase agreement term	20 years
Generating capacity (in mw) | MW	155
Minimum [Member] | Federal Funds Rate [Member] | California Utilities [Member]
Related Party Transaction [Line Items]
Variable percentage rate	13.00%
Maximum [Member] | Federal Funds Rate [Member] | California Utilities [Member]
Related Party Transaction [Line Items]
Variable percentage rate	20.00%

SIGNIFICANT ACCOUNTING POLICI67

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - RESTRICTED NET ASSETS (Details) $ in Millions	Dec. 31, 2017USD ($)
Significant Restrictions of Subsidiaries [Line Items]
Undistributed earnings of equity investments	$ 89
Sempra South American Utilities [Member] | Luz Del Sur [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	35
Sempra Mexico [Member] | Mexican Subsidiaries [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	198
Sempra Mexico [Member] | IEnova Pipelines [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	19
Sempra Mexico [Member] | Ventika [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	34
Sempra Mexico [Member] | Energia Sierra Juarez Wind Project [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 9
Ownership percentage in equity method investee	50.00%
Sempra Mexico [Member] | TAG Pipeline Norte [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 82
Ownership percentage in equity method investee	50.00%
Sempra Renewables [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 265
Sempra Renewables [Member] | Copper Mountain Solar 1 [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	8
Sempra Renewables [Member] | Tax Equity LLCs [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 19
Sempra Renewables [Member] | Joint Venture One [Member]
Significant Restrictions of Subsidiaries [Line Items]
Ownership percentage in equity method investee	50.00%
Sempra Renewables [Member] | Joint Venture Two [Member]
Significant Restrictions of Subsidiaries [Line Items]
Ownership percentage in equity method investee	25.00%
Sempra LNG & Midstream [Member] | Cameron LNG Holdings [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 7,000
Consolidated Entities [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	8,600
Unconsolidated Entities [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	7,400
San Diego Gas and Electric Company [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	5,100
Amount available for dividend distribution and loans without prior approval from regulatory agency	$ 469
Authorized percentage of equity	52.00%
Minimum common equity ratio	30.00%
Southern California Gas Company [Member]
Significant Restrictions of Subsidiaries [Line Items]
Restricted net assets of consolidated subsidiaries	$ 3,200
Amount available for dividend distribution and loans without prior approval from regulatory agency	$ 736
Authorized percentage of equity	52.00%
California Utilities [Member]
Significant Restrictions of Subsidiaries [Line Items]
Maximum ratio of indebtedness to total capitalization	0.65

SIGNIFICANT ACCOUNTING POLICI68

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - OTHER INCOME, NET (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Income [Line Items]
Allowance for equity funds used during construction	$ 168	$ 116	$ 107
Investment gains	56	23	3
Gains (losses) on interest rate and foreign exchange instruments, net	47	(32)	(4)
Foreign currency transaction losses(2)	(35)	(1)	(7)
Sale of other investments	3	5	11
Electrical infrastructure relocation income	3	10	7
Regulatory Interest, net	3	4	3
Sundry, net	9	7	6
Total	254	132	126
Foreign currency transaction losses	35	1	7
San Diego Gas and Electric Company [Member]
Other Income [Line Items]
Allowance for equity funds used during construction	63	46	37
Regulatory Interest, net	3	3	3
Sundry, net	0	1	(4)
Total	66	50	36
Southern California Gas Company [Member]
Other Income [Line Items]
Allowance for equity funds used during construction	44	40	36
Regulatory Interest, net	0	1	0
Sundry, net	(8)	(9)	(6)
Total	36	$ 32	$ 30
Sempra Mexico [Member] | IMG [Member]
Other Income [Line Items]
Foreign currency transaction losses	$ 35

NEW ACCOUNTING STANDARDS (Detai

NEW ACCOUNTING STANDARDS (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Other		$ 149		$ 62	[1]	$ 66	[1]
Changes in other assets		(214)		49	[1]	(169)	[1]
Net cash provided by operating activities		3,625		2,311	[1]	2,898	[1]
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired		(270)		(1,504)	[1]	(198)	[1]
Other		(2)		9	[1]	9	[1]
Net cash used in investing activities		(4,700)		(4,835)	[1]	(2,868)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES
Other		(43)		(21)	[1]	(20)	[1]
Net Cash Provided by (Used in) Financing Activities		1,007		2,502	[1]	(176)	[1]
Effect of exchange rate changes on cash, cash equivalents and restricted cash		7		(3)	[1]	(14)	[1]
(Decrease) increase in cash, cash equivalents and restricted cash		(61)		(25)	[1]	(160)	[1]
Cash and cash equivalents, January 1	[2]	349
Cash and cash equivalents, December 31		288		349	[2]
Cash, cash equivalents and restricted cash, January 1	[1]	425		450		610
Cash, cash equivalents and restricted cash, December 31		364		425	[1]	450	[1]
Income Statement [Abstract]
Operation and maintenance		3,117		2,970		2,886
Other income, net		254		132		126
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Other				62		66
Changes in other assets				49		(169)
Net cash provided by operating activities				2,311		2,898
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired				0		0
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired				(1,504)		(198)
Increases in restricted cash				0		0
Decreases in restricted cash				0		0
Other				9		9
Net cash used in investing activities				(4,835)		(2,868)
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(21)		(20)
Net Cash Provided by (Used in) Financing Activities				2,502		(176)
Effect of Exchange Rate on Cash and Cash Equivalents				0		0
Effect of exchange rate changes on cash, cash equivalents and restricted cash				(3)		(14)
(Decrease) increase in cash and cash equivalents				0		0
(Decrease) increase in cash, cash equivalents and restricted cash				(25)		(160)
Cash and cash equivalents, January 1		0		0		0
Cash and cash equivalents, December 31				0		0
Cash, cash equivalents and restricted cash, January 1		425		450		610
Cash, cash equivalents and restricted cash, December 31				425		450
As previously reported [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Operation and maintenance		3,117		2,970
Other income, net		254		132
As previously reported [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Other				63		66
Changes in other assets				56		(162)
Net cash provided by operating activities				2,319		2,905
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired				(1,582)		(200)
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired				0		0
Increases in restricted cash				(139)		(100)
Decreases in restricted cash				175		93
Other				0		1
Net cash used in investing activities				(4,886)		(2,885)
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(10)		(17)
Net Cash Provided by (Used in) Financing Activities				2,513		(173)
Effect of Exchange Rate on Cash and Cash Equivalents				0		(14)
Effect of exchange rate changes on cash, cash equivalents and restricted cash				0		0
(Decrease) increase in cash and cash equivalents				(54)		(167)
(Decrease) increase in cash, cash equivalents and restricted cash				0		0
Cash and cash equivalents, January 1		349		403		570
Cash and cash equivalents, December 31				349		403
Cash, cash equivalents and restricted cash, January 1		0		0		0
Cash, cash equivalents and restricted cash, December 31				0		0
Effect of adoption [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Other				(1)		0
Changes in other assets				(7)		(7)
Net cash provided by operating activities				(8)		(7)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired				1,582		200
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired				(1,504)		(198)
Increases in restricted cash				139		100
Decreases in restricted cash				(175)		(93)
Other				9		8
Net cash used in investing activities				51		17
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(11)		(3)
Net Cash Provided by (Used in) Financing Activities				(11)		(3)
Effect of Exchange Rate on Cash and Cash Equivalents				0		14
Effect of exchange rate changes on cash, cash equivalents and restricted cash				(3)		(14)
(Decrease) increase in cash and cash equivalents				54		167
(Decrease) increase in cash, cash equivalents and restricted cash				(25)		(160)
Cash and cash equivalents, January 1		(349)		(403)		(570)
Cash and cash equivalents, December 31				(349)		(403)
Cash, cash equivalents and restricted cash, January 1		425		450		610
Cash, cash equivalents and restricted cash, December 31				425		450
Recast [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Operation and maintenance		3,096		2,976
Other income, net		233		138
San Diego Gas and Electric Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Other		(22)		(35)	[1]	(16)	[1]
Changes in other assets		(108)		(20)	[1]	(125)	[1]
Net cash provided by operating activities		1,547		1,323	[1]	1,661	[1]
CASH FLOWS FROM INVESTING ACTIVITIES
Other		9		6	[1]	5	[1]
Net cash used in investing activities		(1,515)		(1,324)	[1]	(1,077)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES
Net Cash Provided by (Used in) Financing Activities		(23)		(22)	[1]	(568)	[1]
Cash and cash equivalents, January 1	[2]	8
Cash and cash equivalents, December 31		12		8	[2]
Cash, cash equivalents and restricted cash, January 1	[1]	20		43		27
Cash, cash equivalents and restricted cash, December 31		29		20	[1]	43	[1]
Income Statement [Abstract]
Utilities Operation and maintenance		1,020		1,048		1,017
Operating income		713		990		1,058
Other income, net		66		50		36
San Diego Gas and Electric Company [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in other assets				(20)		(125)
Net cash provided by operating activities				1,323		1,661
CASH FLOWS FROM INVESTING ACTIVITIES
Increases in restricted cash				0		0
Decreases in restricted cash				0		0
Other				6		5
Net cash used in investing activities				(1,324)		(1,077)
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(6)		(4)
Net Cash Provided by (Used in) Financing Activities				(22)		(568)
(Decrease) increase in cash and cash equivalents				0		0
(Decrease) increase in cash, cash equivalents and restricted cash				(23)		16
Cash and cash equivalents, January 1		0		0		0
Cash and cash equivalents, December 31				0		0
Cash, cash equivalents and restricted cash, January 1		20		43		27
Cash, cash equivalents and restricted cash, December 31				20		43
San Diego Gas and Electric Company [Member] | As previously reported [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Utilities Operation and maintenance		1,020		1,048
Operating income		713		990
Other income, net		66		50
San Diego Gas and Electric Company [Member] | As previously reported [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in other assets				(16)		(122)
Net cash provided by operating activities				1,327		1,664
CASH FLOWS FROM INVESTING ACTIVITIES
Increases in restricted cash				(49)		(39)
Decreases in restricted cash				60		35
Other				0		0
Net cash used in investing activities				(1,319)		(1,086)
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(4)		(2)
Net Cash Provided by (Used in) Financing Activities				(20)		(566)
(Decrease) increase in cash and cash equivalents				(12)		12
(Decrease) increase in cash, cash equivalents and restricted cash				0		0
Cash and cash equivalents, January 1		8		20		8
Cash and cash equivalents, December 31				8		20
Cash, cash equivalents and restricted cash, January 1		0		0		0
Cash, cash equivalents and restricted cash, December 31				0		0
San Diego Gas and Electric Company [Member] | Effect of adoption [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in other assets				(4)		(3)
Net cash provided by operating activities				(4)		(3)
CASH FLOWS FROM INVESTING ACTIVITIES
Increases in restricted cash				49		39
Decreases in restricted cash				(60)		(35)
Other				6		5
Net cash used in investing activities				(5)		9
CASH FLOWS FROM FINANCING ACTIVITIES
Other				(2)		(2)
Net Cash Provided by (Used in) Financing Activities				(2)		(2)
(Decrease) increase in cash and cash equivalents				12		(12)
(Decrease) increase in cash, cash equivalents and restricted cash				(23)		16
Cash and cash equivalents, January 1		(8)		(20)		(8)
Cash and cash equivalents, December 31				(8)		(20)
Cash, cash equivalents and restricted cash, January 1		20		43		27
Cash, cash equivalents and restricted cash, December 31				20		43
San Diego Gas and Electric Company [Member] | Recast [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Utilities Operation and maintenance		1,024		1,062
Operating income		709		976
Other income, net		70		64
Southern California Gas Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Other		11		(26)		(20)
Changes in other assets		(80)		35		(91)
Net cash provided by operating activities		1,306		671		880
CASH FLOWS FROM INVESTING ACTIVITIES
Other		4		0		0
Net cash used in investing activities		(1,363)		(1,269)		(1,402)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Cash Provided by (Used in) Financing Activities		53		552		495
(Decrease) increase in cash and cash equivalents		(4)		(46)		(27)
Cash and cash equivalents, January 1		12	[2]	58		85
Cash and cash equivalents, December 31		8		12	[2]	58
Income Statement [Abstract]
Utilities Operation and maintenance		1,479		1,385		1,361
Operating income		622		557		608
Other income, net		36		32		$ 30
Southern California Gas Company [Member] | As previously reported [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Utilities Operation and maintenance		1,479		1,385
Operating income		622		557
Other income, net		36		32
Southern California Gas Company [Member] | Recast [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Utilities Operation and maintenance		1,474		1,391
Operating income		627		551
Other income, net		$ 31		$ 38
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

ACQUISTION AND DIVESTITURE AC70

ACQUISTION AND DIVESTITURE ACTIVITY - ASSETS ACQUIRED AND LIABILITIES ASSUMED (Details) - USD ($) $ in Millions	Dec. 14, 2016	Sep. 26, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Business Acquisition [Line Items]
Fair value of equity interest in IEnova Pipelines immediately prior to acquisition						$ 28	$ 1,144	[1]	$ 0	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Goodwill			$ 2,397	$ 2,364	[2]	2,397	2,364	[2]	$ 819
Acquisition of business – measurement period adjustment						(13)
Sempra Mexico [Member] | IEnova Pipelines [Member]
Business Acquisition [Line Items]
Cash consideration (fair value of total consideration)		$ 1,144
Fair value of equity interest in IEnova Pipelines immediately prior to acquisition		1,144
Total fair value of business combination		2,288
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Cash and cash equivalents		66
Restricted cash		0
Accounts receivable		39
Other current assets		6
Other intangible assets		0
Deferred income taxes		0
Regulatory assets		33
Property, plant and equipment		1,248
Other noncurrent assets		1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Short-term debt		0
Accounts payable		(11)
Due to unconsolidated affiliates		(3)
Current portion of long-term debt		(49)
Fixed-price contracts and other derivatives, current		(6)
Other current liabilities		(20)
Long-term debt		(315)
Asset retirement obligations		(5)
Deferred income taxes		(127)
Fixed-price contracts and other derivatives, noncurrent		(19)
Other noncurrent liabilities		(11)
Total identifiable net assets		827
Goodwill		$ 1,461
Sempra Mexico [Member] | IEnova Pipelines [Member] | Scenario, Adjustment [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Regulatory assets				33			33
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Deferred income taxes				(119)			$ (119)
Acquisition of business – measurement period adjustment				$ 86
Sempra Mexico [Member] | Ventika [Member]
Business Acquisition [Line Items]
Cash consideration (fair value of total consideration)	$ 310
Fair value of equity interest in IEnova Pipelines immediately prior to acquisition	0
Total fair value of business combination	310
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Cash and cash equivalents	0
Restricted cash	68
Accounts receivable	14
Other current assets	1
Other intangible assets	154
Deferred income taxes	36
Regulatory assets	0
Property, plant and equipment	673
Other noncurrent assets	3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Short-term debt	(125)
Accounts payable	(1)
Due to unconsolidated affiliates	0
Current portion of long-term debt	(7)
Fixed-price contracts and other derivatives, current	(4)
Other current liabilities	(8)
Long-term debt	(478)
Asset retirement obligations	(2)
Deferred income taxes	(120)
Fixed-price contracts and other derivatives, noncurrent	(10)
Other noncurrent liabilities	0
Total identifiable net assets	194
Goodwill	$ 116
Sempra Mexico [Member] | Ventika [Member] | Scenario, Adjustment [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Deferred income taxes			13			$ 13
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Acquisition of business – measurement period adjustment			$ (13)
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

ACQUISTION AND DIVESTITURE AC71

ACQUISTION AND DIVESTITURE ACTIVITY - ACQUISITION ACTIVITY (Details) $ in Millions

Jan. 12, 2018USD ($)

Nov. 15, 2017USD ($)

Oct. 03, 2017USD ($)

Aug. 21, 2017USD ($)director

Jul. 10, 2017USD ($)ppaMW

Dec. 14, 2016USD ($)MW

Oct. 13, 2016USD ($)

Sep. 26, 2016USD ($)

Jul. 01, 2016USD ($)MW

Sep. 30, 2016USD ($)

Mar. 31, 2015USD ($)MW

Dec. 31, 2017USD ($)

Sep. 30, 2017USD ($)

Jun. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Sep. 30, 2016USD ($)

Jun. 30, 2016USD ($)

Mar. 31, 2016USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Nov. 14, 2017

Sep. 06, 2017USD ($)

Sep. 25, 2016

Jan. 01, 2015

Dec. 31, 2014

Business Acquisition [Line Items]

Cash paid, net of cash and cash equivalents acquired

$ (147)

$ (1,342)

[1]

$ (3)

[1]

Revenues

11,207

10,183

10,231

Earnings/Income attributable to common shares

$ (501)

$ 57

$ 259

$ 441

$ 379

$ 622

$ 16

$ 353

256

1,370

1,349

Issuances of common stock

47

51

[1]

52

[1]

Restricted cash

76

$ 76

76

$ 76

IEnova [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 351

Ventika [Member] | IEnova [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 50

Energy Future Holdings Corp. [Member] | Oncor Electric Delivery Company LLC. [Member]

Business Acquisition [Line Items]

Consideration transferred

$ 9,450

Shares issued

$ 25.9

Percentage of consideration funded by equity issuance

65.00%

Percentage of consideration funded by debt issuance

35.00%

Plan percentage of capital structure allocated to debt

57.50%

Plan percentage of capital structure allocated to equity

42.50%

Transaction costs incurred

$ 43

$ 43

Number of directors on board | director

13

Fee receivable if agreement terminated

$ 190

Sempra Mexico [Member] | IEnova [Member]

Business Acquisition [Line Items]

Ownership percentage held by noncontrolling owners

33.60%

33.60%

33.60%

33.60%

33.60%

18.90%

Sempra Mexico [Member] | Ramones Norte Pipeline [Member] | IEnova [Member]

Business Acquisition [Line Items]

Ownership percentage in equity method investee

25.00%

Sempra Mexico [Member] | Ductos Energéticos del Norte [Member] | IEnova [Member]

Business Acquisition [Line Items]

Acquired percentage interest

50.00%

Debt assumed

$ 96

Ownership percentage before acquisition

100.00%

50.00%

Ownership percentage in consolidated entity

100.00%

Ownership percentage in equity method investee

50.00%

Cash paid, net of cash and cash equivalents acquired

$ 165

Weighted average life of finite-lived intangible acquired

23 years

Cash Acquired from Acquisition

$ 18

Other intangible assets

$ 66

Sempra Mexico [Member] | Ductos Energéticos del Norte [Member] | Ramones Norte Pipeline [Member] | IEnova [Member]

Business Acquisition [Line Items]

Ownership percentage before acquisition

50.00%

25.00%

Ownership percentage in consolidated entity

50.00%

Sempra Mexico [Member] | IEnova Pipelines [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 1,144

Cash and cash equivalents

66

Other intangible assets

$ 0

Sempra Mexico [Member] | IEnova Pipelines [Member] | IEnova [Member]

Business Acquisition [Line Items]

Acquired percentage interest

50.00%

Cash consideration (fair value of total consideration)

$ 1,144

Cash and cash equivalents

66

Debt assumed

$ 364

Ownership percentage before acquisition

50.00%

Ownership percentage in consolidated entity

100.00%

Cash paid, net of cash and cash equivalents acquired

$ 1,078

Proceeds from debt issued

$ 1,150

Gain on acquisition of remaining voting rights

$ 617

$ 617

Gain on acquisition of remaining voting rights, net of tax

$ 432

432

Accrued Merger-related transaction costs

4

$ 1

Revenues

82

Earnings/Income attributable to common shares

33

Sempra Mexico [Member] | Ventika [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 310

Cash and cash equivalents

0

Other intangible assets

$ 154

Sempra Mexico [Member] | Ventika [Member] | IEnova [Member]

Business Acquisition [Line Items]

Acquired percentage interest

100.00%

Debt assumed

$ 610

Proceeds from debt issued

250

Cash

10

Accrued Merger-related transaction costs

1

Revenues

4

Earnings/Income attributable to common shares

$ 3

Consideration transferred

$ 310

Generating capacity (in mw) | MW

252

Power purchase agreement term

20 years

Issuances of common stock

$ 50

Restricted cash

$ 68

Sempra Mexico [Member] | Ventika [Member] | IEnova [Member] | Renewable energy and consumption permit [Member]

Business Acquisition [Line Items]

Weighted average life of finite-lived intangible acquired

19 years

Sempra Renewables [Member] | Great Valley Solar [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 124

Generating capacity (in mw) | MW

200

Number of purchase power agreements | ppa

4

Power purchase agreement term

18 years

Sempra Renewables [Member] | Huron County, Michigan [Member]

Business Acquisition [Line Items]

Cash consideration (fair value of total consideration)

$ 18

$ 4

Ownership percentage in consolidated entity

100.00%

Consideration transferred

$ 22

Generating capacity (in mw) | MW

100

Power purchase agreement term

15 years

Sempra Renewables [Member] | Stearns County, Minnesota [Member]

Business Acquisition [Line Items]

Ownership percentage in consolidated entity

100.00%

Consideration transferred

$ 8

Generating capacity (in mw) | MW

78

Power purchase agreement term

20 years

Oncor Holdings Electric Delivery Company LLC [Member] | Energy Future Holdings Corp. [Member] | Energy Future Intermediate Holding Company LLC [Member]

Business Acquisition [Line Items]

Ownership percentage in consolidated entity

100.00%

Energy Future Intermediate Holding Company LLC [Member] | Energy Future Holdings Corp. [Member] | Energy Future Holdings Corp. [Member]

Business Acquisition [Line Items]

Ownership percentage in consolidated entity

100.00%

Energy Future Holdings Corp. [Member] | Energy Future Holdings Corp. [Member]

Business Acquisition [Line Items]

Ownership percentage in consolidated entity

100.00%

Oncor Electric Delivery Company LLC. [Member] | Energy Future Holdings Corp. [Member]

Business Acquisition [Line Items]

Acquired percentage interest

80.03%

Oncor Electric Delivery Company LLC. [Member] | Energy Future Holdings Corp. [Member] | Texas Transmission Investment LLC [Member]

Business Acquisition [Line Items]

Ownership percentage held by noncontrolling owners

19.75%

Oncor Electric Delivery Company LLC. [Member] | Energy Future Holdings Corp. [Member] | Current and Former Directors and Officers of Oncor [Member]

Business Acquisition [Line Items]

Ownership percentage held by noncontrolling owners

0.22%

Independent Director [Member] | Energy Future Holdings Corp. [Member] | Oncor Electric Delivery Company LLC. [Member]

Business Acquisition [Line Items]

Number of directors on board | director

7

Management [Member] | Energy Future Holdings Corp. [Member] | Oncor Electric Delivery Company LLC. [Member]

Business Acquisition [Line Items]

Number of directors on board | director

2

Energy Future Intermediate Holding Company LLC [Member] | Director Appointed by Related Party [Member] | Energy Future Holdings Corp. [Member] | Oncor Electric Delivery Company LLC. [Member]

Business Acquisition [Line Items]

Number of directors on board | director

2

Texas Transmission Investment LLC [Member] | Director Appointed by Related Party [Member] | Energy Future Holdings Corp. [Member] | Oncor Electric Delivery Company LLC. [Member]

Business Acquisition [Line Items]

Number of directors on board | director

2

Subsequent Event [Member] | Energy Future Holdings Corp. [Member]

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 4,900

Commercial paper [Member] | Subsequent Event [Member] | Energy Future Holdings Corp. [Member]

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 2,700

[1]

As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

ACQUISTION AND DIVESTITURE AC72

ACQUISTION AND DIVESTITURE ACTIVITY - PRO FORMA INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Jan. 01, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenues	$ 10,463	$ 10,473
Net income	1,145	1,938
Earnings	$ 1,058	$ 1,641
IEnova [Member] | Sempra Mexico [Member]
Business Acquisition [Line Items]
Ownership percentage held by noncontrolling owners	33.60%		33.60%	33.60%	18.90%

ACQUISTION AND DIVESTITURE AC73

ACQUISTION AND DIVESTITURE ACTIVITY - ASSETS HELD FOR SALE (Details) - Sempra Mexico [Member] - Termoelectrica de Mexicali [Member] $ in Millions	1 Months Ended			3 Months Ended		12 Months Ended
	Jun. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Feb. 29, 2016MW	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generating capacity (in mw) | MW			625
Other than temporary impairment in investment	$ 71	$ 131		$ 71	$ 131
Other than temporary impairment in investment, net of tax		$ 111			$ 111
Deferred tax expense						$ (8)	$ 8
Disposal Group Held-for-sale [Member]
Assets Held for Sale, Assets [Abstract]
Inventories						10
Other current assets						59
Property, plant and equipment, net						56
Other noncurrent assets						2
Total assets held for sale						127
Assets Held for Sale, Liabilities [Abstract]
Accounts payable						5
Other current liabilities						38
Asset retirement obligations						5
Other noncurrent liabilities						1
Total liabilities held for sale						$ 49

ACQUISTION AND DIVESTITURE AC74

ACQUISTION AND DIVESTITURE ACTIVITY - DIVESTITURES (Details) $ in Millions

1 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2016USD ($)

Sep. 30, 2016USD ($)

May 31, 2016USD ($)

Mar. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Apr. 30, 2015USD ($)MW

Sep. 30, 2016USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Sep. 12, 2016USD ($)

May 09, 2016

Mar. 29, 2016

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Liabilities assumed

$ 261

$ 1,322

[1]

$ 2

[1]

Equity method investment

$ 2,517

$ 2,080

Sempra Renewables [Member] | Rosamond Solar [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Ownership percentage in equity method investee

100.00%

100.00%

Proceeds from sale

$ 26

Gain on sale of equity interests

8

Gain on sale of assets, after tax

5

Property, plant and equipment, net

$ 18

Sempra LNG & Midstream [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Other than temporary impairment in investment

$ 44

Other than temporary impairment in investment, net of tax

$ 27

Sempra LNG & Midstream [Member] | Mesquite Power [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Generating capacity (in mw) | MW

625

Proceeds from sale

$ 347

Gain on sale of equity interests

61

Gain on sale of assets, after tax

$ 36

Sempra LNG & Midstream [Member] | Disposal Group Disposed of by Sale [Member] | Energy South [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain on sale of equity interests

$ 130

$ 130

Gain on sale of assets, after tax

78

Proceeds from sale

$ 318

Cash

$ 2

Liabilities assumed

$ 67

Sempra LNG & Midstream [Member] | Rockies Express [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Ownership percentage in equity method investee

25.00%

25.00%

25.00%

25.00%

Proceeds from sale of investments

$ 443

$ 440

Equity method investment

484

Fair value of investment

440

Other than temporary impairment in investment

44

$ 44

Other than temporary impairment in investment, net of tax

$ 27

$ 27

[1]

As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

ACQUISTION AND DIVESTITURE AC75

ACQUISTION AND DIVESTITURE ACTIVITY - SUMMARY OF DECONSOLIDATIONS (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016		Sep. 12, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill			$ 2,397	$ 2,364	[1]		$ 819
Equity method investment			2,517	2,080
Sempra LNG & Midstream [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill			$ 0	$ 0			$ 72
Sempra LNG & Midstream [Member] | Energy South [Member] | Disposal Group Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds, net of transaction costs						$ 304
Cash						(2)
Other current assets						(17)
Property, plant and equipment, net						(199)
Goodwill						(72)
Other noncurrent assets						65
Other current liabilities						25
Long-term debt, including current portion						67
Other noncurrent liabilities						$ 89
Gain on sale of business and equity interests	$ 130	$ 130
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

INVESTMENTS IN UNCONSOLIDATED76

INVESTMENTS IN UNCONSOLIDATED ENTITIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity method investment	$ 2,517	$ 2,080
Income (Loss) from Equity Method Investments	34	6	$ 104
Cameron LNG Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Difference between carrying amount of equity method investment and underlying equity	237	190
R B S Sempra Commodities [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	67
Other Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	10	17
Income (loss) from equity method investment earnings (losses) net of tax	42	78	85
Other Equity Method Investments And Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	2,527	2,097
Sempra Renewables [Member] | California Solar Partnership [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	107	113
Income (Loss) from Equity Method Investments	7	7	6
Sempra Renewables [Member] | Copper Mountain Solar 3 [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	44	42
Income (Loss) from Equity Method Investments	8	8	8
Sempra Renewables [Member] | Broken Bow 2 Wind [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	32	35
Income (Loss) from Equity Method Investments	(2)	(2)	(2)
Sempra Renewables [Member] | Cedar Creek 2 Wind Farm [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	72	75
Income (Loss) from Equity Method Investments	(2)	(2)	(6)
Sempra Renewables [Member] | Flat Ridge 2 Wind Farm [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	255	271
Income (Loss) from Equity Method Investments	(13)	(7)	(12)
Sempra Renewables [Member] | Fowler Ridge 2 Wind Farm [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	44	43
Income (Loss) from Equity Method Investments	4	4	4
Sempra Renewables [Member] | Mehoopany Wind Farm [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	89	92
Income (Loss) from Equity Method Investments	(1)	0	(1)
Sempra Renewables [Member] | Copper Mountain Solar 2 [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	35	33
Income (Loss) from Equity Method Investments	5	6	7
Sempra Renewables [Member] | Mesquite Solar 1 [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	81	86
Income (Loss) from Equity Method Investments	18	17	16
Sempra Renewables [Member] | Auwahi Wind [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	42	41
Income (Loss) from Equity Method Investments	5	4	4
Sempra Renewables [Member] | Other Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	12	13
Income (Loss) from Equity Method Investments	0	(1)	0
Sempra LNG & Midstream [Member] | Cameron LNG Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	997	997
Income (Loss) from Equity Method Investments	5	(2)	5
Sempra LNG & Midstream [Member] | Rockies Express [Member]
Schedule of Equity Method Investments [Line Items]
Income (Loss) from Equity Method Investments	0	(26)	79
Sempra Energy and Other [Member] | R B S Sempra Commodities [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	67	67
Income (Loss) from Equity Method Investments	0	0	(4)
Sempra South American Utilities [Member] | Eletrans [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	16	(8)
Income (loss) from equity method investment earnings (losses) net of tax	4	3	(4)
Sempra Mexico [Member] | Ductos Energéticos del Norte [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	0	42
Income (loss) from equity method investment earnings (losses) net of tax	(13)	5	0
Sempra Mexico [Member] | Energia Sierra Juarez Wind Project [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	39	38
Difference between carrying amount of equity method investment and underlying equity				$ 12
Income (loss) from equity method investment earnings (losses) net of tax	0	6	6
Sempra Mexico [Member] | IEnova Pipelines [Member]
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investment earnings (losses) net of tax	0	64	83
Sempra Mexico [Member] | IMG [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	221	100
Difference between carrying amount of equity method investment and underlying equity	5
Income (loss) from equity method investment earnings (losses) net of tax	45	0	0
Sempra Mexico [Member] | TAG [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	364	0
Difference between carrying amount of equity method investment and underlying equity	130
Income (loss) from equity method investment earnings (losses) net of tax	$ 6	$ 0	$ 0

INVESTMENTS IN UNCONSOLIDATED77

INVESTMENTS IN UNCONSOLIDATED ENTITIES - NARRATIVE (Details) $ in Millions

1 Months Ended

12 Months Ended

Feb. 28, 2017USD ($)

Dec. 31, 2017USD ($)MTBcf

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Nov. 15, 2017

Nov. 14, 2017

Sep. 26, 2016

Sep. 25, 2016

May 31, 2016

May 09, 2016

Mar. 31, 2016USD ($)

Mar. 29, 2016

Jun. 30, 2015USD ($)

Nov. 30, 2014USD ($)

Oct. 01, 2014USD ($)

Schedule of Equity Method Investments [Line Items]

Undistributed earnings of equity method investments

$ 89

$ 44

Equity method investment

2,517

2,080

Debt instrument converted

19

0

[1]

$ 0

[1]

Interest costs capitalized

256

236

201

Fair value at origin guarantee obligation associated with cash flow requirements

$ 82

Current guarantor obligations

26

R B S Sempra Commodities [Member]

Schedule of Equity Method Investments [Line Items]

Equity method investment

$ 67

Cameron LNG [Member]

Schedule of Equity Method Investments [Line Items]

Ownership percentage in equity method investee

50.20%

Threshold for canceling of hedge, Percent of unamortized principal

50.00%

Indirect economic and beneficial and ownership interest prior to financial completion

37.65%

Indirect economic and beneficial and ownership interest after financial completion

10.00%

Cameron LNG [Member] | Other Long Term Debt, Due July 2030 [Member]

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Maximum Exposure, Percentage

50.20%

Debt instrument, maximum borrowing amount

$ 3,900

Sempra Energy and Other [Member] | R B S Sempra Commodities [Member]

Schedule of Equity Method Investments [Line Items]

Equity method investment

67

67

Sempra Mexico [Member] | IEnova Pipelines [Member]

Schedule of Equity Method Investments [Line Items]

Acquired percentage interest

50.00%

Ownership percentage in equity method investee

50.00%

Sempra Mexico [Member] | IMG [Member]

Schedule of Equity Method Investments [Line Items]

Payments to acquire equity method investments

$ 72

100

Ownership percentage in equity method investee

40.00%

Transportation service contract term

25 years

Sempra Mexico [Member] | TransCanada [Member]

Schedule of Equity Method Investments [Line Items]

Ownership percentage in equity method investee

60.00%

Sempra Mexico [Member] | DEN [Member] | IEnova Pipelines [Member]

Schedule of Equity Method Investments [Line Items]

Ownership percentage in equity method investee

50.00%

Sempra Renewables [Member]

Schedule of Equity Method Investments [Line Items]

Payments to acquire equity method investments

18

21

Ownership percentage of operating partner

50.00%

Sempra LNG & Midstream [Member] | Rockies Express [Member]

Schedule of Equity Method Investments [Line Items]

Equity method investment

$ 484

Payments to acquire equity method investments

113

Ownership percentage in equity method investee

25.00%

25.00%

25.00%

25.00%

Sempra LNG & Midstream [Member] | Cameron LNG [Member]

Schedule of Equity Method Investments [Line Items]

Payments to acquire equity method investments

$ 1

10

Proved developed reserves | Bcf

1.5

Project capacity | MT

13.9

Proved undeveloped reserve | MT

12

Proved undeveloped reserve per day | Bcf

1.7

Interest costs capitalized

$ 47

$ 47

$ 49

Debt amount

$ 7,400

Percentage of debt hedged by interest rate derivatives

50.00%

Notional amount of derivatives

$ 1,500

$ 3,700

Sempra LNG & Midstream [Member] | LIBOR [Member] | Cameron LNG [Member]

Schedule of Equity Method Investments [Line Items]

Weighted average rate prior to project completion

1.59%

Weighted average rate after project completion

1.78%

Fixed percentage interest rate

3.32%

3.19%

Corporate Joint Venture [Member] | Sempra South American Utilities [Member] | Eletrans [Member]

Schedule of Equity Method Investments [Line Items]

Debt instrument converted

$ 19

Payments to acquire equity method investments

$ 1

Corporate Joint Venture [Member] | Sempra Mexico [Member] | IEnova [Member] | IMG [Member]

Schedule of Equity Method Investments [Line Items]

Debt instrument, maximum borrowing amount

$ 288

Other Project Partners [Member] | Cameron LNG [Member] | Other Long Term Debt, Due July 2030 [Member]

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Maximum Exposure, Percentage

49.80%

Ductos Energéticos del Norte [Member] | Sempra Mexico [Member] | IEnova [Member]

Schedule of Equity Method Investments [Line Items]

Acquired percentage interest

50.00%

Ownership percentage in equity method investee

50.00%

[1]

As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

INVESTMENTS IN UNCONSOLIDATED78

INVESTMENTS IN UNCONSOLIDATED ENTITIES - SUMMARIZED FINANCIAL INFORMATION (Details) - USD ($) $ in Millions	Nov. 15, 2017	Sep. 26, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 14, 2017	Sep. 25, 2016	May 31, 2016	May 09, 2016	Mar. 31, 2016	Mar. 29, 2016
Equity Method Investment, Summarized Financial Information [Abstract]
Gross revenue			$ 846	$ 1,079	$ 1,533
Operating expense			(590)	(726)	(845)
Income from operations			256	353	688
Interest expense			(217)	(127)	(312)
Net income/earnings			116	252	$ 440
Current assets			974	704
Noncurrent assets			14,087	9,970
Current liabilities			797	629
Noncurrent liabilities			$ 9,809	$ 6,627
Sempra LNG & Midstream [Member] | Rockies Express [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage in equity method investee								25.00%	25.00%	25.00%	25.00%
IEnova [Member] | Ductos Energéticos del Norte [Member] | Sempra Mexico [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage before acquisition	100.00%					50.00%
Acquired percentage interest	50.00%
Ownership percentage in consolidated entity	100.00%
Ownership percentage in equity method investee						50.00%
IEnova [Member] | IEnova Pipelines [Member] | Sempra Mexico [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage before acquisition							50.00%
Acquired percentage interest		50.00%
Ownership percentage in consolidated entity		100.00%

INVESTMENTS IN UNCONSOLIDATED79

INVESTMENTS IN UNCONSOLIDATED ENTITIES - GUARANTEES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Current guarantor obligations	$ 26
Debt Service Operations [Member]
Long-term Purchase Commitment [Line Items]
Maximum exposure of guarantor obligations	183
Current guarantor obligations	6
Purchased Power Contracts [Member]
Long-term Purchase Commitment [Line Items]
Maximum exposure of guarantor obligations	370
Current guarantor obligations	$ 3
IEnova [Member] | Sempra Mexico [Member]
Long-term Purchase Commitment [Line Items]
Ownership percentage held by noncontrolling owners	33.60%	33.60%	33.60%	18.90%
Corporate Joint Venture [Member] | IMG [Member] | IEnova [Member] | Sempra Mexico [Member]
Long-term Purchase Commitment [Line Items]
Ownership percentage held by noncontrolling owners	40.00%
Maximum exposure of guarantor obligations	$ 288
TransCanada [Member] | Corporate Joint Venture [Member] | IMG [Member] | IEnova [Member] | Sempra Mexico [Member]
Long-term Purchase Commitment [Line Items]
Ownership percentage held by noncontrolling owners	60.00%

DEBT AND CREDIT FACILITIES - LI

DEBT AND CREDIT FACILITIES - LINES OF CREDIT (Details)	Jan. 17, 2018USD ($)	Dec. 31, 2017USD ($)lenderline_of_credit	Jan. 16, 2018USD ($)	Dec. 31, 2016
Line of Credit Facility [Line Items]
Letters of credit outstanding		$ 629,000,000
Commitment from syndicated banks for acquisition		$ 4,000,000,000
Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Number of primary lines of credit | line_of_credit		3
Weighted average interest rate on total short-term debt outstanding		1.92%		1.51%
Sempra South American Utilities [Member] | Peru [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		$ 465,000,000
Line of credit outstanding		(169,000,000)
Committed lines of credit, remaining borrowing capacity		$ 296,000,000
Committed lines of credit, maximum debt to equity ratio		170.00%
Committed lines of credit, bank guarantee		$ 18,000,000
Sempra South American Utilities [Member] | Chile [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		115,000,000
Line of credit outstanding		0
Committed lines of credit, remaining borrowing capacity		115,000,000
Sempra Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,170,000,000
Line of credit outstanding		(137,000,000)
Committed lines of credit, remaining borrowing capacity		1,033,000,000
South America and Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,750,000,000
Line of credit outstanding		(306,000,000)
Committed lines of credit, remaining borrowing capacity		1,444,000,000
Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,000,000,000
Committed lines of credit, remaining borrowing capacity		1,000,000,000
Committed lines of credit, capacity for issuance of letters of credit		$ 400,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Sempra Energy [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ 0
Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		2,335,000,000
Committed lines of credit, remaining borrowing capacity		1,404,000,000
Sempra Global [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		(931,000,000)
Southern California Gas Company [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		750,000,000
Committed lines of credit, remaining borrowing capacity		$ 634,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Weighted average interest rate on total short-term debt outstanding		1.64%		0.75%
Southern California Gas Company [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (116,000,000)
San Diego Gas and Electric Company [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		750,000,000
Committed lines of credit, remaining borrowing capacity		$ 497,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Weighted average interest rate on total short-term debt outstanding		1.65%
San Diego Gas and Electric Company [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (253,000,000)
California Utilities [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,000,000,000
Committed lines of credit, remaining borrowing capacity		631,000,000
Reduction in borrowing limit		(500,000,000)
Line of Credit Facility, Available Unused Credit Limit Reduction		(500,000,000)
Committed lines of credit, capacity for issuance of letters of credit		250,000,000
California Utilities [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		(369,000,000)
Reduction in borrowing limit		0
Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		4,335,000,000
Committed lines of credit, remaining borrowing capacity		$ 3,035,000,000
Committed lines of credit, term		5 years
Committed lines of credit, number of lenders | lender		21
Lender maximum share of debt percent		7.00%
Sempra Energy Consolidated [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (1,300,000,000)
Subsequent Event [Member] | Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 1,250,000,000		$ 1,000,000,000
Increase in borrowing capacity	250,000,000
Subsequent Event [Member] | Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	3,185,000,000		$ 2,335,000,000
Increase in borrowing capacity	$ 850,000,000

DEBT AND CREDIT FACILITIES - SC

DEBT AND CREDIT FACILITIES - SCHEDULE OF LONG-TERM DEBT INSTRUMENTS (Details) - USD ($) $ in Millions	Oct. 13, 2017	Dec. 31, 2017	Oct. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Current portion of long-term debt		$ (1,427)			$ (913)	[1]
Long-term debt		16,445			14,429	[1]
San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Gross long-term debt		4,573			4,349
Capital lease obligations		732			240
Long-term debt and capital lease obligations		5,600			4,894
Current portion of long-term debt		(220)			(191)	[1]
Unamortized discount on long-term debt		(11)			(11)
Unamortized debt issuance costs		(34)			(34)
Long-term debt		5,335			4,658	[1]
San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due March 2017 [Member]
Debt Instrument [Line Items]
Gross long-term debt		0			$ 140
Stated percentage rate					1.151%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due July 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 161			$ 161
Stated percentage rate		1.65%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due August 2021 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 350			350
Stated percentage rate		3.00%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due February 2022 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 161			197
Stated percentage rate		1.914%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due September 2023 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 450			450
Stated percentage rate		3.60%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due May 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		2.50%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		6.00%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due January and February 2034 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 176			176
Stated percentage rate		5.875%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2035 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		5.35%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due September 2037 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		6.125%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2039 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 75			75
Stated percentage rate		4.00%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2039 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 300			300
Stated percentage rate		6.00%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2040 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		5.35%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due August 2040 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		4.50%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due November 2041 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		3.95%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due April 2042 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		4.30%
San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2047 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 400		$ 400	0
Stated percentage rate		3.75%		3.75%
San Diego Gas and Electric Company [Member] | Capital Lease Obligations, Purchased Power Agreements [Member]
Debt Instrument [Line Items]
Capital lease obligations		$ 731			239
San Diego Gas and Electric Company [Member] | Capital Lease Obligations, Other [Member]
Debt Instrument [Line Items]
Capital lease obligations		1			1
San Diego Gas and Electric Company [Member] | Other Long-term Debt [Member]
Debt Instrument [Line Items]
Long-term debt and capital lease obligations		$ 1,027			545
San Diego Gas and Electric Company [Member] | Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member]
Debt Instrument [Line Items]
Stated percentage rate		5.2925%
Southern California Gas Company [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 3,000			3,000
Capital lease obligations		1			0
Long-term debt and capital lease obligations		3,010			3,009
Current portion of long-term debt		(501)			0	[1]
Unamortized discount on long-term debt		(7)			(7)
Unamortized debt issuance costs		(17)			(20)
Long-term debt		2,485			2,982	[1]
Southern California Gas Company [Member] | First Mortgage Bonds, Due June 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		2.60%
Southern California Gas Company [Member] | First Mortgage Bonds, Due April 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		5.45%
Southern California Gas Company [Member] | First Mortgage Bonds Due June 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		1.55%
Southern California Gas Company [Member] | First Mortgage Bonds, Due September 2024 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		3.15%
Southern California Gas Company [Member] | First Mortgage Bonds Due June 2025 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 350			350
Stated percentage rate		3.20%
Southern California Gas Company [Member] | First Mortgage Bonds, Due November 2035 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		5.75%
Southern California Gas Company [Member] | First Mortgage Bonds, Due November 2040 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 300			300
Stated percentage rate		5.125%
Southern California Gas Company [Member] | First Mortgage Bonds, Due September 2042 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 350			350
Stated percentage rate		3.75%
Southern California Gas Company [Member] | First Mortgage Bonds, Due March 2044 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 250			250
Stated percentage rate		4.45%
Southern California Gas Company [Member] | Other Long-term Debt [Member]
Debt Instrument [Line Items]
Long-term debt and capital lease obligations		$ 10			9
Southern California Gas Company [Member] | Other Long-term Debt, Due May 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 4			4
Stated percentage rate		1.875%
Southern California Gas Company [Member] | Other Long-term Debt, Due January 2028 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 5			5
Stated percentage rate		5.67%
Sempra Energy [Member]
Debt Instrument [Line Items]
Build to suit lease		$ 138			137
Sempra Energy [Member] | Other Long Term Debt Due April 2017 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 0			600
Stated percentage rate		2.30%
Sempra Energy [Member] | Other Long-term Debt, Due June 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		6.15%
Sempra Energy [Member] | Other Long-term Debt, Due February 2019 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		9.80%
Sempra Energy [Member] | Other Long-term Debt, Due October 2019 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		1.625%
Sempra Energy [Member] | Other Long Term Debt Due March 2020 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		2.40%
Sempra Energy [Member] | Other Long Term Debt, Due November 2020 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 400			400
Stated percentage rate		2.85%
Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 850	$ 850		0
Effective percentage rate		2.038%
Sempra Energy [Member] | Other Long-term Debt, Due October 2022 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		2.875%
Sempra Energy [Member] | Other Long-term Debt, Due December 2023 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		4.05%
Sempra Energy [Member] | Other Long Term Debt Due June 2024 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 500			500
Stated percentage rate		3.55%
Sempra Energy [Member] | Other Long-term Debt, Due November 2025 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 350			350
Stated percentage rate		3.75%
Sempra Energy [Member] | Other Long Term Debt Due June 2027 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 750			0
Stated percentage rate		3.25%
Sempra Energy [Member] | Other Long-Term Debt, Due October 2039 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 750			750
Stated percentage rate		6.00%
Sempra Energy [Member] | Market Value Adjustment For Interest Rate Swap [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ (1)			(3)
Sempra South American Utilities [Member]
Debt Instrument [Line Items]
Capital lease obligations		6			6
Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through October 2030 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 205			185
Stated percentage rate		4.25%
Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 53			75
Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Stated percentage rate		5.18%
Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated percentage rate		6.70%
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 415			346
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Stated percentage rate		4.75%
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated percentage rate		8.75%
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 6			7
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Stated percentage rate		3.77%
Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated percentage rate		4.61%
Sempra Mexico [Member] | Other Long-term Debt, Due February 2018 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 66			63
Variable percentage rate		2.66%
Sempra Mexico [Member] | Other Long Term Debt, Due February 2023 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 198			189
Stated percentage rate		6.30%
Effective percentage rate		4.12%
Sempra Mexico [Member] | Other Long-term Debt, Currently Through December 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 314			352
Stated percentage rate		4.63%
Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2028 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 300			0
Stated percentage rate		3.75%
Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 468			481
Stated percentage rate		6.67%
Long-term debt subject to fixed rate		$ 251
Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032, Variable Rate Two [Member]
Debt Instrument [Line Items]
Effective percentage rate		4.62%
Long-term debt subject to variable rate		$ 39
Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2048 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 540			0
Stated percentage rate		4.875%
Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032, Variable Rate One [Member]
Debt Instrument [Line Items]
Weighted average rate		6.29%
Long-term debt subject to variable rate		$ 178
Sempra Renewables [Member] | Other LongTerm Debt, Variable Rate Loan Payable Currently Through December 2028 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 77			84
Stated percentage rate		3.668%
Variable percentage rate		3.325%
Long-term debt subject to fixed rate		$ 59
Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 20			20
Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Stated percentage rate		2.87%
Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated percentage rate		3.51%
Sempra LNG & Midstream [Member] | Other Long Term Debt, Payable Currently Through December 2017 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 0			6
Stated percentage rate		8.45%
Other Sempra Energy [Member]
Debt Instrument [Line Items]
Long-term debt and capital lease obligations		$ 9,405			7,548
Current portion of long-term debt		(706)			(722)
Unamortized discount on long-term debt		(13)			(10)
Unamortized premium on long-term debt		4			4
Unamortized debt issuance costs		(65)			(31)
Long-term debt		8,625			6,789
LIBOR [Member] | Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]
Debt Instrument [Line Items]
Variable percentage rate	0.45%
Otay Mesa VIE [Member] | San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Current portion of long-term debt		(10)			(10)
Long-term debt		284			293
Otay Mesa VIE [Member] | San Diego Gas and Electric Company [Member] | Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member]
Debt Instrument [Line Items]
Gross long-term debt		$ 295			$ 305
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

DEBT AND CREDIT FACILITIES - MA

DEBT AND CREDIT FACILITIES - MATURITIES OF LONG-TERM DEBT (5 YEAR SCHEDULE) (Details)	Dec. 31, 2017USD ($)
Schedule Of Long Term Debt Maturities [Line Items]
2,018	$ 1,412,000,000
2,019	1,419,000,000
2,020	1,033,000,000
2,021	1,346,000,000
2,022	647,000,000
Thereafter	11,282,000,000
Long-term Debt Maturities, Total Repayments Of Principal	17,139,000,000
San Diego Gas and Electric Company [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2,018	207,000,000
2,019	321,000,000
2,020	36,000,000
2,021	385,000,000
2,022	18,000,000
Thereafter	3,901,000,000
Long-term Debt Maturities, Total Repayments Of Principal	4,868,000,000
Southern California Gas Company [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2,018	500,000,000
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	2,509,000,000
Long-term Debt Maturities, Total Repayments Of Principal	3,009,000,000
Other Sempra Energy [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2,018	705,000,000
2,019	1,098,000,000
2,020	997,000,000
2,021	961,000,000
2,022	629,000,000
Thereafter	4,872,000,000
Long-term Debt Maturities, Total Repayments Of Principal	$ 9,262,000,000

DEBT AND CREDIT FACILITIES - UN

DEBT AND CREDIT FACILITIES - UNSECURED DEBT (Details)	Dec. 31, 2017USD ($)
Unsecured Debt [Line Items]
Unsecured debt	$ 8,400,000,000
Southern California Gas Company [Member]
Unsecured Debt [Line Items]
Unsecured debt	9,000,000
San Diego Gas and Electric Company [Member]
Unsecured Debt [Line Items]
Unsecured debt	$ 0

DEBT AND CREDIT FACILITIES - CA

DEBT AND CREDIT FACILITIES - CALLABLE LONG-TERM DEBT (Details) $ in Millions	Dec. 31, 2017USD ($)
Schedule Of Callable Long-term Debt [Line Items]
Callable Long-term Debt	$ 513
Callable Long term Debt Subject To Make Whole Provisions	14,224
Southern California Gas Company [Member]
Schedule Of Callable Long-term Debt [Line Items]
Callable Long-term Debt	4
Callable Long term Debt Subject To Make Whole Provisions	3,005
Other Sempra Energy [Member]
Schedule Of Callable Long-term Debt [Line Items]
Callable Long-term Debt	97
Callable Long term Debt Subject To Make Whole Provisions	7,058
San Diego Gas and Electric Company [Member]
Schedule Of Callable Long-term Debt [Line Items]
Callable Long-term Debt	412
Callable Long term Debt Subject To Make Whole Provisions	4,161
Otay Mesa Energy Center [Member]
Schedule Of Callable Long-term Debt [Line Items]
Callable Long-term Debt	$ 295

DEBT AND CREDIT FACILITIES - FI

DEBT AND CREDIT FACILITIES - FIRST MORTGAGE BONDS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
San Diego Gas and Electric Company [Member]
First Mortgage Bonds [Line Items]
First mortgage bonds available for future issuance	$ 4,700
Gross long-term debt	4,573		$ 4,349
Southern California Gas Company [Member]
First Mortgage Bonds [Line Items]
First mortgage bonds available for future issuance	1,100
Gross long-term debt	3,000		3,000
First Mortgage Bonds, Due June 2047 [Member] | San Diego Gas and Electric Company [Member]
First Mortgage Bonds [Line Items]
Gross long-term debt	$ 400	$ 400	$ 0
Stated percentage rate	3.75%	3.75%

DEBT AND CREDIT FACILITIES - OT

DEBT AND CREDIT FACILITIES - OTHER LONG-TERM DEBT (Details) - USD ($)	Oct. 13, 2017	Dec. 14, 2016	Jun. 30, 2017	Dec. 31, 2015	Jan. 31, 2018	Dec. 31, 2017	Oct. 30, 2017	Feb. 28, 2017	Dec. 31, 2016
Sempra Energy [Member] | Other Long-term Debt, Due October 2019 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 500,000,000			$ 500,000,000
Stated percentage rate						1.625%
Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 850,000,000	$ 850,000,000		0
Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Variable percentage rate	0.45%
Sempra Energy [Member] | Fixed Rate Notes Maturing in 2027 [Member]
Debt Instrument [Line Items]
Stated percentage rate			3.25%
Debt amount			$ 750,000,000
San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 4,573,000,000			4,349,000,000
Luz Del Sur [Member] | South America Utilities [Member] | Corporate Bonds Maturing in 2023 [Member]
Debt Instrument [Line Items]
Stated percentage rate								6.375%
Debt amount								$ 50,000,000
Luz Del Sur [Member] | South America Utilities [Member] | Corporate Bonds Maturing in 2027 [Member]
Debt Instrument [Line Items]
Stated percentage rate						5.9375%
Debt amount						$ 50,000,000
IEnova [Member] | Sempra Mexico [Member] | Ventika [Member]
Debt Instrument [Line Items]
Power purchase agreement term		20 years
Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 468,000,000			481,000,000
Stated percentage rate						6.67%
Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2028 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 300,000,000			0
Stated percentage rate						3.75%
Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2048 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 540,000,000			$ 0
Stated percentage rate						4.875%
Subsequent Event [Member] | Sempra Energy [Member] | Fixed and Variable Rate Notes [Member]
Debt Instrument [Line Items]
Gross long-term debt					$ 5,000,000,000
Peaker Plant Facility [Member] | San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Power purchase agreement term				25 years
Capital lease obligations incurred			$ 500,000,000

INCOME TAXES - RECONCILIATION T

INCOME TAXES - RECONCILIATION TO EFFECTIVE TAX RATE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. federal statutory income tax rate	35.00%	35.00%	35.00%
Effects of the TCJA	55.00%	0.00%	0.00%
Utility depreciation	6.00%	4.00%	5.00%
Foreign exchange and inflation effects	3.00%	(2.00%)	(2.00%)
Utility repairs expenditures	(6.00%)	(4.00%)	(5.00%)
Tax credits	(4.00%)	(3.00%)	(4.00%)
Self-developed software expenditures	(4.00%)	(3.00%)	(3.00%)
Non-U.S. earnings taxed at lower statutory income tax rates	(3.00%)	(3.00%)	(2.00%)
Allowance for equity funds used during construction	(3.00%)	(2.00%)	(2.00%)
Resolution of prior years’ income tax items	(2.00%)	0.00%	(3.00%)
Share-based compensation	0.00%	(2.00%)	0.00%
State income taxes, net of federal income tax benefit	1.00%	1.00%	1.00%
Other, net	3.00%	0.00%	0.00%
Effective income tax rate	81.00%	21.00%	20.00%
Income before Income Taxes, Domestic	$ 878	$ 773	$ 1,189
Income before Income Taxes, Foreign	707	1,057	515
Income before income taxes	$ 1,585	$ 1,830	$ 1,704
San Diego Gas and Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. federal statutory income tax rate	35.00%	35.00%	35.00%
Effects of the TCJA	5.00%	0.00%	0.00%
Utility depreciation	7.00%	5.00%	4.00%
Utility repairs expenditures	(8.00%)	(4.00%)	(4.00%)
Self-developed software expenditures	(6.00%)	(3.00%)	(3.00%)
Allowance for equity funds used during construction	(4.00%)	(2.00%)	(2.00%)
Resolution of prior years’ income tax items	(4.00%)	(1.00%)	(2.00%)
Share-based compensation	0.00%	(1.00%)	0.00%
State income taxes, net of federal income tax benefit	3.00%	5.00%	5.00%
Other, net	(1.00%)	(1.00%)	(1.00%)
Effective income tax rate	27.00%	33.00%	32.00%
Income before income taxes	$ 576	$ 845	$ 890
Southern California Gas Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. federal statutory income tax rate	35.00%	35.00%	35.00%
Utility depreciation	9.00%	9.00%	8.00%
Utility repairs expenditures	(8.00%)	(9.00%)	(10.00%)
Self-developed software expenditures	(5.00%)	(6.00%)	(6.00%)
Allowance for equity funds used during construction	(3.00%)	(2.00%)	(2.00%)
Resolution of prior years’ income tax items	(2.00%)	2.00%	(3.00%)
Share-based compensation	0.00%	(1.00%)	0.00%
State income taxes, net of federal income tax benefit	3.00%	2.00%	4.00%
Other, net	0.00%	(1.00%)	(1.00%)
Effective income tax rate	29.00%	29.00%	25.00%
Income before income taxes	$ 557	$ 493	$ 558

INCOME TAXES - EFFECTS OF THE T

INCOME TAXES - EFFECTS OF THE TAX CUTS AND JOBS ACT OF 2017 (Details) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 27, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Effect of Changes in Legislation of Income Tax (Expense) [Line Items]
Decrease in net deferred income tax liabilities due to remeasurement		$ (2,220)
Increase in net regulatory liabilities from remeasurement of deferred tax income tax assets and liabilities		2,402
Income tax expense, related to remeasurement of deferred income tax assets and liabilities		182
Income tax expense related to deemed repatriation		328
U.S. state and non-U.S. withholding tax expense, related to expected future repatriation of foreign earnings		360
Total increase in income tax expense		$ 870
U.S. federal statutory income tax rate		35.00%	35.00%	35.00%
Foreign undistributed earnings		$ 4,000
Undistributed earnings of foreign subsidiaries considered to be indefinitely reinvested		1,000
San Diego Gas and Electric Company [Member]
Schedule of Effect of Changes in Legislation of Income Tax (Expense) [Line Items]
Decrease in net deferred income tax liabilities due to remeasurement		(1,400)
Increase in net regulatory liabilities from remeasurement of deferred tax income tax assets and liabilities		1,428
Income tax expense, related to remeasurement of deferred income tax assets and liabilities		28
Income tax expense related to deemed repatriation		0
U.S. state and non-U.S. withholding tax expense, related to expected future repatriation of foreign earnings		0
Total increase in income tax expense		$ 28
U.S. federal statutory income tax rate		35.00%	35.00%	35.00%
Southern California Gas Company [Member]
Schedule of Effect of Changes in Legislation of Income Tax (Expense) [Line Items]
Decrease in net deferred income tax liabilities due to remeasurement		$ (972)
Increase in net regulatory liabilities from remeasurement of deferred tax income tax assets and liabilities		974
Income tax expense, related to remeasurement of deferred income tax assets and liabilities		2
Income tax expense related to deemed repatriation		0
U.S. state and non-U.S. withholding tax expense, related to expected future repatriation of foreign earnings		0
Total increase in income tax expense		$ 2
U.S. federal statutory income tax rate		35.00%	35.00%	35.00%
Subsequent Event [Member]
Schedule of Effect of Changes in Legislation of Income Tax (Expense) [Line Items]
U.S. federal statutory income tax rate	21.00%
U.S. federal statutory income tax rate on foreign earning held as cash and cash equivalents	15.50%
U.S. federal statutory income tax rate on foreign other accumulated earnings	8.00%

INCOME TAXES - COMPONENTS OF IN

INCOME TAXES - COMPONENTS OF INCOME TAX EXPENSE (BENEFIT) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	$ 0	$ 0	$ 3
U.S. state	0	1	(24)
Non-U.S.	116	171	123
Total	116	172	102
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	536	78	242
U.S. state	297	9	34
Non-U.S.	327	135	(32)
Total	1,160	222	244
Deferred investment tax credits	0	(5)	(5)
Total income tax expense	1,276	389	341
San Diego Gas and Electric Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	100	0	12
U.S. state	65	22	77
Total	165	22	89
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	29	223	233
U.S. state	(41)	38	(35)
Total	(12)	261	198
Deferred investment tax credits	2	(3)	(3)
Total income tax expense	155	280	284
Southern California Gas Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	0	0	(1)
U.S. state	23	40	12
Total	23	40	11
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal	144	123	122
U.S. state	(5)	(18)	7
Total	139	105	129
Deferred investment tax credits	(2)	(2)	(2)
Total income tax expense	$ 160	$ 143	$ 138

INCOME TAXES - DEFERRED INCOME

INCOME TAXES - DEFERRED INCOME TAXES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, Gross [Abstract]
Less: valuation allowances	$ 133	$ 31
Deferred income taxes, noncurrent	170	234	[1]
Deferred income tax liabilities, noncurrent	2,767	3,745	[1]
Sempra Energy Consolidated [Member]
Deferred Tax Liabilities, Gross [Abstract]
Differences in financial and tax bases of fixed assets, investments and other assets	4,233	6,111
U.S. state and non-U.S. withholding tax on repatriation of foreign earnings	360	0
Regulatory balancing accounts	376	783
Property taxes	37	63
Other deferred income tax liabilities	117	143
Total deferred income tax liabilities	5,123	7,100
Deferred Tax Assets, Gross [Abstract]
Tax credits	1,066	431
Net operating losses	968	2,304
Compensation-related items	199	252
Postretirement benefits	251	434
Other deferred income tax assets	115	87
Accrued expenses not yet deductible	60	112
Deferred income tax assets before valuation allowances	2,659	3,620
Less: valuation allowances	133	31
Total deferred income tax assets	2,526	3,589
Net deferred income tax liability	2,597	3,511
Deferred income taxes, noncurrent	170	234
Deferred income tax liabilities, noncurrent	2,767	3,745
San Diego Gas and Electric Company [Member]
Deferred Tax Liabilities, Gross [Abstract]
Differences in financial and tax bases of fixed assets, investments and other assets	1,472	2,549
Regulatory balancing accounts	113	379
Property taxes	26	42
Other deferred income tax liabilities	10	10
Total deferred income tax liabilities	1,621	2,980
Deferred Tax Assets, Gross [Abstract]
Tax credits	7	27
Net operating losses	0	0
Compensation-related items	5	8
Postretirement benefits	43	98
Other deferred income tax assets	19	11
State income taxes	14	0
Accrued expenses not yet deductible	3	7
Total deferred income tax assets	91	151
Net deferred income tax liability	1,530	2,829
Deferred income tax liabilities, noncurrent	1,530	2,829	[1]
Southern California Gas Company [Member]
Deferred Tax Liabilities, Gross [Abstract]
Differences in financial and tax bases of fixed assets, investments and other assets	987	1,699
Regulatory balancing accounts	271	411
Property taxes	12	21
Other deferred income tax liabilities	1	4
Total deferred income tax liabilities	1,271	2,135
Deferred Tax Assets, Gross [Abstract]
Tax credits	15	17
Net operating losses	58	83
Compensation-related items	25	32
Postretirement benefits	152	244
Other deferred income tax assets	7	11
State income taxes	7	19
Accrued expenses not yet deductible	12	20
Total deferred income tax assets	276	426
Net deferred income tax liability	995	1,709
Deferred income tax liabilities, noncurrent	$ 995	$ 1,709	[1]
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

INCOME TAXES - NET OPERATING LO

INCOME TAXES - NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Valuation allowances	$ 133	$ 31
U.S. Federal [Member]
Operating Loss Carryforwards [Line Items]
NOLs	3,145
U.S. Federal [Member] | General business tax credits [Member]
Operating Loss Carryforwards [Line Items]
Tax credits	389
U.S. Federal [Member] | Foreign tax credits [Member]
Operating Loss Carryforwards [Line Items]
Tax credits	631
Valuation allowances	83
U.S. state [Member]
Operating Loss Carryforwards [Line Items]
NOLs	2,295
U.S. state [Member] | General business tax credits [Member]
Operating Loss Carryforwards [Line Items]
Tax credits	51
U.S. state [Member] | Deferred Tax Assets, Operating Loss and Tax Credit Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowances	30	30
Non-U.S. [Member]
Operating Loss Carryforwards [Line Items]
NOLs	607
Non-U.S. [Member] | Deferred Tax Assets, Operating Loss Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowances	20	$ 1
Southern California Gas Company [Member] | U.S. Federal [Member]
Operating Loss Carryforwards [Line Items]
NOLs	334
Southern California Gas Company [Member] | U.S. Federal [Member] | General business tax credits [Member]
Operating Loss Carryforwards [Line Items]
Tax credits	$ 12

INCOME TAXES - UNRECOGNIZED TAX

INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits
Beginning balance	$ 90	$ 87	$ 117
Increase in prior period tax positions	22	2	10
Decrease in prior period tax positions	(15)	(2)	0
Increase in current period tax positions	4	6	8
Settlements with taxing authorities	(12)	(3)	(48)
Ending balance	89	90	87
Of the total, amounts related to tax positions that, if recognized, in future years, would decrease the effective tax rate	(77)	(87)	(83)
Of the total, amounts related to tax positions that, if recognized, in future years, would increase the effective tax rate	20	36	32
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Accrued interest and penalties	0	1	0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense [Abstract]
Interest income and penalties on unrecognized income tax benefits	0	0	2
San Diego Gas and Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits
Beginning balance	22	20	14
Increase in prior period tax positions	9	0	5
Decrease in prior period tax positions	(11)	0	0
Increase in current period tax positions	0	2	2
Settlements with taxing authorities	(10)	0	(1)
Ending balance	10	22	20
Of the total, amounts related to tax positions that, if recognized, in future years, would decrease the effective tax rate	(7)	(19)	(16)
Of the total, amounts related to tax positions that, if recognized, in future years, would increase the effective tax rate	1	13	11
Southern California Gas Company [Member]
Reconciliation of Unrecognized Tax Benefits
Beginning balance	29	27	19
Increase in prior period tax positions	3	0	2
Decrease in prior period tax positions	0	(2)	0
Increase in current period tax positions	4	4	6
Settlements with taxing authorities	(1)	0	0
Ending balance	35	29	27
Of the total, amounts related to tax positions that, if recognized, in future years, would decrease the effective tax rate	(26)	(29)	(27)
Of the total, amounts related to tax positions that, if recognized, in future years, would increase the effective tax rate	$ 20	$ 24	$ 21

INCOME TAXES - CHANGES IN UNREC

INCOME TAXES - CHANGES IN UNRECOGNIZED TAX BENEFITS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	$ (8)	$ (38)	$ (34)
San Diego Gas and Electric Company [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	(6)	(11)	(9)
Expiration of statutes of limitations on tax assessments [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	0	(2)	(2)
Expiration of statutes of limitations on tax assessments [Member] | San Diego Gas and Electric Company [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	0	(1)	(1)
Potential resolution of audit issues with various U.S. federal, state, and local non-U.S. taxing authorities [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	(8)	(36)	(32)
Potential resolution of audit issues with various U.S. federal, state, and local non-U.S. taxing authorities [Member] | San Diego Gas and Electric Company [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	(6)	(10)	(8)
Potential resolution of audit issues with various U.S. federal, state, and local non-U.S. taxing authorities [Member] | Southern California Gas Company [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Possible change in unrecognized tax benefits in next 12 months	$ (2)	$ (25)	$ (22)

EMPLOYEE BENEFIT PLANS - NARRAT

EMPLOYEE BENEFIT PLANS - NARRATIVE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Dedicated assets in support of certain benefit plans	$ 455	$ 430	[1]
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Change in plan liability due to divestiture	0	61
Change in plan assets due to divestiture	0	44
Increase in liability due to special termination benefits	0	0
Settlements	194	75
Settlement charge	38	16
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Change in plan liability due to divestiture	0	6
Change in plan assets due to divestiture	0	4
Increase in liability due to special termination benefits	18	26
Settlements	0	1
San Diego Gas and Electric Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in liability due to special termination benefits	0	0
Settlements	0	75
Settlement charge	0	16		$ 0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in liability due to special termination benefits	0	14
Settlements	0	0
Settlement charge	0	0		0
Southern California Gas Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in liability due to special termination benefits	0	0
Settlements	175	0
Settlement charge	30	0		0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in liability due to special termination benefits	18	11
Settlements	0	0
Settlement charge	$ 0	$ 0		$ 0
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

EMPLOYEE BENEFIT PLANS - EMPLOY

EMPLOYEE BENEFIT PLANS - EMPLOYEE BENEFIT PLANS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Liability, Defined Benefit Plan [Abstract]
Noncurrent liabilities	$ (1,148,000,000)	$ (1,208,000,000)	[1]
Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]
Net actuarial gain (loss) expected to be amortized next year	(10,000,000)
Prior service cost (credit) expected to be amortized next year	$ 1,000,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	7.00%
Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	$ 3,679,000,000	3,649,000,000
Service cost	117,000,000	107,000,000		$ 114,000,000
Interest cost	151,000,000	160,000,000		154,000,000
Contributions from plan participants	0	0
Actuarial loss (gain)	286,000,000	116,000,000
Benefit payments	(182,000,000)	(217,000,000)
Divestiture of EnergySouth	0	(61,000,000)
Plan amendments	1,000,000	0
Special termination benefits	0	0
Curtailments	(1,000,000)	0
Settlements	(194,000,000)	(75,000,000)
Ending balance	3,857,000,000	3,679,000,000		3,649,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	2,459,000,000	2,484,000,000
Actual return on plan assets	421,000,000	207,000,000
Employer contributions	155,000,000	104,000,000
Contributions from plan participants	0	0
Benefit payments	(182,000,000)	(217,000,000)
Divestiture of EnergySouth	0	(44,000,000)
Settlements	(194,000,000)	(75,000,000)
Ending balance	2,659,000,000	2,459,000,000		2,484,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	(1,198,000,000)	(1,220,000,000)
Net recorded liability	(1,198,000,000)	(1,220,000,000)
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	0	0
Current liabilities	(69,000,000)	(56,000,000)
Noncurrent liabilities	(1,129,000,000)	(1,164,000,000)
Net recorded (liability) asset	(1,198,000,000)	(1,220,000,000)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net actuarial (loss) gain	(84,000,000)	(95,000,000)
Prior service cost	(4,000,000)	(4,000,000)
Total	(88,000,000)	(99,000,000)
Accumulated benefit obligation	3,551,000,000	3,465,000,000
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Projected benefit obligation	3,623,000,000	3,431,000,000
Accumulated benefit obligation	3,334,000,000	3,227,000,000
Fair value of plan assets	2,659,000,000	2,459,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	117,000,000	107,000,000		114,000,000
Interest cost	151,000,000	160,000,000		154,000,000
Expected return on assets	(161,000,000)	(166,000,000)		(173,000,000)
Amortization of Prior service cost (credit)	11,000,000	11,000,000		11,000,000
Amortization of actuarial loss (gain)	36,000,000	30,000,000		38,000,000
Settlement and curtailment charges	38,000,000	16,000,000		4,000,000
Settlement charge	38,000,000	16,000,000
Special termination benefits	0	0		0
Regulatory adjustment	(42,000,000)	(57,000,000)		(110,000,000)
Defined Benefit Plan, Net Periodic Benefit Cost, Total	150,000,000	101,000,000		38,000,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	0	26,000,000		17,000,000
Prior service cost	1,000,000	0		4,000,000
Amortization of actuarial loss	(18,000,000)	(10,000,000)		(14,000,000)
Amortization of prior service cost	(1,000,000)	(1,000,000)		0
Total recognized in OCI	(18,000,000)	15,000,000		7,000,000
Total recognized in net periodic benefit cost and OCI	$ 132,000,000	$ 116,000,000		$ 45,000,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.65%	4.08%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.08%	4.46%		4.09%
Expected return on plan assets	7.00%	7.00%		7.00%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Expected employer contributions	$ 226,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	351,000,000
2,019	304,000,000
2,020	294,000,000
2,021	285,000,000
2,022	273,000,000
2023-2027	$ 1,217,000,000
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	$ 922,000,000	$ 963,000,000
Service cost	21,000,000	20,000,000		$ 26,000,000
Interest cost	39,000,000	42,000,000		44,000,000
Contributions from plan participants	20,000,000	20,000,000
Actuarial loss (gain)	6,000,000	(81,000,000)
Benefit payments	(63,000,000)	(61,000,000)
Divestiture of EnergySouth	0	(6,000,000)
Plan amendments	0	0
Special termination benefits	18,000,000	26,000,000
Curtailments	0	0
Settlements	0	(1,000,000)
Ending balance	963,000,000	922,000,000		963,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	1,057,000,000	1,003,000,000
Actual return on plan assets	185,000,000	94,000,000
Employer contributions	10,000,000	6,000,000
Contributions from plan participants	20,000,000	20,000,000
Benefit payments	(63,000,000)	(61,000,000)
Divestiture of EnergySouth	0	(4,000,000)
Settlements	0	(1,000,000)
Ending balance	1,209,000,000	1,057,000,000		1,003,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	246,000,000	135,000,000
Net recorded liability	246,000,000	135,000,000
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	266,000,000	179,000,000
Current liabilities	(1,000,000)	0
Noncurrent liabilities	(19,000,000)	(44,000,000)
Net recorded (liability) asset	246,000,000	135,000,000
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net actuarial (loss) gain	4,000,000	3,000,000
Prior service cost	0	0
Total	4,000,000	3,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	21,000,000	20,000,000		26,000,000
Interest cost	39,000,000	42,000,000		44,000,000
Expected return on assets	(66,000,000)	(69,000,000)		(68,000,000)
Amortization of Prior service cost (credit)	1,000,000	0		(4,000,000)
Amortization of actuarial loss (gain)	(4,000,000)	(1,000,000)		0
Settlement and curtailment charges	0	0		0
Special termination benefits	18,000,000	26,000,000		0
Regulatory adjustment	0	(11,000,000)		12,000,000
Defined Benefit Plan, Net Periodic Benefit Cost, Total	9,000,000	7,000,000		10,000,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	(2,000,000)	(2,000,000)		(4,000,000)
Prior service cost	0	0		0
Amortization of actuarial loss	0	0		0
Amortization of prior service cost	0	0		0
Total recognized in OCI	(2,000,000)	(2,000,000)		(4,000,000)
Total recognized in net periodic benefit cost and OCI	$ 7,000,000	$ 5,000,000		$ 6,000,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.70%	4.19%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.19%	4.49%		4.15%
Expected return on plan assets	6.47%	6.98%		6.98%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost	$ 5,000,000
Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(4,000,000)
Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations	53,000,000
Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations	(44,000,000)
Expected employer contributions	9,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	52,000,000
2,019	52,000,000
2,020	54,000,000
2,021	53,000,000
2,022	53,000,000
2023-2027	$ 262,000,000
Other Postretirement Benefits Plan [Member] | Pre-65Retiree [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	7.00%	8.00%		8.10%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	5.00%	5.00%		5.00%
Year the rate reaches the ultimate trend	2,022	2,022		2,022
Other Postretirement Benefits Plan [Member] | Retiree Aged 65 or Older [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	5.00%	5.50%		5.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	4.50%	4.50%		4.50%
Year the rate reaches the ultimate trend	2,022	2,022		2,022
Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
Southern California Gas Company [Member]
Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]
Net actuarial gain (loss) expected to be amortized next year	$ (1,000,000)
Prior service cost (credit) expected to be amortized next year	1,000,000
Southern California Gas Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	2,343,000,000	$ 2,255,000,000
Service cost	76,000,000	67,000,000		$ 74,000,000
Interest cost	98,000,000	101,000,000		98,000,000
Contributions from plan participants	0	0
Actuarial loss (gain)	216,000,000	77,000,000
Benefit payments	(73,000,000)	(158,000,000)
Special termination benefits	0	0
Settlements	(175,000,000)	0
Transfer of liability from (to) other plans	1,000,000	1,000,000
Ending balance	2,486,000,000	2,343,000,000		2,255,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	1,579,000,000	1,537,000,000
Actual return on plan assets	269,000,000	128,000,000
Employer contributions	93,000,000	72,000,000
Contributions from plan participants	0	0
Benefit payments	(73,000,000)	(158,000,000)
Transfer of assets from other plans	1,000,000	0
Settlements	(175,000,000)	0
Ending balance	1,694,000,000	1,579,000,000		1,537,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	(792,000,000)	(764,000,000)
Net recorded liability	(792,000,000)	(764,000,000)
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	0	0
Current liabilities	(3,000,000)	(2,000,000)
Noncurrent liabilities	(789,000,000)	(762,000,000)
Net recorded (liability) asset	(792,000,000)	(764,000,000)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net actuarial (loss) gain	(6,000,000)	(6,000,000)
Prior service cost	(2,000,000)	(3,000,000)
Total	(8,000,000)	(9,000,000)
Accumulated benefit obligation	2,241,000,000	2,167,000,000
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Projected benefit obligation	2,462,000,000	2,320,000,000
Accumulated benefit obligation	2,220,000,000	2,148,000,000
Fair value of plan assets	1,694,000,000	1,579,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	76,000,000	67,000,000		74,000,000
Interest cost	98,000,000	101,000,000		98,000,000
Expected return on assets	(103,000,000)	(103,000,000)		(106,000,000)
Amortization of Prior service cost (credit)	9,000,000	9,000,000		9,000,000
Amortization of actuarial loss (gain)	19,000,000	11,000,000		21,000,000
Settlement charge	30,000,000	0		0
Special termination benefits	0	0		0
Regulatory adjustment	(34,000,000)	(12,000,000)		(90,000,000)
Defined Benefit Plan, Net Periodic Benefit Cost, Total	95,000,000	73,000,000		6,000,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	0	4,000,000		0
Prior service cost	0	2,000,000		2,000,000
Amortization of prior service cost	(1,000,000)	0		0
Total recognized in OCI	(1,000,000)	6,000,000		2,000,000
Total recognized in net periodic benefit cost and OCI	$ 94,000,000	$ 79,000,000		$ 8,000,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.65%	4.10%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.10%	4.50%		4.15%
Expected return on plan assets	7.00%	7.00%		7.00%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Expected employer contributions	$ 113,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	192,000,000
2,019	188,000,000
2,020	179,000,000
2,021	173,000,000
2,022	172,000,000
2023-2027	$ 782,000,000
Southern California Gas Company [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
Southern California Gas Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	$ 691,000,000	$ 752,000,000
Service cost	14,000,000	14,000,000		$ 17,000,000
Interest cost	29,000,000	32,000,000		34,000,000
Contributions from plan participants	13,000,000	13,000,000
Actuarial loss (gain)	16,000,000	(86,000,000)
Benefit payments	(44,000,000)	(45,000,000)
Special termination benefits	18,000,000	11,000,000
Settlements	0	0
Transfer of liability from (to) other plans	0	0
Ending balance	737,000,000	691,000,000		752,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	870,000,000	822,000,000
Actual return on plan assets	151,000,000	79,000,000
Employer contributions	3,000,000	1,000,000
Contributions from plan participants	13,000,000	13,000,000
Benefit payments	(44,000,000)	(45,000,000)
Transfer of assets from other plans	0	0
Settlements	0	0
Ending balance	993,000,000	870,000,000		822,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	256,000,000	179,000,000
Net recorded liability	256,000,000	179,000,000
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	256,000,000	179,000,000
Current liabilities	0	0
Noncurrent liabilities	0	0
Net recorded (liability) asset	256,000,000	179,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	14,000,000	14,000,000		17,000,000
Interest cost	29,000,000	32,000,000		34,000,000
Expected return on assets	(53,000,000)	(56,000,000)		(56,000,000)
Amortization of Prior service cost (credit)	(3,000,000)	(4,000,000)		(7,000,000)
Amortization of actuarial loss (gain)	(3,000,000)	0		0
Settlement charge	0	0		0
Special termination benefits	18,000,000	11,000,000		0
Regulatory adjustment	0	3,000,000		12,000,000
Defined Benefit Plan, Net Periodic Benefit Cost, Total	2,000,000	0		0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	0	0		0
Prior service cost	0	0		0
Amortization of prior service cost	0	0		0
Total recognized in OCI	0	0		0
Total recognized in net periodic benefit cost and OCI	$ 2,000,000	$ 0		$ 0
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.70%	4.20%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.20%	4.50%		4.15%
Expected return on plan assets	6.37%	7.00%		7.00%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost	$ 4,000,000
Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(3,000,000)
Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations	48,000,000
Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations	(40,000,000)
Expected employer contributions	2,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	38,000,000
2,019	39,000,000
2,020	40,000,000
2,021	40,000,000
2,022	40,000,000
2023-2027	$ 197,000,000
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
San Diego Gas and Electric Company [Member]
Liability, Defined Benefit Plan [Abstract]
Noncurrent liabilities	$ (182,000,000)	$ (232,000,000)	[1]
Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]
Net actuarial gain (loss) expected to be amortized next year	(1,000,000)
Prior service cost (credit) expected to be amortized next year	0
San Diego Gas and Electric Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	935,000,000	965,000,000
Service cost	29,000,000	29,000,000		$ 29,000,000
Interest cost	38,000,000	41,000,000		39,000,000
Contributions from plan participants	0	0
Actuarial loss (gain)	50,000,000	7,000,000
Benefit payments	(83,000,000)	(25,000,000)
Special termination benefits	0	0
Settlements	0	(75,000,000)
Transfer of liability from (to) other plans	2,000,000	(7,000,000)
Ending balance	971,000,000	935,000,000		965,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	714,000,000	752,000,000
Actual return on plan assets	120,000,000	59,000,000
Employer contributions	22,000,000	3,000,000
Contributions from plan participants	0	0
Benefit payments	(83,000,000)	(25,000,000)
Transfer of assets from other plans	3,000,000	0
Settlements	0	(75,000,000)
Ending balance	776,000,000	714,000,000		752,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	(195,000,000)	(221,000,000)
Net recorded liability	(195,000,000)	(221,000,000)
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	0	0
Current liabilities	(13,000,000)	(10,000,000)
Noncurrent liabilities	(182,000,000)	(211,000,000)
Net recorded (liability) asset	(195,000,000)	(221,000,000)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net actuarial (loss) gain	(8,000,000)	(8,000,000)
Accumulated benefit obligation	930,000,000	904,000,000
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Projected benefit obligation	939,000,000	902,000,000
Accumulated benefit obligation	900,000,000	874,000,000
Fair value of plan assets	776,000,000	714,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	29,000,000	29,000,000		29,000,000
Interest cost	38,000,000	41,000,000		39,000,000
Expected return on assets	(47,000,000)	(49,000,000)		(54,000,000)
Amortization of Prior service cost (credit)	1,000,000	1,000,000		8,000,000
Amortization of actuarial loss (gain)	9,000,000	10,000,000		2,000,000
Settlement charge	0	16,000,000		0
Special termination benefits	0	0		0
Regulatory adjustment	(8,000,000)	(45,000,000)		(20,000,000)
Defined Benefit Plan, Net Periodic Benefit Cost, Total	22,000,000	3,000,000		4,000,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	2,000,000	1,000,000		(6,000,000)
Amortization of actuarial loss	(1,000,000)	(1,000,000)		(1,000,000)
Total recognized in OCI	1,000,000	0		(7,000,000)
Total recognized in net periodic benefit cost and OCI	$ 23,000,000	$ 3,000,000		$ (3,000,000)
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.64%	4.08%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.08%	4.35%		4.00%
Expected return on plan assets	7.00%	7.00%		7.00%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Expected employer contributions	$ 48,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	90,000,000
2,019	76,000,000
2,020	74,000,000
2,021	71,000,000
2,022	68,000,000
2023-2027	$ 314,000,000
San Diego Gas and Electric Company [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
San Diego Gas and Electric Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Beginning balance	$ 190,000,000	$ 165,000,000
Service cost	5,000,000	5,000,000		$ 7,000,000
Interest cost	8,000,000	7,000,000		8,000,000
Contributions from plan participants	7,000,000	7,000,000
Actuarial loss (gain)	(9,000,000)	6,000,000
Benefit payments	(16,000,000)	(14,000,000)
Special termination benefits	0	14,000,000
Settlements	0	0
Transfer of liability from (to) other plans	0	0
Ending balance	185,000,000	190,000,000		165,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	169,000,000	161,000,000
Actual return on plan assets	30,000,000	13,000,000
Employer contributions	5,000,000	2,000,000
Contributions from plan participants	7,000,000	7,000,000
Benefit payments	(16,000,000)	(14,000,000)
Transfer of assets from other plans	0	0
Settlements	0	0
Ending balance	195,000,000	169,000,000		161,000,000
Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]
Funded status	10,000,000	(21,000,000)
Net recorded liability	10,000,000	(21,000,000)
Liability, Defined Benefit Plan [Abstract]
Noncurrent assets	10,000,000	0
Current liabilities	0	0
Noncurrent liabilities	0	(21,000,000)
Net recorded (liability) asset	10,000,000	(21,000,000)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	5,000,000	5,000,000		7,000,000
Interest cost	8,000,000	7,000,000		8,000,000
Expected return on assets	(11,000,000)	(12,000,000)		(11,000,000)
Amortization of Prior service cost (credit)	3,000,000	3,000,000		3,000,000
Amortization of actuarial loss (gain)	0	(1,000,000)		0
Settlement charge	0	0		0
Special termination benefits	0	14,000,000		0
Regulatory adjustment	0	(14,000,000)		0
Defined Benefit Plan, Net Periodic Benefit Cost, Total	5,000,000	2,000,000		7,000,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]
Net loss (gain)	0	0		0
Amortization of actuarial loss	0	0		0
Total recognized in OCI	0	0		0
Total recognized in net periodic benefit cost and OCI	$ 5,000,000	$ 2,000,000		$ 7,000,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.65%	4.15%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.15%	4.50%		4.15%
Expected return on plan assets	6.91%	6.90%		6.91%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost	$ 1,000,000
Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	0
Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations	3,000,000
Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations	(2,000,000)
Expected employer contributions	3,000,000
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2,018	10,000,000
2,019	10,000,000
2,020	10,000,000
2,021	11,000,000
2,022	11,000,000
2023-2027	$ 52,000,000
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	10.00%	10.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	10.00%	10.00%		10.00%
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Rate of compensation increase	2.00%	2.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of compensation increase	2.00%	2.00%		2.00%
Mobile Gas [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year				8.10%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)				5.00%
Year the rate reaches the ultimate trend				2,022
Chilquinta Energia [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	3.00%	3.00%		3.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	3.00%	3.00%		3.00%
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

EMPLOYEE BENEFIT PLANS - PLAN A

EMPLOYEE BENEFIT PLANS - PLAN ASSETS (Details)	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.00%
Domestic Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	38.00%
International Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	26.00%
Long Credit [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	18.00%
Ultra-long duration government securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	8.00%
High Yield Credit [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	5.00%
Real Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted plan asset allocations	5.00%
Return Seeking Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset allocations	74.00%
Risk Mitigating Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset allocations	26.00%
Minimum [Member] | Return Seeking Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.00%
Minimum [Member] | Risk Mitigating Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	3.00%
Maximum [Member] | Return Seeking Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	9.00%
Maximum [Member] | Risk Mitigating Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.00%
Southern California Gas Company [Member] | Return Seeking Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset allocations	38.00%
Southern California Gas Company [Member] | Risk Mitigating Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset allocations	62.00%

EMPLOYEE BENEFIT PLANS - FAIR V

EMPLOYEE BENEFIT PLANS - FAIR VALUE OF PLAN ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 2,659	$ 2,459	$ 2,484
Cash and cash equivalents excluded	13	14
Accounts payable excluded	18	24
Pension Plan [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	946	884
Pension Plan [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	538	522
Pension Plan [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	102	127
Pension Plan [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	269	246
Pension Plan [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12	9
Pension Plan [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	338	346
Pension Plan [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	64	94
Pension Plan [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	14
Pension Plan [Member] | Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Pension Plan [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,276	2,242
Pension Plan [Member] | Common/collective trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	384	223
Pension Plan [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	4	4
Pension Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,664	2,469
Pension Plan [Member] | Level 1 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	946	884
Pension Plan [Member] | Level 1 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	538	522
Pension Plan [Member] | Level 1 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	102	127
Pension Plan [Member] | Level 1 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	242	214
Pension Plan [Member] | Level 1 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 1 [Member] | Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Plan [Member] | Level 1 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,828	1,747
Pension Plan [Member] | Level 2 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 2 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 2 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan [Member] | Level 2 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27	32
Pension Plan [Member] | Level 2 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12	9
Pension Plan [Member] | Level 2 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	338	346
Pension Plan [Member] | Level 2 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	64	94
Pension Plan [Member] | Level 2 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	14
Pension Plan [Member] | Level 2 [Member] | Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Pension Plan [Member] | Level 2 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	448	495
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,209	1,057	1,003
Other Postretirement Benefits Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,207	1,057
Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	438	436
Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	340	221
San Diego Gas and Electric Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	776	714	752
San Diego Gas and Electric Company [Member] | Pension Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	777	717
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	195	169	161
Cash and cash equivalents excluded	1	1
Accounts payable excluded	1	1
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	46	41
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26	24
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	52	46
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13	11
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17	16
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	3
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17	17
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175	158
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Common/collective trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	20	11
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	195	169
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	46	41
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26	24
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	52	46
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12	10
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	136	121
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17	16
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	3
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17	17
San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39	37
Southern California Gas Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,694	1,579	1,537
Southern California Gas Company [Member] | Pension Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,697	1,585
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	993	870	$ 822
Cash and cash equivalents excluded	4	4
Accounts payable excluded	2	4
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	78	130
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	77
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	41	46
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	138	60
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7	2
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	164	94
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	28
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85	47
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	585	484
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Common/collective trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	406	386
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	991	870
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	78	130
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	77
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	41	46
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	125	52
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	288	305
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13	8
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7	2
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	164	94
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	28
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85	47
Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	297	179
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7	6
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	3
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18	15
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Common/collective trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	2	3
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments measured at NAV	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Total fair value of plan assets excluding cash and cash equivalents and accounts payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	21	18
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7	6
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	3
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 1 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	10
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Equity Securities, Registered Investment Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | domestic government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	0
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International government bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Domestic corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | International corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Registered investment companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Other Sempra Energy [Member] | Other Postretirement Benefits Plan [Member] | Level 2 [Member] | Total investment assets in the fair value hierarchy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	5
Sempra Energy [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Cash and cash equivalents excluded	5	5
Accounts payable excluded	$ 3	$ 5

EMPLOYEE BENEFIT PLANS - PROFIT

EMPLOYEE BENEFIT PLANS - PROFIT SHARING PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Chilquinta Energia Profit Sharing [Member]
Profit Sharing Plans [Line Items]
Recorded Annual Profit Sharing Expense	$ 7	$ 5	$ 3
Luz del Sur Profit Sharing [Member]
Profit Sharing Plans [Line Items]
Recorded Annual Profit Sharing Expense	$ 12	$ 10	$ 10

EMPLOYEE BENEFIT PLANS - SAVING

EMPLOYEE BENEFIT PLANS - SAVINGS PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Savings Plan [Line Items]
Employer contributions to defined benefit plan	$ 41	$ 42	$ 43
Market value of employer stock held by plan	1,100	1,100
San Diego Gas and Electric Company [Member]
Savings Plan [Line Items]
Employer contributions to defined benefit plan	14	15	17
Southern California Gas Company [Member]
Savings Plan [Line Items]
Employer contributions to defined benefit plan	$ 22	$ 22	$ 21

SHARE-BASED COMPENSATION EXPENS

SHARE-BASED COMPENSATION EXPENSE/ OPTIONS (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Excess tax benefit			$ 52
Share-based compensation expense, before income taxes	$ 78	$ 46	48
Income tax benefit	(31)	(18)	(19)
Share-based compensation expense, net of taxes	47	28	29
Capitalized share-based compensation cost	9	7	6
Excess income tax benefit	$ 0	$ (34)	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Beginning balance	360,255
Exercised	(164,454)	(167,742)	(227,815)
Ending balance	195,801	360,255
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Beginning balance (in dollars per share)	$ 52.46
Exercised (in dollars per share)	55.04
Ending balance (in dollars per share)	$ 50.30	$ 52.46
Outstanding at period end, Weighted- average remaining contractual term	1 year 6 months
Outstanding at period end, Aggregate intrinsic value	$ 11
Vested at period end	195,801
Vested at period end, Weighted- average exercise price (in dollars per share)	$ 50.30
Vested at period end, Weighted- average remaining contractual term	1 year 6 months
Vested at period end, Aggregate intrinsic value	$ 11
Exercisable at period end	195,801
Exercisable at period end, Weighted- average exercise price (in dollars per share)	$ 50.30
Exercisable at period end, Weighted- average remaining contractual term	1 year 6 months
Exercisable at period end, Aggregate intrinsic value	$ 11
Aggregate intrinsic value of options exercised	$ 9	$ 8	$ 12
Options grants in period (in shares)	0	0	0
Cash received from exercise of options	$ 9
Restricted Stock Units Issued By Subsidiary, Outstanding	1,374,114
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	5,589,925
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	5,589,925
Restricted stock units issued by subsidary	1,043,709	378,367	278,538
San Diego Gas and Electric Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based compensation expense, before income taxes	$ 13	$ 7	$ 8
Income tax benefit	(5)	(3)	(3)
Share-based compensation expense, net of taxes	8	4	5
Capitalized share-based compensation cost	5	4	4
Excess income tax benefit	0	(7)	0
Southern California Gas Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based compensation expense, before income taxes	17	8	10
Income tax benefit	(7)	(3)	(4)
Share-based compensation expense, net of taxes	10	5	6
Capitalized share-based compensation cost	4	3	2
Excess income tax benefit	0	(4)	0
IENova Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Cash paid to settle awards	$ 2	$ 1	$ 4
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award vesting period	4 years
Expiration period	10 years
Restricted Stock Units (RSUs), Service-based [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	3 years
Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	4 years
Awarded During Or After Two Thousand and Fourteen [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award vesting rights maximum additional award	100.00%
Awarded during or after two thousand fifteen [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award vesting rights maximum additional award	100.00%
Award vesting rights, Increase modifier for top quartile	20.00%
Award vesting rights, decrease modifier for bottom quartile	20.00%
Awarded during or after two thousand fifteen [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	3 years
Awards Granted in 2013 and Earlier [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award vesting rights maximum additional award	50.00%
Awards Before 2015 [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	4 years
Awards Before 2015 [Member] | Restricted Stock Units (RSUs), Service-based [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	4 years
Minimum [Member] | Other Performance-Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	2 years
Minimum [Member] | Restricted Stock Units, Employee Stock Options, or Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	3 years
Maximum [Member] | Other Performance-Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	3 years
Maximum [Member] | Restricted Stock Units, Employee Stock Options, or Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Award requisite service period	4 years

- RSAs and RSUs (Details)

- RSAs and RSUs (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Maximum Performance Based RSU Target Performance Conditions Exceeded Through 2013	50.00%
Maximum Performance Based RSU Target Performance Conditions Exceeded For Awards Granted during or after 2014	100.00%
Share-Based Compensation, Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	17.00%	16.00%	14.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.50%	1.30%	1.10%
Share-Based Compensation, Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 17
Weighted average period over which unrecognized compensation cost will be recognized	1 year 10 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 45	$ 46	$ 46
Share-Based Compensation, Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 0	$ 1
Share-Based Compensation, Performance Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Beginning Balance	1,954,322
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period	$ 88.58
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	424,760
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 110.54	$ 100.37	$ 123.30
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(637,577)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 57.42
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(39,888)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 103.17
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Ending Balance	1,701,617	1,954,322
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, End of Period	$ 105.84	$ 88.58
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Vested And Expected To Vest, Outstanding, Number	1,670,885
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Vested And Expected To Vest, Weighted Average Grant Date Fair Value	$ 105.38
Share-Based Compensation, Service Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Beginning Balance	305,736
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period	$ 94.68
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	93,619
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 101.88	$ 93.59	$ 111.43
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(108,880)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 79.61
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(4,580)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 97.84
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Ending Balance	285,895	305,736
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, End of Period	$ 98.81	$ 94.68
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Vested And Expected To Vest, Outstanding, Number	282,106
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Vested And Expected To Vest, Weighted Average Grant Date Fair Value	$ 98.65

DERIVATIVE FINANCIAL INSTRUM102

DERIVATIVE FINANCIAL INSTRUMENTS - COMMODITY VOLUMES (Details) MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2017MWhMMBTU	Dec. 31, 2016MWhMMBTU
SDG&E [Member] | Natural Gas Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure	39	48
SDG&E [Member] | Electric Energy Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure | MWh	3	4
SDG&E [Member] | Congestion Revenue Rights Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure | MWh	59	48
SoCalGas [Member] | Natural Gas Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure	0	1
Sempra LNG & Midstream [Member] | Natural Gas Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure	3	31
Sempra Mexico [Member] | Natural Gas Derivative [Member]
Derivatives, Fair Value [Line Items]
Notional Amount, Energy Measure	4	0

DERIVATIVE FINANCIAL INSTRUM103

DERIVATIVE FINANCIAL INSTRUMENTS - NOTIONALS AMOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2018
Cross-currency swaps [Member]
Derivatives, Fair Value [Line Items]
Notional amount of derivative liability	$ 408	$ 408
Other foreign currency derivatives [Member]
Derivatives, Fair Value [Line Items]
Notional amount of derivative liability	345	86
Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Notional amount of derivative liability	$ 861	$ 924
Minimum [Member] | Cross-currency swaps [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2017
Minimum [Member] | Other foreign currency derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2017
Minimum [Member] | Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2017
Maximum [Member] | Cross-currency swaps [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2023	Dec. 31, 2023
Maximum [Member] | Other foreign currency derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2019	Dec. 31, 2018
Maximum [Member] | Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2032	Dec. 31, 2032
Subsequent Event [Member] | Other foreign currency derivatives [Member]
Derivatives, Fair Value [Line Items]
Notional amount of derivative liability			$ 650
San Diego Gas and Electric Company [Member] | Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Notional amount of derivative liability	$ 295	$ 305
San Diego Gas and Electric Company [Member] | Minimum [Member] | Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2017
San Diego Gas and Electric Company [Member] | Maximum [Member] | Cash Flow Hedging [Member] | Interest rate instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative, Maturity Date	Dec. 31, 2019	Dec. 31, 2019

DERIVATIVE FINANCIAL INSTRUM104

DERIVATIVE FINANCIAL INSTRUMENTS - BALANCE SHEET (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	$ 47,000,000	$ 41,000,000
Additional margin posted for commodity contracts not subject to rate recovery	2,000,000	10,000,000
Additional margin posted for commodity contracts subject to rate recovery	17,000,000	32,000,000
Total	66,000,000	83,000,000
Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	105,000,000	82,000,000
Additional margin posted for commodity contracts not subject to rate recovery	0	0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	105,000,000	82,000,000
Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	(103,000,000)	(77,000,000)
Additional margin posted for commodity contracts not subject to rate recovery	0	0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	(103,000,000)	(77,000,000)
Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	(281,000,000)	(364,000,000)
Additional margin posted for commodity contracts not subject to rate recovery	0	0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	(281,000,000)	(364,000,000)
Designated as Hedging Instrument [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	5,000,000	7,000,000
Commodity contracts not subject to rate recovery		0
Designated as Hedging Instrument [Member] | Other assets: Sundry [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	2,000,000	2,000,000
Commodity contracts not subject to rate recovery		0
Designated as Hedging Instrument [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	(51,000,000)	(24,000,000)
Commodity contracts not subject to rate recovery		(14,000,000)
Designated as Hedging Instrument [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	(165,000,000)	(228,000,000)
Commodity contracts not subject to rate recovery		0
Not Designated as Hedging Instrument [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Foreign exchange instruments	0
Commodity contracts not subject to rate recovery	81,000,000	248,000,000
Associated offsetting commodity contracts not subject to rate recovery	(67,000,000)	(242,000,000)
Associated cash collateral commodity contracts not subject to rate recovery		0
Commodity contracts subject to rate recovery	28,000,000	37,000,000
Associated offsetting commodity contracts subject to rate recovery	0	(9,000,000)
Associated cash collateral commodity contracts subject to rate recovery	0	0
Not Designated as Hedging Instrument [Member] | Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Foreign exchange instruments	0
Commodity contracts not subject to rate recovery	8,000,000	36,000,000
Associated offsetting commodity contracts not subject to rate recovery	(5,000,000)	(27,000,000)
Associated cash collateral commodity contracts not subject to rate recovery		(1,000,000)
Commodity contracts subject to rate recovery	101,000,000	73,000,000
Associated offsetting commodity contracts subject to rate recovery	(1,000,000)	(1,000,000)
Associated cash collateral commodity contracts subject to rate recovery	0	0
Not Designated as Hedging Instrument [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Foreign exchange instruments	(1,000,000)
Commodity contracts not subject to rate recovery	(72,000,000)	(254,000,000)
Associated offsetting commodity contracts not subject to rate recovery	67,000,000	242,000,000
Associated cash collateral commodity contracts not subject to rate recovery		16,000,000
Commodity contracts subject to rate recovery	(65,000,000)	(57,000,000)
Associated offsetting commodity contracts subject to rate recovery	0	9,000,000
Associated cash collateral commodity contracts subject to rate recovery	19,000,000	5,000,000
Not Designated as Hedging Instrument [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Foreign exchange instruments	0
Commodity contracts not subject to rate recovery	(6,000,000)	(28,000,000)
Associated offsetting commodity contracts not subject to rate recovery	5,000,000	27,000,000
Associated cash collateral commodity contracts not subject to rate recovery		1,000,000
Commodity contracts subject to rate recovery	(120,000,000)	(150,000,000)
Associated offsetting commodity contracts subject to rate recovery	1,000,000	1,000,000
Associated cash collateral commodity contracts subject to rate recovery	4,000,000	13,000,000
San Diego Gas and Electric Company [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	26,000,000	27,000,000
Additional margin posted for commodity contracts not subject to rate recovery		1,000,000
Additional margin posted for commodity contracts subject to rate recovery	16,000,000	30,000,000
Total	42,000,000	58,000,000
San Diego Gas and Electric Company [Member] | Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	100,000,000	72,000,000
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	100,000,000	72,000,000
San Diego Gas and Electric Company [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	(54,000,000)	(55,000,000)
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	(54,000,000)	(55,000,000)
San Diego Gas and Electric Company [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	(118,000,000)	(148,000,000)
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	(118,000,000)	(148,000,000)
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	0	0
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Other assets: Sundry [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	0	0
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	(10,000,000)	(13,000,000)
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate and foreign exchange instruments	(3,000,000)	(12,000,000)
San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	26,000,000	33,000,000
Associated offsetting commodity contracts subject to rate recovery	0	(6,000,000)
Associated cash collateral commodity contracts subject to rate recovery	0	0
San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	101,000,000	73,000,000
Associated offsetting commodity contracts subject to rate recovery	(1,000,000)	(1,000,000)
Associated cash collateral commodity contracts subject to rate recovery	0	0
San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	(63,000,000)	(51,000,000)
Associated offsetting commodity contracts subject to rate recovery	0	6,000,000
Associated cash collateral commodity contracts subject to rate recovery	19,000,000	3,000,000
San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	(120,000,000)	(150,000,000)
Associated offsetting commodity contracts subject to rate recovery	1,000,000	1,000,000
Associated cash collateral commodity contracts subject to rate recovery	4,000,000	13,000,000
Southern California Gas Company [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	2,000,000	1,000,000
Additional margin posted for commodity contracts not subject to rate recovery		1,000,000
Additional margin posted for commodity contracts subject to rate recovery	1,000,000	2,000,000
Total	3,000,000	4,000,000
Southern California Gas Company [Member] | Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	0	0
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	0	0
Southern California Gas Company [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	(2,000,000)	(1,000,000)
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	(2,000,000)	(1,000,000)
Southern California Gas Company [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Net amount presented on balance sheet	0	0
Additional margin posted for commodity contracts not subject to rate recovery		0
Additional margin posted for commodity contracts subject to rate recovery	0	0
Total	0	0
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Current assets: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	2,000,000	4,000,000
Associated offsetting commodity contracts subject to rate recovery		(3,000,000)
Associated cash collateral commodity contracts subject to rate recovery		0
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Other assets: Sundry [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	0	0
Associated offsetting commodity contracts subject to rate recovery		0
Associated cash collateral commodity contracts subject to rate recovery		0
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Current liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	(2,000,000)	(6,000,000)
Associated offsetting commodity contracts subject to rate recovery		3,000,000
Associated cash collateral commodity contracts subject to rate recovery		2,000,000
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Deferred credits and other liabilities: Fixed-price contracts and other derivatives [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net [Abstract]
Commodity contracts subject to rate recovery	$ 0	0
Associated offsetting commodity contracts subject to rate recovery		0
Associated cash collateral commodity contracts subject to rate recovery		$ 0

DERIVATIVE FINANCIAL INSTRUM105

DERIVATIVE FINANCIAL INSTRUMENTS - INCOME STATEMENT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	$ (7,000,000)	$ (21,000,000)	[1]	$ 10,000,000	[1]
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings		1,000,000		1,000,000
Gain (loss) on fair value hedge ineffectiveness		0		0
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings		3,000,000		6,000,000
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Other Income [Member] | Interest rate instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings		(2,000,000)		(5,000,000)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	(8,000,000)	(21,000,000)		(106,000,000)
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	(23,000,000)	(33,000,000)		(29,000,000)
Loss on cash flow hedge ineffectiveness	5,000,000	4,000,000		2,000,000
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate and foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	19,000,000	(8,000,000)		(18,000,000)
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	4,000,000	(17,000,000)		(18,000,000)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Equity Earnings Before Income Tax [Member] | Interest rate instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	(25,000,000)	(9,000,000)		(80,000,000)
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	(8,000,000)	(10,000,000)		(12,000,000)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Remeasurement of Equity Method Investment [Member] | Interest rate and foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	0	0		0
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	0	(7,000,000)		0
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Equity Earnings Net Of Income Tax [Member] | Interest rate and foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	(9,000,000)	5,000,000		(20,000,000)
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	(12,000,000)	(5,000,000)		(13,000,000)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	3,000,000	(13,000,000)		12,000,000
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	(9,000,000)	6,000,000		14,000,000
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Revenues: Energy-Related Businesses [Member] | Foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	4,000,000	4,000,000		0
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	2,000,000	0		0
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	118,000,000	(103,000,000)		(92,000,000)
Not Designated as Hedging Instrument [Member] | Other Income [Member] | Interest rate and foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	49,000,000	(32,000,000)		(4,000,000)
Not Designated as Hedging Instrument [Member] | Equity Earnings Net Of Income Tax [Member] | Foreign exchange instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1,000,000	3,000,000		(4,000,000)
Not Designated as Hedging Instrument [Member] | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	16,000,000	(18,000,000)		42,000,000
Not Designated as Hedging Instrument [Member] | Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	0	1,000,000		(1,000,000)
Not Designated as Hedging Instrument [Member] | 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	54,000,000	(53,000,000)		(126,000,000)
Not Designated as Hedging Instrument [Member] | 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	(2,000,000)	(4,000,000)		1,000,000
San Diego Gas and Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	2,000,000	3,000,000	[1]	4,000,000	[1]
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss on cash flow hedge ineffectiveness	0	0		0
San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	(2,000,000)	(2,000,000)		(6,000,000)
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	(13,000,000)	(12,000,000)		(12,000,000)
San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | 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	54,000,000	(53,000,000)		(126,000,000)
Southern California Gas Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pretax gain (loss) on derivative recognized in OCI (effective portion)	0	0		0
Pretax gain (loss) reclassified from AOCI into earnings (effective portion)	0	(1,000,000)		(1,000,000)
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	(2,000,000)	(3,000,000)		0
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	0	1,000,000		(1,000,000)
Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | 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	$ (2,000,000)	$ (4,000,000)		$ 1,000,000
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

DERIVATIVE FINANCIAL INSTRUM106

DERIVATIVE FINANCIAL INSTRUMENTS - CASH FLOW HEDGES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Cash flow hedge gain (loss) to be reclassified within 12 months	$ 33
Maximum length of time hedged in cash flow hedge	14 years
Equity Method Investee [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Maximum length of time hedged in cash flow hedge	18 years
San Diego Gas and Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Maximum length of time hedged in cash flow hedge	1 year
San Diego Gas and Electric Company [Member] | Non-controlling interests [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash flow hedge gain (loss) to be reclassified within 12 months	$ 9
Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash flow hedge gain (loss) to be reclassified within 12 months	$ 1

DERIVATIVE FINANCIAL INSTRUM107

DERIVATIVE FINANCIAL INSTRUMENTS - CONTINGENT FEATURES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate fair value of net liability position	$ 6	$ 10
Aggregate fair value of additional collateral	6
San Diego Gas and Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate fair value of net liability position	1	$ 0
Aggregate fair value of additional collateral	$ 1

FAIR VALUE MEASUREMENTS - RECUR

FAIR VALUE MEASUREMENTS - RECURRING FAIR VALUE MEASURES (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	$ 496	$ 508
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	54	52
Nuclear decomissioning trusts - Municipal debt securities	250	206
Nuclear decommissioning trusts - Other debt securities	217	141
Nuclear decommissioning trusts - Total debt securities	521	399
Total nuclear decommissioning trusts	1,017	907
Assets fair value disclosure, total	1,188	1,072
Liabilities fair value disclosure, total	384	441
Interest Rate and Foreign Exchange Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	7	9
Derivative Liability	217	252
Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	17	15
Effect of netting and allocation of collateral	2	9
Derivative Liability	6	27
Effect of netting and allocation of collateral		(17)
Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	128	100
Effect of netting and allocation of collateral	17	32
Derivative Liability	184	197
Effect of netting and allocation of collateral	(23)	(18)
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	491	508
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	45	36
Nuclear decomissioning trusts - Municipal debt securities	0	0
Nuclear decommissioning trusts - Other debt securities	0	0
Nuclear decommissioning trusts - Total debt securities	45	36
Total nuclear decommissioning trusts	536	544
Assets fair value disclosure, total	555	574
Liabilities fair value disclosure, total	0	0
Level 1 [Member] | Interest Rate and Foreign Exchange Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Level 1 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	5	0
Effect of netting and allocation of collateral	2	2
Derivative Liability	0	16
Effect of netting and allocation of collateral		(17)
Level 1 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1
Effect of netting and allocation of collateral	12	27
Derivative Liability	23	19
Effect of netting and allocation of collateral	(23)	(18)
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	5	0
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	9	16
Nuclear decomissioning trusts - Municipal debt securities	250	206
Nuclear decommissioning trusts - Other debt securities	217	141
Nuclear decommissioning trusts - Total debt securities	476	363
Total nuclear decommissioning trusts	481	363
Assets fair value disclosure, total	502	397
Liabilities fair value disclosure, total	230	271
Level 2 [Member] | Interest Rate and Foreign Exchange Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	7	9
Derivative Liability	217	252
Level 2 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	12	15
Effect of netting and allocation of collateral	0	7
Derivative Liability	6	11
Effect of netting and allocation of collateral		0
Level 2 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	3
Effect of netting and allocation of collateral	0	0
Derivative Liability	7	8
Effect of netting and allocation of collateral	0	0
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	0	0
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0	0
Nuclear decomissioning trusts - Municipal debt securities	0	0
Nuclear decommissioning trusts - Other debt securities	0	0
Nuclear decommissioning trusts - Total debt securities	0	0
Total nuclear decommissioning trusts	0	0
Assets fair value disclosure, total	131	101
Liabilities fair value disclosure, total	154	170
Level 3 [Member] | Interest Rate and Foreign Exchange Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Level 3 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Effect of netting and allocation of collateral	0	0
Derivative Liability	0	0
Effect of netting and allocation of collateral		0
Level 3 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	126	96
Effect of netting and allocation of collateral	5	5
Derivative Liability	154	170
Effect of netting and allocation of collateral	0	0
San Diego Gas and Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	496	508
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	54	52
Nuclear decomissioning trusts - Municipal debt securities	250	206
Nuclear decommissioning trusts - Other debt securities	217	141
Nuclear decommissioning trusts - Total debt securities	521	399
Total nuclear decommissioning trusts	1,017	907
Assets fair value disclosure, total	1,159	1,037
Liabilities fair value disclosure, total	172	203
San Diego Gas and Electric Company [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		1
San Diego Gas and Electric Company [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	126	99
Effect of netting and allocation of collateral	16	30
Derivative Liability	182	194
Effect of netting and allocation of collateral	(23)	(16)
San Diego Gas and Electric Company [Member] | Interest rate instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	13	25
San Diego Gas and Electric Company [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	491	508
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	45	36
Nuclear decomissioning trusts - Municipal debt securities	0	0
Nuclear decommissioning trusts - Other debt securities	0	0
Nuclear decommissioning trusts - Total debt securities	45	36
Total nuclear decommissioning trusts	536	544
Assets fair value disclosure, total	547	571
Liabilities fair value disclosure, total	0	1
San Diego Gas and Electric Company [Member] | Level 1 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		1
San Diego Gas and Electric Company [Member] | Level 1 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1
Effect of netting and allocation of collateral	11	25
Derivative Liability	23	17
Effect of netting and allocation of collateral	(23)	(16)
San Diego Gas and Electric Company [Member] | Level 1 [Member] | Interest rate instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0	0
San Diego Gas and Electric Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	5	0
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	9	16
Nuclear decomissioning trusts - Municipal debt securities	250	206
Nuclear decommissioning trusts - Other debt securities	217	141
Nuclear decommissioning trusts - Total debt securities	476	363
Total nuclear decommissioning trusts	481	363
Assets fair value disclosure, total	481	365
Liabilities fair value disclosure, total	18	32
San Diego Gas and Electric Company [Member] | Level 2 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		0
San Diego Gas and Electric Company [Member] | Level 2 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	2
Effect of netting and allocation of collateral	0	0
Derivative Liability	5	7
Effect of netting and allocation of collateral	0	0
San Diego Gas and Electric Company [Member] | Level 2 [Member] | Interest rate instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	13	25
San Diego Gas and Electric Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	0	0
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0	0
Nuclear decomissioning trusts - Municipal debt securities	0	0
Nuclear decommissioning trusts - Other debt securities	0	0
Nuclear decommissioning trusts - Total debt securities	0	0
Total nuclear decommissioning trusts	0	0
Assets fair value disclosure, total	131	101
Liabilities fair value disclosure, total	154	170
San Diego Gas and Electric Company [Member] | Level 3 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		0
San Diego Gas and Electric Company [Member] | Level 3 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	126	96
Effect of netting and allocation of collateral	5	5
Derivative Liability	154	170
Effect of netting and allocation of collateral	0	0
San Diego Gas and Electric Company [Member] | Level 3 [Member] | Interest rate instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0	0
Southern California Gas Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets fair value disclosure, total	3	4
Liabilities fair value disclosure, total	2	1
Southern California Gas Company [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		1
Southern California Gas Company [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	1
Effect of netting and allocation of collateral	1	2
Derivative Liability	2	3
Effect of netting and allocation of collateral		(2)
Southern California Gas Company [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets fair value disclosure, total	1	3
Liabilities fair value disclosure, total	0	0
Southern California Gas Company [Member] | Level 1 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		1
Southern California Gas Company [Member] | Level 1 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Effect of netting and allocation of collateral	1	2
Derivative Liability	0	2
Effect of netting and allocation of collateral		(2)
Southern California Gas Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets fair value disclosure, total	2	1
Liabilities fair value disclosure, total	2	1
Southern California Gas Company [Member] | Level 2 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		0
Southern California Gas Company [Member] | Level 2 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	1
Effect of netting and allocation of collateral	0	0
Derivative Liability	2	1
Effect of netting and allocation of collateral		0
Southern California Gas Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets fair value disclosure, total	0	0
Liabilities fair value disclosure, total	0	0
Southern California Gas Company [Member] | Level 3 [Member] | Commodity contracts not subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Effect of netting and allocation of collateral		0
Southern California Gas Company [Member] | Level 3 [Member] | Commodity contracts subject to rate recovery [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Effect of netting and allocation of collateral	0	0
Derivative Liability	$ 0	0
Effect of netting and allocation of collateral		$ 0

FAIR VALUE MEASUREMENTS - RECON

FAIR VALUE MEASUREMENTS - RECON OF LEVEL 3 ASSETS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements [Abstract]
Balance at beginning of period	$ (74,000,000)	$ 19,000,000	$ 107,000,000
Realized and unrealized gains (losses)	34,000,000	(120,000,000)	(134,000,000)
Allocated transmission instruments	6,000,000	8,000,000	12,000,000
Settlements	6,000,000	19,000,000	34,000,000
Balance at end of period	(28,000,000)	(74,000,000)	19,000,000
Change in unrealized gains (losses) relating to instruments still held at the end of the period	30,000,000	(101,000,000)	$ (27,000,000)
San Diego Gas and Electric Company [Member] | Maximum [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements [Abstract]
Congestion revenue rights	6.93	10.23
Market electricity forward price inputs	51.01	56.67
San Diego Gas and Electric Company [Member] | Minimum [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements [Abstract]
Congestion revenue rights	(11.88)	(23.81)
Market electricity forward price inputs	$ 22.55	$ 17.40
Subsequent Event [Member] | San Diego Gas and Electric Company [Member] | Maximum [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements [Abstract]
Congestion revenue rights				$ 11.99
Subsequent Event [Member] | San Diego Gas and Electric Company [Member] | Minimum [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements [Abstract]
Congestion revenue rights				$ (7.25)

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Accumulated interest outstanding	$ 29	$ 17
Foreign currency Translation	35
Unamortized discount (net of premium) and debt issuance costs	143	109
Capital lease obligations and build-to-suit	877	383
Level 3 [Member] | Otay Mesa VIE [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross long-term debt	295	305
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term amounts due from unconsolidated affiliates	604	184
Long-term amounts due to unconsolidated affiliates	35
Total long-term debt	17,138	15,068
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term amounts due from unconsolidated affiliates	624	175
Long-term amounts due to unconsolidated affiliates	32
Total long-term debt	18,409	15,947
Fair Value [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term amounts due from unconsolidated affiliates	0	0
Long-term amounts due to unconsolidated affiliates	0
Total long-term debt	817	0
Fair Value [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term amounts due from unconsolidated affiliates	528	91
Long-term amounts due to unconsolidated affiliates	32
Total long-term debt	17,134	15,455
Fair Value [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term amounts due from unconsolidated affiliates	96	84
Long-term amounts due to unconsolidated affiliates	0
Total long-term debt	458	492
San Diego Gas and Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unamortized discount (net of premium) and debt issuance costs		45
Gross long-term debt	4,573	4,349
Capital lease obligations	732	240
San Diego Gas and Electric Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	4,868	4,654
San Diego Gas and Electric Company [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	5,368	5,032
San Diego Gas and Electric Company [Member] | Fair Value [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	0	0
San Diego Gas and Electric Company [Member] | Fair Value [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	5,073	4,727
San Diego Gas and Electric Company [Member] | Fair Value [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	295	305
Southern California Gas Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unamortized discount (net of premium) and debt issuance costs	24	27
Gross long-term debt	3,000	3,000
Capital lease obligations	1	0
Southern California Gas Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,009	3,009
Southern California Gas Company [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,192	3,131
Southern California Gas Company [Member] | Fair Value [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	0	0
Southern California Gas Company [Member] | Fair Value [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,192	3,131
Southern California Gas Company [Member] | Fair Value [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	$ 0	$ 0

FAIR VALUE MEASUREMENTS - NONRE

FAIR VALUE MEASUREMENTS - NONRECURRING FAIR VALUE MEASURES (Details) - USD ($) $ in Millions	Sep. 26, 2016	May 31, 2016	Mar. 31, 2016	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[1]	Sep. 29, 2016	May 09, 2016	Mar. 29, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Remeasurement of equity method investment							$ 0	$ 617	[1]	$ 0
Equity method investment							2,517	$ 2,080
Market Approach Valuation Technique [Member] | IEnova Pipelines [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of investment	$ 1,144
% of fair value measurement	100.00%
Range of inputs	100.00%
Market Approach Valuation Technique [Member] | TdM [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of investment				$ 62			$ 78					$ 145
% of fair value measurement				100.00%								100.00%
Range of inputs				100.00%								100.00%
Market Approach Valuation Technique [Member] | Rockies Express [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of investment														$ 440
% of fair value measurement														100.00%
Range of inputs														100.00%
Sempra Mexico [Member] | IEnova Pipelines [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Acquired percentage interest	50.00%
Ownership percentage in equity method investee	100.00%
Remeasurement of equity method investment	$ 617
Gain on acquisition of remaining voting rights, net of tax	432
Fair value of investment	1,144
Equity method investment	520
Reclassification adjustment from AOCI	(7)
Fair value of business combination	$ 2,288
Sempra Mexico [Member] | TdM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other than temporary impairment in investment				$ 71	$ 131
Other than temporary impairment in investment, net of tax					$ 111
Sempra LNG & Midstream [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other than temporary impairment in investment			$ 44
Other than temporary impairment in investment, net of tax			$ 27
Sempra LNG & Midstream [Member] | Rockies Express [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Ownership percentage in equity method investee		25.00%	25.00%										25.00%	25.00%
Fair value of investment			$ 440
Equity method investment			484
Other than temporary impairment in investment			44			$ 44
Other than temporary impairment in investment, net of tax			27			$ 27
Proceeds from sale of investments		$ 443	$ 440
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

PREFERRED STOCK (Details)

PREFERRED STOCK (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 09, 2018	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Preferred Stock [Line Items]
Preferred stock shares authorized			50,000,000	50,000,000
Sempra Energy [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			50,000,000
Number of preferred stock shares outstanding			0
San Diego Gas and Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			45,000,000	45,000,000
Number of preferred stock shares outstanding			0
Southern California Gas Company [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			11,000,000	11,000,000
Number of preferred stock shares outstanding			1,000,000	1,000,000
So Cal Gas Series Preferred Stock [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			5,000,000
So Cal Gas Series Preferred Stock [Member] | Southern California Gas Company [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			5,000,000
Preferred stock outstanding			$ 22	$ 22
Twenty Five Dollar Par, Six Percent Series [Member] | Southern California Gas Company [Member]
Preferred Stock [Line Items]
Preferred stock shares authorized			1,000,000
Par value (in dollars per share)			$ 25
Number of preferred stock shares outstanding			79,011
Preferred stock outstanding			$ 3	3
Twenty Five Dollar Par, Six Percent Series A [Member] | Southern California Gas Company [Member]
Preferred Stock [Line Items]
Par value (in dollars per share)			$ 25
Number of preferred stock shares outstanding			783,032
Preferred stock outstanding			$ 19	19
Liquidation preference (in dollars per share)			$ 25
So Cal Gas Preferred Stock Owned By Pacific Enterprises [Member]
Preferred Stock [Line Items]
Preferred stock outstanding held by parent			$ (2)	(2)
So Cal Gas Preferred Stock Owned By Pacific Enterprises [Member] | Southern California Gas Company [Member]
Preferred Stock [Line Items]
Number of preferred stock shares outstanding			50,970
Preferred Stock Of Subsidiaries [Member]
Preferred Stock [Line Items]
Preferred stock outstanding			$ 20	$ 20
Subsequent Event [Member] | Convertible Preferred Stock [Member] | Sempra Energy [Member]
Preferred Stock [Line Items]
Shares issued	17,250,000	17,250,000
Value of shares issued		$ 1,690
Liquidation preference (in dollars per share)	$ 100

SEMPRA ENERGY - SHAREHOLDERS113

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE - EARNINGS PER SHARE COMPUTATIONS AND DIVIDENDS DECLARED (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings/Income attributable to common shares	$ (501)	$ 57	$ 259	$ 441	$ 379	$ 622	$ 16	$ 353	$ 256	$ 1,370	$ 1,349
Weighted-average number of shares outstanding, basic	251,900,000	251,700,000	251,400,000	251,100,000	250,600,000	250,400,000	250,100,000	249,700,000	251,545,000	250,217,000	248,249,000
Fully vested RSUs included in the computation of EPS									609	568	491
Dilutive effect of stock options, restricted stock awards and restricted stock units (in shares)									755,000	938,000	2,674,000
Weighted-average number of shares outstanding, diluted	251,900,000	253,400,000	252,800,000	252,200,000	251,600,000	252,400,000	252,000,000	251,500,000	252,300,000	251,155,000	250,923,000
Basic earnings per common share (in dollars per share)	$ (1.99)	$ 0.23	$ 1.03	$ 1.76	$ 1.51	$ 2.48	$ 0.06	$ 1.41	$ 1.02	$ 5.48	$ 5.43
Diluted earnings per common share (in dollars per share)	$ (1.99)	$ 0.22	$ 1.03	$ 1.75	$ 1.51	$ 2.46	$ 0.06	$ 1.40	1.01	5.46	5.37
Dividends declared per share of common stock (in dollars per share)									$ 3.29	$ 3.02	$ 2.8

SEMPRA ENERGY - SHAREHOLDERS114

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE - ANTIDILUTIVE SECURITIES EXCLUDED FROM COMPUTATION OF EPS (Details) - shares	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of EPS	800,000
Restricted Stock Units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of EPS		237,741	0	722

SEMPRA ENERGY - SHAREHOLDERS115

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE - COMMON STOCK ACTIVITY (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 09, 2018	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings Per Share [Abstract]
Common stock, shares authorized		750,000,000	750,000,000
Common stock par value (in dollars per share)		$ 0	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common shares outstanding, January 1		250,152,514	248,298,080		246,330,884
RSUs vesting		362,022	1,363,555		1,499,062
Stock options exercised		164,454	167,742		227,815
Savings plan issuance		567,428	653,607		652,631
Common stock investment plan		254,047	266,056		249,665
Issuance of RSUs held in our Deferred Compensation Plan		7,811	0		0
Shares repurchased		149,299	596,526		661,977
Common shares outstanding, December 31		251,358,977	250,152,514		248,298,080
Schedule of Capitalization, Equity [Line Items]
Issuances of common stock		$ 47	$ 51	[1]	$ 52	[1]
Subsequent Event [Member] | Public Offering [Member]
Schedule of Capitalization, Equity [Line Items]
Shares issued	23,364,486
Subsequent Event [Member] | Over-Allotment Option [Member]
Schedule of Capitalization, Equity [Line Items]
Shares issued	3,504,672
Issuances of common stock	$ 368
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SAN ONOFRE NUCLEAR GENERATIN116

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - NARRATIVE (Details) - USD ($) $ in Millions	Mar. 13, 2017	Apr. 30, 2016	Oct. 31, 2015	Dec. 31, 2017	Feb. 28, 2017	Dec. 31, 2016	[1]
Jointly Owned Utility Plant Interests [Line Items]
Nuclear plant closure regulatory asset, current				$ 325		$ 348
Nuclear plant closure regulatory asset, noncurrent				1,517		3,414
Nuclear decommissioning trusts				$ 1,033		1,026
Litigation settlement payable	$ 118
Percent of arbitration expenses awarded	95.00%
Settlement payable net of arbitration expense	$ 60
Period of environmental exit				10 years
SONGS mitigation costs remaining		$ 4,400
San Onofre Nuclear Generating Station (SONGS) [Member]
Jointly Owned Utility Plant Interests [Line Items]
Insurance recovery			$ 400
San Diego Gas and Electric Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Nuclear plant closure regulatory asset, current				$ 316		340
Nuclear plant closure regulatory asset, noncurrent				451		2,012
Nuclear decommissioning trusts				1,033		$ 1,026
Decommissioning liability				607
Cost study estimate decommissioning escalated				$ 1,000
Litigation settlement payable	24
Arbitration expense	12
Settlement payable net of arbitration expense	12
Legal fees	11
Litigation settlement amount allocated to ratepayers and shareholders	$ 1
Percentage of environmental exit costs incurred				20.00%
SONGS mitigation costs remaining		$ 899		$ 24
Nuclear decommissioning trust authorized recovery amount				362	$ 60
San Diego Gas and Electric Company [Member] | Nuclear Plant Closure [Member]
Jointly Owned Utility Plant Interests [Line Items]
Regulatory asset threshold to cease rate recovery				775
Receivable for nuclear plant closure				152
Nuclear plant closure regulatory asset, current				32
Nuclear plant closure regulatory asset, noncurrent				$ 120
San Diego Gas and Electric Company [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage				20.00%
Portion of weighted average return on preferred stock included in nuclear plant return on ratebase				50.00%
Insurance recovery			$ 80
Recovery allocation percentage			5.00%
Ratepayers [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]
Jointly Owned Utility Plant Interests [Line Items]
Amount funded to customers through Energy Resource Recovery Account			$ 75
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SAN ONOFRE NUCLEAR GENERATIN117

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - NUCLEAR DECOMMISSIONING TRUSTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 701	$ 658
Gross unrealized gains	336	372
Gross unrealized losses	(4)	(4)
Estimated fair value	1,033	1,026
Proceeds from sales	1,314	1,134	$ 577
Gross realized gains	157	111	29
Gross realized losses	(14)	(29)	$ (15)
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	514	396
Gross unrealized gains	10	6
Gross unrealized losses	(3)	(3)
Estimated fair value	521	399
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	54	52
Gross unrealized gains	0	0
Gross unrealized losses	0	0
Estimated fair value	54	52
Municipal bonds [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	245	203
Gross unrealized gains	7	4
Gross unrealized losses	(2)	(1)
Estimated fair value	250	206
Other securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	215	141
Gross unrealized gains	3	2
Gross unrealized losses	(1)	(2)
Estimated fair value	217	141
Equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	171	143
Gross unrealized gains	326	366
Gross unrealized losses	(1)	(1)
Estimated fair value	496	508
Cash and cash equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	16	119
Gross unrealized gains	0	0
Gross unrealized losses	0	0
Estimated fair value	$ 16	$ 119

SAN ONOFRE NUCLEAR GENERATIN118

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL (Details) - USD ($) $ in Millions	Apr. 18, 2016	Oct. 31, 2017	May 31, 2017	Feb. 28, 2017	Sep. 30, 2016	May 31, 2016	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
Jointly Owned Utility Plant Interests [Line Items]
Decrease in nuclear decommissioning balancing account							$ (108)	$ (198)		$ (586)
San Diego Gas and Electric Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Decommissioning liability							607
Cost study estimate decommissioning escalated							1,000
Decrease in nuclear decommissioning balancing account							$ (56)	$ (35)		$ (474)
San Diego Gas and Electric Company [Member] | Total Ownership [Member]
Jointly Owned Utility Plant Interests [Line Items]
Damages awarded to other party	$ 162			$ 43
Damages sought		$ 58			$ 56
San Diego Gas and Electric Company [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]
Jointly Owned Utility Plant Interests [Line Items]
Damages awarded to other party			$ 9			$ 32
Damages sought		$ 12
Decrease in regulatory asset						(23)
Decrease in nuclear decommissioning balancing account						(8)
Decrease in SONGS O&M cost balancing account						$ (1)
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SAN ONOFRE NUCLEAR GENERATIN119

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - NUCLEAR INSURANCE (Details) - San Diego Gas and Electric Company [Member] - USD ($) $ in Millions	Jan. 10, 2018	Jan. 09, 2018	Jan. 05, 2018	Jan. 04, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Maximum required nuclear liability insurance available					$ 450
Maximum secondary financial protection available					13,000
Maximum required company contribution if nuclear liability loss occurs					50.9
Annual maximum required company contribution if nuclear liability loss occurs					7.6
Federal nuclear property damage insurance, minimum required					1,060
Federal nuclear property damage insurance premium assessment					10.4
Maximum nuclear property insurance terrorism coverage					$ 3,240
Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Maximum required nuclear liability insurance available			$ 100	$ 450
Federal nuclear property damage insurance, minimum required	$ 50	$ 1,060

REGULATORY MATTERS - REGULATORY

REGULATORY MATTERS - REGULATORY ACCOUNTS (Details) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 27, 2018	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Write-off of wildfire regulatory asset		$ 351	$ 0	[1]	$ 0	[1]
U.S. federal statutory income tax rate		35.00%	35.00%		35.00%
Amortization expense on regulatory assets		$ 50	$ 65		$ 62
Sempra Mexico [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		83	71
Net Regulatory Assets (Liabilities) Sempra Energy Consolidated [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(2,189)	764
San Diego Gas and Electric Company [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Regulatory balancing accounts - net undercollected, Noncurrent		63
Write-off of wildfire regulatory asset		$ 351	$ 0	[1]	$ 0	[1]
U.S. federal statutory income tax rate		35.00%	35.00%		35.00%
Amortization expense on regulatory assets		$ 49	$ 63		$ 60
San Diego Gas and Electric Company [Member] | Fixed-price contracts and other derivatives [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		96	141
San Diego Gas and Electric Company [Member] | Costs related to SONGS plant closure [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		0	183
San Diego Gas and Electric Company [Member] | Costs related to wildfire litigation [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		0	353
San Diego Gas and Electric Company [Member] | Deferred income taxes (refundable) recoverable in rates [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(281)	1,014
San Diego Gas and Electric Company [Member] | Pension and other postretirement benefit plan obligations [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		153	210
San Diego Gas and Electric Company [Member] | Removal obligations [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(1,846)	(1,725)
San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 9	12
San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member] | Maximum [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Remaining amortization period		10 years
San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member] | Minimum [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Remaining amortization period		1 year
San Diego Gas and Electric Company [Member] | Environmental costs [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 29	48
San Diego Gas and Electric Company [Member] | Legacy meters [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		0	16
San Diego Gas and Electric Company [Member] | Sunrise Powerlink fire mitigation [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 119	118
Remaining amortization period		52-year
San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Commodity – electric [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 82	35
San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Gas transportation [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		22	61
San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Safety and reliability [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		48	20
San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Public purpose programs [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(70)	(106)
San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Other balancing accounts [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		233	249
San Diego Gas and Electric Company [Member] | Other regulatory (liabilities) assets [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(70)	(2)
San Diego Gas and Electric Company [Member] | Net Regulatory Assets (Liabilities) SDGE [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(1,476)	627
Southern California Gas Company [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Regulatory balancing accounts - net undercollected, Noncurrent		$ 118	$ 85
U.S. federal statutory income tax rate		35.00%	35.00%		35.00%
Amortization expense on regulatory assets		$ 1	$ 2		$ 2
Southern California Gas Company [Member] | Deferred income taxes (refundable) recoverable in rates [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(437)	417
Southern California Gas Company [Member] | Pension and other postretirement benefit plan obligations [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		513	563
Southern California Gas Company [Member] | Employee benefit costs [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		45	45
Southern California Gas Company [Member] | Removal obligations [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(924)	(972)
Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 8	10
Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member] | Maximum [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Remaining amortization period		8 years
Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member] | Minimum [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Remaining amortization period		3 years
Southern California Gas Company [Member] | Environmental costs [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		$ 22	22
Southern California Gas Company [Member] | Workers’ compensation [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		12	10
Southern California Gas Company [Member] | Regulatory Balancing Accounts, Commodity - gas including transportation
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		151	207
Southern California Gas Company [Member] | Regulatory Balancing Accounts, Safety and reliability [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		266	230
Southern California Gas Company [Member] | Regulatory Balancing Accounts, Public purpose programs [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(274)	(270)
Southern California Gas Company [Member] | Regulatory Balancing Accounts, Other balancing accounts [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(114)	(204)
Southern California Gas Company [Member] | Other regulatory (liabilities) assets [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(64)	8
Southern California Gas Company [Member] | Net Regulatory Assets (Liabilities) SoCalGas [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Net regulatory assets (liabilities)		(796)	$ 66
Loss from Catastrophes [Member] | San Diego Gas and Electric Company [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
Write-off of wildfire regulatory asset		$ 351
Subsequent Event [Member]
Schedule Of Net Regulatory Assets (Liabilities) [Line Items]
U.S. federal statutory income tax rate	21.00%
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

REGULATORY MATTERS - GENERAL RA

REGULATORY MATTERS - GENERAL RATE CASE (Details) - USD ($) $ in Millions	Oct. 06, 2017	Oct. 31, 2016	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2017	Sep. 30, 2016
Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement	$ 2,989
GRC requested revenue requirement adjustment	533
Refund of tax memorandum account, pre-tax				$ 72
Refund of tax memorandum account, net of tax				(43)
Change in tax estimates, pre-tax				(11)
Change in tax estimates, net of tax				(6)	$ 6
Adjustment to revenue related to tax repairs deductions, pre-tax				(83)
Adjustment to revenue related to tax repairs deductions, net of tax				(49)
Southern California Gas Company [Member] | Year 2016 [Member]
General Rate Case [Line Items]
GRC revenue requirement			$ 2,204
Rate base adjustment						$ 38
Revenue requirement adjustment						$ 5
Change in income tax liability from prior year							$ (19)
Southern California Gas Company [Member] | Years 2017 and 2018 [Member]
General Rate Case [Line Items]
Change in GRC revenue requirement						3.50%
Z Factor Mechanism, Deductible Per Event						$ 5
Southern California Gas Company [Member] | Years 2012 through 2014 [Member]
General Rate Case [Line Items]
Regulatory liability			11		11
Southern California Gas Company [Member] | Year 2015 [Member]
General Rate Case [Line Items]
Amended requested change in rate		$ 32
Southern California Gas Company [Member] | General Rate Case [Member]
General Rate Case [Line Items]
Tracked income tax expense liability						65
San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement	2,199
GRC requested revenue requirement adjustment	$ 217
Refund of tax memorandum account, pre-tax				37
Refund of tax memorandum account, net of tax				(22)
Change in tax estimates, pre-tax				(15)
Change in tax estimates, net of tax				(9)	9
Adjustment to revenue related to tax repairs deductions, pre-tax				(52)
Adjustment to revenue related to tax repairs deductions, net of tax				$ (31)
San Diego Gas and Electric Company [Member] | Year 2016 [Member]
General Rate Case [Line Items]
GRC revenue requirement			1,791
Rate base adjustment						55
Revenue requirement adjustment						7
Change in income tax liability from prior year							$ (5)
San Diego Gas and Electric Company [Member] | Years 2012 through 2014 [Member]
General Rate Case [Line Items]
Regulatory liability			$ 15		$ 15
San Diego Gas and Electric Company [Member] | Year 2015 [Member]
General Rate Case [Line Items]
Amended requested change in rate		$ 53
San Diego Gas and Electric Company [Member] | General Rate Case [Member]
General Rate Case [Line Items]
Tracked income tax expense liability						$ 69
Minimum [Member] | Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	6.00%
Minimum [Member] | San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	5.00%
Maximum [Member] | Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	8.00%
Maximum [Member] | San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	7.00%

REGULATORY MATTERS - COST OF CA

REGULATORY MATTERS - COST OF CAPITAL & FERC RATES (Details)	9 Months Ended	12 Months Ended	24 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2019
Southern California Gas Company [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Weighted return on rate base	8.02%	8.02%
Cost of debt	5.77%
Southern California Gas Company [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			100.00%
Change in return on rate base			(0.68%)
Weighted return on rate base			7.34%
Change in cost of debt			(1.44%)
Cost of debt			4.33%
Southern California Gas Company [Member] | Capital Structure, Long Term Debt [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			45.60%
Return on rate base			4.33%
Weighted return on rate base			1.97%
Southern California Gas Company [Member] | Capital Structure, Preferred Stock [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			2.40%
Return on rate base			6.00%
Weighted return on rate base			0.14%
Southern California Gas Company [Member] | Capital Structure, Common Equity [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			52.00%
Return on rate base			10.05%
Weighted return on rate base			5.23%
San Diego Gas and Electric Company [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Weighted return on rate base	7.79%	7.79%
Cost of debt	5.00%
San Diego Gas and Electric Company [Member] | Federal Energy Regulatory Commission [Member]
Public Utilities, General Disclosures [Line Items]
Weighting		100.00%
Weighted return on rate base		7.51%
San Diego Gas and Electric Company [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			100.00%
Change in return on rate base			(0.24%)
Weighted return on rate base			7.55%
Change in cost of debt			(0.41%)
Cost of debt			4.59%
San Diego Gas and Electric Company [Member] | Capital Structure, Long Term Debt [Member] | Federal Energy Regulatory Commission [Member]
Public Utilities, General Disclosures [Line Items]
Weighting		43.44%
Return on rate base		4.21%
Weighted return on rate base		1.83%
San Diego Gas and Electric Company [Member] | Capital Structure, Long Term Debt [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			45.25%
Return on rate base			4.59%
Weighted return on rate base			2.08%
San Diego Gas and Electric Company [Member] | Capital Structure, Preferred Stock [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			2.75%
Return on rate base			6.22%
Weighted return on rate base			0.17%
San Diego Gas and Electric Company [Member] | Capital Structure, Common Equity [Member] | Federal Energy Regulatory Commission [Member]
Public Utilities, General Disclosures [Line Items]
Weighting		56.56%
Return on rate base		10.05%
Weighted return on rate base		5.68%
San Diego Gas and Electric Company [Member] | Capital Structure, Common Equity [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Authorized weighting			52.00%
Return on rate base			10.20%
Weighted return on rate base			5.30%
Cost of Capital [Member] | Southern California Gas Company [Member] | Capital Structure, Common Equity [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Return on rate base	10.10%
Cost of Capital [Member] | Southern California Gas Company [Member] | Capital Structure, Common Equity [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Return on rate base			10.05%
Cost of Capital [Member] | San Diego Gas and Electric Company [Member] | Capital Structure, Common Equity [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Return on rate base	10.30%
Cost of Capital [Member] | San Diego Gas and Electric Company [Member] | Capital Structure, Common Equity [Member] | Scenario, Forecast [Member] | California Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Return on rate base			10.20%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - LOSS ON CONTINGENCIES (Details) £ in Millions

Feb. 22, 2018plaintifflawsuit

Jul. 19, 2017Bcf

Mar. 13, 2017

Mar. 31, 2016t

Feb. 28, 2017USD ($)

Jan. 31, 2017lawsuit

Sep. 30, 2016USD ($)

Dec. 31, 2017USD ($)Bcfappeal

Dec. 31, 2016USD ($)

Dec. 31, 2016GBP (£)

Dec. 31, 2015USD ($)

[1]

Dec. 31, 2015GBP (£)

Oct. 21, 2016t

Oct. 01, 2014GBP (£)

Loss Contingencies [Line Items]

Loss contingency accrual

$ 92,000,000

Write-off of wildfire regulatory asset

351,000,000

$ 0

[1]

$ 0

Litigation Settlement, Percent of Arbitration Expenses

95.00%

Reserve for Aliso Canyon costs

84,000,000

53,000,000

[2]

San Diego Gas and Electric Company [Member]

Loss Contingencies [Line Items]

Loss contingency accrual

3,000,000

Write-off of wildfire regulatory asset

351,000,000

0

[1]

$ 0

Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Loss contingency accrual

88,000,000

Recoverable costs through insurance settlement

887,000,000

Reserve for Aliso Canyon costs

$ 84,000,000

$ 53,000,000

[2]

Loss from Catastrophes, 2007 Wildfire [Member] | San Diego Gas and Electric Company [Member]

Loss Contingencies [Line Items]

Number of Appeals Pending | appeal

1

Write-off of wildfire regulatory asset

$ 351,000,000

Write-off of wildfire regulatory asset net of tax

208,000,000

Lawsuit Against MHI [Member] | San Diego Gas and Electric Company [Member]

Loss Contingencies [Line Items]

Litigation Settlement, Percent of Arbitration Expenses

95.00%

Aliso Canyon Natural Gas Storage Facility Gas Leak [Member]

Loss Contingencies [Line Items]

Loss contingency accrual

$ 83,000,000

Aliso Canyon Natural Gas Storage Facility Gas Leak [Member] | Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Amount of Natural Gas Released | Bcf

4.62

Loss contingency accrual

$ 83,000,000

Recorded estimated costs

$ 913,000,000

Perecentage of recorded estimated costs allocated to temporary relocation program

60.00%

Recoverable costs through insurance settlement

$ 887,000,000

Reserve for Aliso Canyon costs

84,000,000

Insurance receivable for Aliso Canyon costs

418,000,000

Proceeds from Insurance Settlement, Operating Activities

$ 469,000,000

Loss Contingency, Period Of Required Climate Reductions

20 years

Loss Contingency, Period Of Required Regulatory Climate Reductions

100 years

Loss Contingency, Target Emissions Level | t

9,000,000

Loss Contingency, Total Actual Emissions, Floor | t

90,350

Loss Contingency, Total Actual Emissions, Ceiling | t

108,950

Loss Contingency, Mitigation Requirement | t

109,000

Storage Facility Maximum Capacity | Bcf

86

Aliso Canyon Facility As A Percentage of SoCalGas Total Storage Capacity

28.00%

63.00%

Storage Facility, Working Gas Target | Bcf

23.6

Storage Facility, Working Gas Minimum | Bcf

14.8

Net Book Value Of Aliso Canyon Natural Gas Storage Facility

$ 644,000,000

Construction in Work Progress Of Aliso Canyon Natural Gas Storage Facility

$ 252,000,000

Damages from Product Defects [Member] | Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Maximum Occupational Safety And Health Fines

$ 75,000

Penalty Assessments

233,500

Maximum Other Assessments

$ 5,000,000

Sempra Mexico Property Disputes [Member]

Loss Contingencies [Line Items]

Number of lawsuits

2

HMRC VAT Claim [Member] | Plaintiffs [Member]

Loss Contingencies [Line Items]

Damages sought | £

£ 80

HMRC VAT Claim [Member] | Parent Company [Member]

Loss Contingencies [Line Items]

VAT Tax Claim Paid Upon Appeal | £

£ 86

Subsequent Event [Member] | Aliso Canyon Natural Gas Storage Facility Gas Leak [Member] | Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Number of lawsuits | lawsuit

373

Number Of Plaintiffs | plaintiff

45,000

Minimum [Member] | Aliso Canyon Natural Gas Storage Facility Gas Leak [Member] | Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Liability insurance coverage

$ 1,200,000,000

Loss Contingency, Environmental Mitigation Period

5 years

Storage Facility, Working Gas Target | Bcf

0

Maximum [Member] | Aliso Canyon Natural Gas Storage Facility Gas Leak [Member] | Southern California Gas Company [Member]

Loss Contingencies [Line Items]

Liability insurance coverage

1,400,000,000

Loss Contingency, Environmental Mitigation Period

10 years

Storage Facility, Working Gas Target | Bcf

24.6

Consolidated Class Action Complaints [Member]

Loss Contingencies [Line Items]

Number of lawsuits | lawsuit

2

Property Class Action [Member]

Loss Contingencies [Line Items]

Number of lawsuits | lawsuit

1

Complaints Filed by Public Entities [Member]

Loss Contingencies [Line Items]

Litigation Settlement, Amount Awarded to Other Party

$ 8,500,000

Complaints Filed by Public Entities [Member] | Health Study [Member]

Loss Contingencies [Line Items]

Litigation Settlement, Amount Awarded to Other Party

$ 1,000,000

R B S Sempra Commodities [Member]

Loss Contingencies [Line Items]

Damages sought | £

£ 160

Investment in RBS Sempra Commodities LLP

$ 67,000,000

[1]

As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

[2]

Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

COMMITMENTS AND CONTINGENCIE124

COMMITMENTS AND CONTINGENCIES - LONG-TERM PURCHASE COMMITMENT (Details)	Mar. 13, 2017USD ($)	May 31, 2017USD ($)	May 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2011USD ($)MMcf
Long-term Purchase Commitment [Line Items]
Litigation settlement payable	$ 118,000,000
Sempra LNG & Midstream [Member]
Long-term Purchase Commitment [Line Items]
Loss on release of pipeline capacity			$ 206,000,000
Litigation settlement payable		$ 57,000,000	47,000,000
San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Litigation settlement payable	$ 24,000,000
Sempra LNG & Midstream [Member]
Long-term Purchase Commitment [Line Items]
Loss on release of pipeline capacity			206,000,000
Loss on release of pipeline capacity net of tax			$ 123,000,000
Natural Gas Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				$ 292,000,000
2,019				146,000,000
2,020				48,000,000
2,021				47,000,000
2,022				45,000,000
Thereafter				127,000,000
Total Contractual Commitments				705,000,000
Purchases				1,429,000,000	$ 1,169,000,000	$ 1,200,000,000
Natural Gas Contracts [Member] | SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				108,000,000
2,019				59,000,000
2,020				29,000,000
2,021				28,000,000
2,022				28,000,000
Thereafter				81,000,000
Total Contractual Commitments				333,000,000
Purchases				1,213,000,000	966,000,000	975,000,000
Natural Gas Storage and Transportation Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				231,000,000
2,019				146,000,000
2,020				48,000,000
2,021				46,000,000
2,022				44,000,000
Thereafter				127,000,000
Total Contractual Commitments				642,000,000
Natural Gas Transportation Contracts [Member] | SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				108,000,000
2,019				59,000,000
2,020				29,000,000
2,021				27,000,000
2,022				27,000,000
Thereafter				81,000,000
Total Contractual Commitments				331,000,000
Natural Gas Supply Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				61,000,000
2,019				0
2,020				0
2,021				1,000,000
2,022				1,000,000
Thereafter				0
Total Contractual Commitments				63,000,000
Natural Gas Supply Contracts [Member] | SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				0
2,019				0
2,020				0
2,021				1,000,000
2,022				1,000,000
Thereafter				0
Total Contractual Commitments				2,000,000
Purchased Power Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				702,000,000
2,019				690,000,000
2,020				631,000,000
2,021				633,000,000
2,022				598,000,000
Thereafter				5,726,000,000
Total Contractual Commitments				8,980,000,000
Purchases				1,694,000,000	1,667,000,000	1,573,000,000
Purchased Power Contracts [Member] | SDG&E [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				577,000,000
2,019				571,000,000
2,020				510,000,000
2,021				510,000,000
2,022				496,000,000
Thereafter				5,457,000,000
Total Contractual Commitments				8,121,000,000
Purchases				781,000,000	752,000,000	715,000,000
Sunrise Powerlink Construction [Member] | SDG&E [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
2,018				3,000,000
2,019				3,000,000
2,020				3,000,000
2,021				3,000,000
2,022				3,000,000
Thereafter				104,000,000
Total Commitment				$ 119,000,000
Annual estimated escalation percentage				2.00%
Commitment period				52 years
Present value of future payments				$ 119,000,000
Continental Forge [Member] | Sempra LNG & Midstream [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
Commitment period							18 years
Amount of Natural Gas to be Sold | MMcf							500
Reduction in price index							$ 0.02
Liquefied Natural Gas Contracts [Member] | Sempra LNG & Midstream [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				302,000,000
2,019				383,000,000
2,020				391,000,000
2,021				403,000,000
2,022				411,000,000
Thereafter				2,935,000,000
Total Contractual Commitments				4,825,000,000
Nuclear Plant Maintenance [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				10,000,000
Infrastructure Construction And Improvements [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				257,000,000
2,019				62,000,000
2,020				44,000,000
2,021				24,000,000
2,022				16,000,000
Thereafter				124,000,000
Total Contractual Commitments				527,000,000
Infrastructure Construction And Improvements [Member] | San Diego Gas and Electric Company [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				1,000,000
2,019				1,000,000
2,020				1,000,000
Infrastructure Construction And Improvements [Member] | California Utilities [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
Total Contractual Commitments				10,000,000
Infrastructure Construction And Improvements [Member] | Southern California Gas Company [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				3,000,000
2,019				2,000,000
2,020				2,000,000
Infrastructure Construction And Improvements [Member] | SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				117,000,000
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				78,000,000
2,019				9,000,000
2,020				19,000,000
2,021				5,000,000
2,022				1,000,000
Thereafter				5,000,000
Infrastructure Construction And Improvements [Member] | Sempra South American Utilities [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				16,000,000
Infrastructure Improvements For Natural Gas And Electric Transmission And Distribution [Member] | SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				$ 72,000,000
Long-term Contracts [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				43.00%
Other Owned Generation [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				56.00%
Spot Market Purchases [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				1.00%
Renewable Energy Contracts Expiring Through 2041 [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				37.00%
Sempra Renewables Construction [Member] | Sempra Renewables [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				$ 80,000,000
2,019				4,000,000
2,020				3,000,000
2,021				2,000,000
Total Contractual Commitments				89,000,000
Sempra Natural Gas Construction [Member] | Sempra LNG & Midstream [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				6,000,000
San Luis Rey Synchronous Condensor And Bay Boulevard Substation [Member] | SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				35,000,000
Pipelines [Member] | Sempra Mexico [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2,018				73,000,000
2,019				46,000,000
2,020				19,000,000
2,021				17,000,000
2,022				15,000,000
Thereafter				119,000,000
Total Contractual Commitments				289,000,000
Renewable Energy PPAs [Member] | SDG&E [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
Total Contractual Commitments				5,400,000,000
Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2,018				192,000,000
Power Purchase Agreements [Member] | San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Capital lease depreciation expense				$ 8,000,000	$ 4,000,000	$ 4,000,000

COMMITMENTS AND CONTINGENCIE125

COMMITMENTS AND CONTINGENCIES - OPERATING LEASES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 109	$ 77	$ 78
Future minimum lease payments
2,018	85
2,019	57
2,020	51
2,021	48
2,022	42
Thereafter	300
Total	583
Future estimated rental payments
2,018	13
2,019	12
2,020	12
2,021	12
2,022	13
Thereafter	46
Total	108
Total future rental commitments
2,018	98
2,019	69
2,020	63
2,021	60
2,022	55
Thereafter	346
Total	$ 691
San Diego Gas and Electric Company [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 28	28	27
Future minimum lease payments
2,018	22
2,019	21
2,020	20
2,021	19
2,022	18
Thereafter	54
Total	154
Future estimated rental payments
2,018	2
2,019	2
2,020	2
2,021	2
2,022	2
Thereafter	3
Total	13
Total future rental commitments
2,018	24
2,019	23
2,020	22
2,021	21
2,022	20
Thereafter	57
Total	167
Utility Subsidiaries [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Aggregate maximum lease limit	250
Lease limit utilized	$ 133
Southern California Gas Company [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 43	$ 38	$ 39
Future minimum lease payments
2,018	29
2,019	25
2,020	20
2,021	19
2,022	13
Thereafter	36
Total	142
Future estimated rental payments
2,018	11
2,019	10
2,020	10
2,021	10
2,022	11
Thereafter	43
Total	95
Total future rental commitments
2,018	40
2,019	35
2,020	30
2,021	29
2,022	24
Thereafter	79
Total	$ 237

COMMITMENTS AND CONTINGENCIE126

COMMITMENTS AND CONTINGENCIES - CAPITAL LEASES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Power Purchase Agreements [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	$ 192
2,019	210
2,020	210
2,021	210
2,022	210
Thereafter	3,299
Total minimum payments	4,331
Less: estimated executory costs	(502)
Less: interest	(2,548)
Present value of net minimum lease payments	1,281
Capital leases, Current portion	13
Capital leases, Noncurrent portion	718
Power Purchase Agreement Upon Completion of Power Plant [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Present value of net minimum lease payments	$ 550
HQ Build To Suit Lease [Member]
Leases, Capital [Abstract]
Capital Lease Term (Years)	25
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	$ 10
2,019	10
2,020	11
2,021	11
2,022	11
Thereafter	234
Total minimum payments	287
Present value of net minimum lease payments	138
Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	4
2,019	2
2,020	1
2,021	0
2,022	0
Thereafter	8
Present value of net minimum lease payments	8
Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	3	$ 2	$ 4
San Diego Gas and Electric Company [Member]
Leases, Capital [Abstract]
Capital lease obligations	$ 732	240
San Diego Gas and Electric Company [Member] | Power Purchase Agreements [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	5
Number Of Power Purchase Agreements With Peaker Facilities In Commercial Operation In 2015	1
Capital lease obligations	$ 731
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 8	4	4
San Diego Gas and Electric Company [Member] | Purchase Power Agreements With 25 Year Term [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	4
Capital Lease Term (Years)	25
San Diego Gas and Electric Company [Member] | Purchase Power Agreements With 9 Year Term [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	1
Capital Lease Term (Years)	9
San Diego Gas and Electric Company [Member] | Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	$ 1
San Diego Gas and Electric Company [Member] | Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 1	1	2
San Diego Gas and Electric Company [Member] | Intermediate Stage Power Plant Facility [Member]
Leases, Capital [Abstract]
Power purchase agreement term	20 years
Generating capacity (in mw) | MW	500
Southern California Gas Company [Member]
Leases, Capital [Abstract]
Capital lease obligations	$ 1	0
Southern California Gas Company [Member] | Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	1
Southern California Gas Company [Member] | Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 2	$ 1	$ 2

COMMITMENTS AND CONTINGENCIE127

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL ISSUES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Environmental Issues [Line Items]
Environmental Costs Recognized, Capitalized in Period	$ 92	$ 53	$ 64
San Diego Gas and Electric Company [Member]
Environmental Issues [Line Items]
Environmental Costs Recognized, Capitalized in Period	46	17	24
Southern California Gas Company [Member]
Environmental Issues [Line Items]
Environmental Costs Recognized, Capitalized in Period	$ 45	$ 35	$ 39

COMMITMENTS AND CONTINGENCIE128

COMMITMENTS AND CONTINGENCIES - SITE CONTINGENCY (Details) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2016USD ($)	Dec. 31, 2017USD ($)
Site Contingency [Line Items]
Accrual for environmental loss contingencies		$ 29
Accrual for environmental loss contingencies, current		9
Accrual for environmental loss contingencies, noncurrent		20
SONGS mitigation costs remaining	$ 4,400
Manufactured Gas Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		22
Waste Disposal Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		4
Other Hazardous Waste Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		3
San Diego Gas and Electric Company [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		4
Accrual for environmental loss contingencies, current		1
Accrual for environmental loss contingencies, noncurrent		3
Estimated SONGS mitigation costs, recoverable in rates		68
SONGS mitigation costs incurred		44
SONGS mitigation costs remaining	$ 899	$ 24
San Diego Gas and Electric Company [Member] | Manufactured Gas Sites [Member]
Site Contingency [Line Items]
Site Contingency, Sites Completed		3
Site Contingency, Sites In Process		0
Accrual for environmental loss contingencies		$ 0
San Diego Gas and Electric Company [Member] | Waste Disposal Sites [Member]
Site Contingency [Line Items]
Site Contingency, Sites Completed		2
Site Contingency, Sites In Process		1
Accrual for environmental loss contingencies		$ 2
San Diego Gas and Electric Company [Member] | Other Hazardous Waste Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		2
San Diego Gas and Electric Company [Member] | California Coastal Reef Expansion [Member]
Site Contingency [Line Items]
SONGS mitigation costs remaining		4
Southern California Gas Company [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		24
Accrual for environmental loss contingencies, current		8
Accrual for environmental loss contingencies, noncurrent		$ 16
Southern California Gas Company [Member] | Manufactured Gas Sites [Member]
Site Contingency [Line Items]
Site Contingency, Sites Completed		39
Site Contingency, Sites In Process		3
Accrual for environmental loss contingencies		$ 22
Southern California Gas Company [Member] | Waste Disposal Sites [Member]
Site Contingency [Line Items]
Site Contingency, Sites Completed		5
Site Contingency, Sites In Process		2
Accrual for environmental loss contingencies		$ 1
Southern California Gas Company [Member] | Other Hazardous Waste Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		1
Other Sempra Energy [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		1
Other Sempra Energy [Member] | Manufactured Gas Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		0
Other Sempra Energy [Member] | Waste Disposal Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		1
Other Sempra Energy [Member] | Other Hazardous Waste Sites [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies		$ 0

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)		Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment										6
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										$ 11,207	$ 10,183		$ 10,231
Segment reporting information, Interest Expense										659	553		561
Segment reporting information, Interest Income										46	26		29
Segment reporting information, Depreciation and Amortization										1,490	1,312		1,250
Segment reporting information, Income Tax Expense (Benefit)										1,276	389		341
Earnings attributable to common shares	$ (501)	$ 57	$ 259	$ 441	$ 379		$ 622	$ 16	$ 353	256	1,370		1,349
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	50,454				47,786	[1]				50,454	47,786	[1]	41,150
Segment Reporting Information Expenditures For Property Plant and Equipment										3,949	4,214		3,156
Assets, geographical	39,030				35,028					39,030	35,028		30,944
Entity-Wide Disclosure On Geographic Areas, United States [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										8,547	8,004		8,119
Segment Reporting Information, Additional Information [Abstract]
Assets, geographical	31,487				28,351					31,487	28,351		26,132
Entity-Wide Disclosure On Geographic Areas, South America [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										1,567	1,556		1,544
Segment Reporting Information, Additional Information [Abstract]
Assets, geographical	2,180				1,863					2,180	1,863		1,652
Entity-Wide Disclosure On Geographic Areas Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										1,093	623		568
Segment Reporting Information, Additional Information [Abstract]
Assets, geographical	5,363				4,814					5,363	4,814		3,160
Operating Segments [Member] | SDG&E [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										4,476	4,253		4,219
Segment reporting information, Interest Expense										203	195		204
Segment reporting information, Depreciation and Amortization										670	646		604
Segment reporting information, Income Tax Expense (Benefit)										155	280		284
Earnings attributable to common shares										407	570		587
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	17,844				17,719					17,844	17,719		16,515
Segment Reporting Information Expenditures For Property Plant and Equipment										1,555	1,399		1,133
Operating Segments [Member] | SoCalGas [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										3,785	3,471		3,489
Segment reporting information, Interest Expense										102	97		84
Segment reporting information, Interest Income										1	1		4
Segment reporting information, Depreciation and Amortization										515	476		461
Segment reporting information, Income Tax Expense (Benefit)										160	143		138
Earnings attributable to common shares										396	349		419
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	14,159				13,424					14,159	13,424		12,104
Segment Reporting Information Expenditures For Property Plant and Equipment										1,367	1,319		1,352
Operating Segments [Member] | Sempra South American Utilities [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										1,567	1,556		1,544
Segment reporting information, Interest Expense										38	38		32
Segment reporting information, Interest Income										28	21		19
Segment reporting information, Depreciation and Amortization										54	49		50
Segment reporting information, Income Tax Expense (Benefit)										80	80		67
Earnings attributable to common shares										186	156		175
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	4,060				3,591					4,060	3,591		3,235
Segment Reporting Information Expenditures For Property Plant and Equipment										244	194		154
Operating Segments [Member] | Sempra Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										1,196	725		669
Segment reporting information, Interest Expense										97	13		23
Segment reporting information, Interest Income										23	6		7
Segment reporting information, Depreciation and Amortization										156	77		70
Segment reporting information, Income Tax Expense (Benefit)										227	188		11
Earnings attributable to common shares										169	463		213
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	8,554				7,542					8,554	7,542		3,783
Segment Reporting Information Expenditures For Property Plant and Equipment										248	330		302
Operating Segments [Member] | Sempra Renewables [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										94	34		36
Segment reporting information, Interest Expense										15	4		3
Segment reporting information, Interest Income										7	5		4
Segment reporting information, Depreciation and Amortization										38	6		6
Segment reporting information, Income Tax Expense (Benefit)										(226)	(38)		(49)
Earnings attributable to common shares										252	55		63
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	2,898				3,644					2,898	3,644		1,441
Segment Reporting Information Expenditures For Property Plant and Equipment										497	835		81
Operating Segments [Member] | Sempra LNG & Midstream [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										540	508		653
Segment reporting information, Interest Expense										39	43		72
Segment reporting information, Interest Income										56	71		75
Segment reporting information, Depreciation and Amortization										42	47		49
Segment reporting information, Income Tax Expense (Benefit)										(119)	(80)		28
Earnings attributable to common shares										150	(107)		44
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	4,872				5,564					4,872	5,564		5,566
Segment Reporting Information Expenditures For Property Plant and Equipment										20	117		87
Adjustment and Elimination [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										(1)	0		(2)
All Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Interest Expense										284	282		263
Segment reporting information, Depreciation and Amortization										15	11		10
Segment reporting information, Income Tax Expense (Benefit)										999	(184)		(138)
Earnings attributable to common shares										(1,304)	(116)		(152)
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	915				475					915	475		734
Segment Reporting Information Expenditures For Property Plant and Equipment										18	20		47
Intersegment Eliminations [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										(450)	(364)		(377)
Segment reporting information, Interest Expense										(119)	(119)		(120)
Segment reporting information, Interest Income										(69)	(78)		(80)
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	$ (2,848)				$ (4,173)					(2,848)	(4,173)		(2,228)
Intersegment Eliminations [Member] | SDG&E [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										7	6		9
Intersegment Eliminations [Member] | SoCalGas [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										74	76		75
Intersegment Eliminations [Member] | Sempra Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										103	102		101
Intersegment Eliminations [Member] | Sempra LNG & Midstream [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenue										$ 266	$ 180		$ 192
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

QUARTERLY FINANCIAL DATA (UN130

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, shares in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
Quarterly Financial Data, Revenues	$ 2,964,000,000	$ 2,679,000,000	$ 2,533,000,000	$ 3,031,000,000	$ 2,870,000,000	$ 2,535,000,000	$ 2,156,000,000	$ 2,622,000,000
Quarterly Financial Data, Expenses And Other Income	2,564,000,000	2,664,000,000	2,118,000,000	2,276,000,000	2,365,000,000	1,553,000,000	2,268,000,000	2,167,000,000
Quarterly Financial Data, Net Income (Loss)	(451,000,000)	102,000,000	248,000,000	452,000,000	409,000,000	719,000,000	27,000,000	364,000,000
Earnings	$ (501,000,000)	$ 57,000,000	$ 259,000,000	$ 441,000,000	$ 379,000,000	$ 622,000,000	$ 16,000,000	$ 353,000,000	$ 256,000,000	$ 1,370,000,000	$ 1,349,000,000
Quarterly Financial Data, Net Income Per Share, Basic (in dollars per share)	$ (1.80)	$ 0.41	$ 0.99	$ 1.80	$ 1.63	$ 2.87	$ 0.11	$ 1.46
Basic earnings per common share (in dollars per share)	$ (1.99)	$ 0.23	$ 1.03	$ 1.76	$ 1.51	$ 2.48	$ 0.06	$ 1.41	$ 1.02	$ 5.48	$ 5.43
Weighted-average number of shares outstanding, basic	251,900	251,700	251,400	251,100	250,600	250,400	250,100	249,700	251,545	250,217	248,249
Quarterly Financial Data, Net Income Per Share, Diluted (in dollars per share)	$ (1.80)	$ 0.41	$ 0.98	$ 1.79	$ 1.62	$ 2.85	$ 0.11	$ 1.45
Diluted earnings per common share (in dollars per share)	$ (1.99)	$ 0.22	$ 1.03	$ 1.75	$ 1.51	$ 2.46	$ 0.06	$ 1.40	$ 1.01	$ 5.46	$ 5.37
Weighted-average number of shares outstanding, diluted	251,900	253,400	252,800	252,200	251,600	252,400	252,000	251,500	252,300	251,155	250,923
Antidilutive securities excluded from the computation of EPS	800
San Diego Gas and Electric Company [Member]
Selected Quarterly Financial Information [Line Items]
Quarterly Financial Data, Revenues	$ 1,125,000,000	$ 1,236,000,000	$ 1,058,000,000	$ 1,057,000,000	$ 1,061,000,000	$ 1,209,000,000	$ 992,000,000	$ 991,000,000
Quarterly Financial Data, Operating Expenses	877,000,000	1,290,000,000	817,000,000	779,000,000	800,000,000	886,000,000	822,000,000	755,000,000
Quarterly Financial Data, Operating Income	248,000,000	(54,000,000)	241,000,000	278,000,000	261,000,000	323,000,000	170,000,000	236,000,000
Quarterly Financial Data, Net Income (Loss)	130,000,000	(19,000,000)	153,000,000	157,000,000	147,000,000	194,000,000	87,000,000	137,000,000
Quarterly Financial Data, (Earnings) Losses Attributable To Noncontrolling Interests	(1,000,000)	9,000,000	4,000,000	2,000,000	(4,000,000)	11,000,000	(13,000,000)	1,000,000
Quarterly Financial Data, Earnings Attributable To Common Shares	131,000,000	(28,000,000)	149,000,000	155,000,000	151,000,000	183,000,000	100,000,000	136,000,000
Southern California Gas Company [Member]
Selected Quarterly Financial Information [Line Items]
Quarterly Financial Data, Revenues	1,090,000,000	684,000,000	770,000,000	1,241,000,000	1,135,000,000	686,000,000	617,000,000	1,033,000,000
Quarterly Financial Data, Operating Expenses	888,000,000	674,000,000	675,000,000	926,000,000	899,000,000	648,000,000	628,000,000	739,000,000
Quarterly Financial Data, Operating Income	202,000,000	10,000,000	95,000,000	315,000,000	236,000,000	38,000,000	(11,000,000)	294,000,000
Quarterly Financial Data, Net Income (Loss)	128,000,000	7,000,000	59,000,000	203,000,000	151,000,000	0	0	199,000,000
Quarterly Financial Data, Dividends On Preferred Stock	0	0	1,000,000	0	0	0	1,000,000	0
Quarterly Financial Data, Earnings Attributable To Common Shares	$ 128,000,000	$ 7,000,000	$ 58,000,000	$ 203,000,000	$ 151,000,000	$ 0	$ (1,000,000)	$ 199,000,000

QUARTERLY FINANCIAL DATA (UN131

QUARTERLY FINANCIAL DATA (UNAUDITED) - NARRATIVE (Details) - USD ($) $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Jun. 30, 2017

May 31, 2017

Sep. 30, 2016

May 31, 2016

Mar. 31, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

[1]

Significant Items Affecting Quarterly Results [Line Items]

Total increase in income tax expense due to tax cuts and jobs act

$ 870

Write-off of wildfire regulatory asset

351

$ 0

[1]

$ 0

San Diego Gas and Electric Company [Member]

Significant Items Affecting Quarterly Results [Line Items]

Total increase in income tax expense due to tax cuts and jobs act

28

Write-off of wildfire regulatory asset

351

0

[1]

$ 0

Sempra LNG & Midstream [Member]

Significant Items Affecting Quarterly Results [Line Items]

Other than temporary impairment in investment

$ 44

Other than temporary impairment in investment, net of tax

$ 27

Loss on release of pipeline capacity

$ 206

Loss on release of pipeline capacity net of tax

$ 123

Proceeds from settlement

$ 47

Proceeds from settlement net of taxes

$ 28

IEnova Pipelines [Member] | Sempra Mexico [Member] | IEnova [Member]

Significant Items Affecting Quarterly Results [Line Items]

Gain on acquisition of remaining voting rights

$ 617

617

Gain on acquisition of remaining voting rights, net of tax

432

$ 432

Gain on acquisition of remaining voting rights, net of tax and noncontrolling interests

350

Termoelectrica de Mexicali [Member] | Sempra Mexico [Member]

Significant Items Affecting Quarterly Results [Line Items]

Other than temporary impairment in investment

$ 71

131

$ 71

$ 131

Other than temporary impairment in investment, net of tax

111

$ 111

Other than temporary impairment in investment, net of tax and noncontrolling interest

$ 47

$ 90

Loss from Catastrophes [Member] | San Diego Gas and Electric Company [Member]

Significant Items Affecting Quarterly Results [Line Items]

Write-off of wildfire regulatory asset

351

Write-off of wildfire regulatory asset net of tax

$ 208

[1]

As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ / shares in Units, $ in Millions	Jan. 12, 2018USD ($)	Jan. 09, 2018USD ($)shares$ / sharesRate	Jan. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	[1]	Dec. 31, 2015USD ($)	[1]	Dec. 29, 2017$ / shares
Subsequent Event [Line Items]
Proceeds from issuance of shares				$ 47	$ 51		$ 52
Sempra Energy [Member] | Common Stock [Member]
Subsequent Event [Line Items]
Share price (in dollars per share) | $ / shares									$ 106.92
Subsequent Event [Member] | Public Offering [Member]
Subsequent Event [Line Items]
Shares issued | shares		23,364,486
Subsequent Event [Member] | Over-Allotment Option [Member]
Subsequent Event [Line Items]
Shares issued | shares		3,504,672
Proceeds from issuance of shares		$ 368
Subsequent Event [Member] | Common Stock [Member]
Subsequent Event [Line Items]
Shares issued | shares		26,869,158
Proceeds from issuance of shares		$ 2,460
Subsequent Event [Member] | Common Stock [Member] | Public Offering [Member]
Subsequent Event [Line Items]
Shares issued | shares		23,364,486
Price of shares issued (in dollars per share) | $ / shares		$ 107
Price of shares issued net of underwriting discount (in dollars per share) | $ / shares		$ 105.074
Subsequent Event [Member] | Common Stock [Member] | Over-Allotment Option [Member]
Subsequent Event [Line Items]
Shares issued | shares		3,504,672
Proceeds from issuance of shares		$ 368
Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member]
Subsequent Event [Line Items]
Shares issued | shares		17,250,000	17,250,000
Stated percentage rate		6.00%
Conversion price per share (in dollars per share) | $ / shares		$ 100
Conversion price per share net of underwriting discount (in dollars per share) | $ / shares		98.20
Liquidation preference (in dollars per share) | $ / shares		100
Value of shares issued			$ 1,690
Threshold appreciation price (in dollars per share) | $ / shares		$ 131.075
Share dividends issued, percentage of weighted average share price		97.00%
Number of shares issuable | shares		16,100,000
Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Minimum [Member]
Subsequent Event [Line Items]
Threshold appreciation price (in dollars per share) | $ / shares		$ 107
Shares issuable for each instrument | Rate		76.29%
Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Maximum [Member]
Subsequent Event [Line Items]
Threshold appreciation price (in dollars per share) | $ / shares		$ 131.075
Shares issuable for each instrument | Rate		93.45%
Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Over-Allotment Option [Member]
Subsequent Event [Line Items]
Shares issued | shares		2,250,000
Energy Future Holdings Corp. [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from issuance of debt	$ 4,900
Redemption price percentage	101.00%
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2019 [Member]
Subsequent Event [Line Items]
Debt amount	$ 500
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2019 [Member] | LIBOR [Member]
Subsequent Event [Line Items]
Variable percentage rate	0.25%
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2021 [Member]
Subsequent Event [Line Items]
Debt amount	$ 700
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2021 [Member] | LIBOR [Member]
Subsequent Event [Line Items]
Variable percentage rate	0.50%
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 2.400% Senior Notes Due 2020 [Member]
Subsequent Event [Line Items]
Stated percentage rate	2.40%
Debt amount	$ 500
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 2.900% Senior Notes Due 2023 [Member]
Subsequent Event [Line Items]
Stated percentage rate	2.90%
Debt amount	$ 500
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 3.400% Senior Notes Due 2028 [Member]
Subsequent Event [Line Items]
Stated percentage rate	3.40%
Debt amount	$ 1,000
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 3.800% Senior Notes Due 2038 [Member]
Subsequent Event [Line Items]
Stated percentage rate	3.80%
Debt amount	$ 1,000
Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 4.000% Senior Notes Due 2048 [Member]
Subsequent Event [Line Items]
Stated percentage rate	4.00%
Debt amount	$ 800
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SCHEDULE I, CONDENSED FINANC133

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - STATEMENT OF OPERATIONS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Income Statements, Captions [Line Items]
Interest expense									$ (659)	$ (553)	$ (561)
Other (expense) income, net									254	132	126
Income tax (expense) benefit									(1,276)	(389)	(341)
Equity in earnings of subsidiaries, net of income taxes									42	78	85
Net income/Earnings	$ (501)	$ 57	$ 259	$ 441	$ 379	$ 622	$ 16	$ 353	$ 256	$ 1,370	$ 1,349
Basic earnings per common share (in dollars per share)	$ (1.99)	$ 0.23	$ 1.03	$ 1.76	$ 1.51	$ 2.48	$ 0.06	$ 1.41	$ 1.02	$ 5.48	$ 5.43
Weighted-average number of shares outstanding for basic EPS	251,900	251,700	251,400	251,100	250,600	250,400	250,100	249,700	251,545	250,217	248,249
Earnings Per Share, Diluted	$ (1.99)	$ 0.22	$ 1.03	$ 1.75	$ 1.51	$ 2.46	$ 0.06	$ 1.40	$ 1.01	$ 5.46	$ 5.37
Weighted-average common shares outstanding for diluted EPS	251,900	253,400	252,800	252,200	251,600	252,400	252,000	251,500	252,300	251,155	250,923
Parent Company [Member]
Condensed Income Statements, Captions [Line Items]
Interest expense									$ (293)	$ (277)	$ (261)
Operation and maintenance									(87)	(81)	(66)
Other (expense) income, net									107	(2)	7
Income tax (expense) benefit									33	181	150
Loss before equity in earnings of subsidiaries									(240)	(179)	(170)
Equity in earnings of subsidiaries, net of income taxes									496	1,549	1,519
Net income/Earnings									$ 256	$ 1,370	$ 1,349
Basic earnings per common share (in dollars per share)									$ 1.02	$ 5.48	$ 5.43
Weighted-average number of shares outstanding for basic EPS									251,545	250,217	248,249
Earnings Per Share, Diluted									$ 1.01	$ 5.46	$ 5.37
Weighted-average common shares outstanding for diluted EPS									252,300	251,155	250,923

SCHEDULE I, CONDENSED FINANC134

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - STATEMENT OF COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Condensed Statement of Income Captions [Line Items]
Net income	$ 351	$ 1,519	[1]	$ 1,448	[1]
Total other comprehensive income (loss)	142	52		(334)
Pretax amount [Member]
Condensed Statement of Income Captions [Line Items]
Net income	1,533	1,760		1,691
Foreign currency translation adjustments	107	42		(260)
Financial instruments	2	(6)		(80)
Pension and other postretirement benefits	20	(13)		(3)
Total other comprehensive income (loss)	129	23		(343)
Total comprehensive income, after preferred dividends of subsidiaries	1,661	1,782		1,347
Income tax benefit [Member]
Condensed Statement of Income Captions [Line Items]
Net income	(1,276)	(389)		(341)
Foreign currency translation adjustments	0	0		0
Financial instruments	1	11		33
Pension and other postretirement benefits	(8)	4		1
Total other comprehensive income (loss)	(7)	15		34
Total comprehensive income, after preferred dividends of subsidiaries	(1,283)	(374)		(307)
Net-of-tax amount [Member]
Condensed Statement of Income Captions [Line Items]
Net income	257	1,371		1,350
Foreign currency translation adjustments	107	42		(260)
Financial instruments	3	5		(47)
Pension and other postretirement benefits	12	(9)		(2)
Total other comprehensive income (loss)	122	38		(309)
Total comprehensive income, after preferred dividends of subsidiaries	378	1,408		1,040
Parent Company [Member] | Pretax amount [Member]
Condensed Statement of Income Captions [Line Items]
Net income	223	1,189		1,199
Foreign currency translation adjustments	107	42		(260)
Financial instruments	2	(6)		(80)
Pension and other postretirement benefits	20	(13)		(3)
Total other comprehensive income (loss)	129	23		(343)
Total comprehensive income, after preferred dividends of subsidiaries	352	1,212		856
Parent Company [Member] | Income tax benefit [Member]
Condensed Statement of Income Captions [Line Items]
Net income	33	181		150
Foreign currency translation adjustments	0	0		0
Financial instruments	1	11		33
Pension and other postretirement benefits	(8)	4		1
Total other comprehensive income (loss)	(7)	15		34
Total comprehensive income, after preferred dividends of subsidiaries	26	196		184
Parent Company [Member] | Net-of-tax amount [Member]
Condensed Statement of Income Captions [Line Items]
Net income	256	1,370		1,349
Foreign currency translation adjustments	107	42		(260)
Financial instruments	3	5		(47)
Pension and other postretirement benefits	12	(9)		(2)
Total other comprehensive income (loss)	122	38		(309)
Total comprehensive income, after preferred dividends of subsidiaries	$ 378	$ 1,408		$ 1,040
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

SCHEDULE I, CONDENSED FINANC135

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - BALANCE SHEETS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Assets [Abstract]
Cash and cash equivalents	$ 288	$ 349	[1]
Due from affiliates	37	26	[1]
Income taxes receivable	110	43	[1]
Other current assets	136	142	[1]
Total current assets	3,341	3,110	[1]
Investments in subsidiaries	2,527	2,097	[1]
Due from affiliates	598	201	[1]
Deferred income taxes	170	234	[1]
Other assets	792	520	[1]
Total assets	50,454	47,786	[1]	$ 41,150
Liabilities and shareholders’ equity:
Current portion of long-term debt	1,427	913	[1]
Due to affiliates	7	11	[1]
Other current liabilities	545	517	[1]
Total current liabilities	6,635	5,927	[1]
Long-term debt	16,445	14,429	[1]
Due to affiliates	35	0	[1]
Shareholders’ equity	12,670	12,951	[1]
Total liabilities and equity	50,454	47,786	[1]
Parent Company [Member]
Assets [Abstract]
Cash and cash equivalents	104	12		$ 4	$ 3
Due from affiliates	83	73
Income taxes receivable	272	0
Other current assets	6	2
Total current assets	465	87
Investments in subsidiaries	17,924	17,329
Due from affiliates	2	0
Deferred income taxes	1,802	2,570
Other assets	656	592
Total assets	20,849	20,578
Liabilities and shareholders’ equity:
Current portion of long-term debt	500	600
Due to affiliates	280	359
Income taxes payable	0	153
Other current liabilities	396	374
Total current liabilities	1,176	1,486
Long-term debt	6,198	5,100
Due to affiliates	300	517
Other long-term liabilities	505	524
Shareholders’ equity	12,670	12,951
Total liabilities and equity	$ 20,849	$ 20,578
[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SCHEDULE I, CONDENSED FINANC136

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - CASH FLOWS (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Condensed Cash Flow Statements, Captions [Line Items]
Net cash used in operating activities		$ 3,625	$ 2,311	[1]	$ 2,898	[1]
Expenditures for property, plant and equipment		(3,949)	(4,214)	[1]	(3,156)	[1]
Purchase of trust assets		(2)	9	[1]	9	[1]
Net cash used in investing activities		(4,700)	(4,835)	[1]	(2,868)	[1]
Common stock dividends paid		(755)	(686)	[1]	(628)	[1]
Issuances of common stock		47	51	[1]	52	[1]
Repurchases of common stock		(15)	(56)	[1]	(74)	[1]
Issuances of long-term debt		4,509	2,951	[1]	2,992	[1]
Payments on long-term debt		(2,800)	(2,057)	[1]	(1,854)	[1]
Tax benefit related to share-based compensation		0	0	[1]	52	[1]
Other		(43)	(21)	[1]	(20)	[1]
Net cash provided by (used in) financing activities		1,007	2,502	[1]	(176)	[1]
Cash and cash equivalents, January 1	[2]	349
Cash and cash equivalents, December 31		288	349	[2]
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued Merger-related transaction costs		31	0	[1]	0	[1]
Financing of build-to-suit property		0	0	[1]	61	[1]
Common dividends issued in stock		53	53	[1]	55	[1]
Dividends declared but not paid		214	196	[1]	180	[1]
Parent Company [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash used in operating activities		89	(3)		95
Expenditures for property, plant and equipment		(11)	(5)	[1]	(43)	[1]
Purchase of trust assets		0	0		(5)
Decrease (increase) in loans to affiliate, net		0	457	[1]	(457)	[1]
Expenditures for Merger-related transaction costs		(12)	0		0
Net cash used in investing activities		(23)	452		(505)
Common stock dividends paid		(755)	(686)		(628)
Issuances of common stock		47	51		52
Repurchases of common stock		(15)	(56)		(74)
Issuances of long-term debt		1,595	499		1,248
Payments on long-term debt		(600)	(750)		0
Increase (decrease) in loans from affiliates, net		(239)	504		(230)
Tax benefit related to share-based compensation		0	0		52
Other		(7)	(3)		(9)
Net cash provided by (used in) financing activities		26	(441)		411
(Decrease) increase in cash and cash equivalents		92	8		1
Cash and cash equivalents, January 1		12	4		3
Cash and cash equivalents, December 31		104	12		4
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued Merger-related transaction costs		31	0		0
Financing of build-to-suit property		0	0		61
Common dividends issued in stock		53	53		55
Dividends declared but not paid		$ 207	$ 189		$ 174
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SCHEDULE I, CONDENSED FINANC137

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - FOOTNOTES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Basis of Presentation
Rabbi trust investment gains	$ 9	$ 7		$ 6
Gain (loss) on settlement	(7)	(21)	[1]	10	[1]
New Accounting Standards
Net cash used in operating activities	3,625	2,311	[1]	2,898	[1]
Net cash used in investing activities	(4,700)	(4,835)	[1]	(2,868)	[1]
Other (expense) income, net	254	132		126
Debt Instruments [Abstract]
Current portion of long-term debt	(1,427)	(913)	[2]
Total long-term debt	16,445	14,429	[2]
Long-term Debt, Fiscal Year Maturity [Abstract]
2,018	1,412
2,019	1,419
2,020	1,033
2,021	1,346
2,022	647
Thereafter	11,282
Parent Company [Member]
Basis of Presentation
Rabbi trust investment gains	56	23		3
New Accounting Standards
Net cash used in operating activities	89	(3)		95
Net cash used in investing activities	(23)	452		(505)
Operation and maintenance	(87)	(81)		(66)
Other (expense) income, net	107	(2)		7
Debt Instruments [Abstract]
Market value adjustments for interest rate swaps, net	(1)	(3)
Build-to-suit lease	138	137
Gross long-term debt	6,737	5,734
Current portion of long-term debt	(500)	(600)
Unamortized discount on long-term debt	(13)	(10)
Unamortized debt issuance costs	(26)	(24)
Total long-term debt	6,198	5,100
Long-term Debt, Fiscal Year Maturity [Abstract]
2,018	500
2,019	1,000
2,020	900
2,021	850
2,022	500
Thereafter	2,850
Parent Company [Member] | 2.3% Notes April 1, 2017 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 0	600
Stated percentage rate	2.30%
Parent Company [Member] | 6.15% Notes June 15, 2018 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	6.15%
Parent Company [Member] | 9.8% Notes February 15, 2019 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	9.80%
Parent Company [Member] | 1.625% Notes October 7, 2019 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	1.625%
Parent Company [Member] | 2.4% Notes March 15, 2020 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	2.40%
Parent Company [Member] | 2.85% Notes November 15, 2020 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 400	400
Stated percentage rate	2.85%
Parent Company [Member] | Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 850	0
Effective rate percentage	2.038%
Parent Company [Member] | 2.875% Notes October 1, 2022 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	2.875%
Parent Company [Member] | 4.05% Notes December 1, 2023 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	4.05%
Parent Company [Member] | 3.55% Notes June 15, 2024 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 500	500
Stated percentage rate	3.55%
Parent Company [Member] | 3.75% Notes November 15, 2025 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 350	350
Stated percentage rate	3.75%
Parent Company [Member] | 3.25% Notes June 15, 2027 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 750	0
Stated percentage rate	3.25%
Parent Company [Member] | 6% Notes October 15, 2039 [Member]
Debt Instruments [Abstract]
Gross long-term debt	$ 750	750
Stated percentage rate	6.00%
Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Standards
Net cash used in operating activities		(3)		95
Dividends received from subsidiaries		0		0
Net cash used in investing activities		452		(505)
Parent Company [Member] | Foreign exchange instruments [Member]
Basis of Presentation
Gain (loss) on settlement	$ 50	(28)
As previously reported [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Standards
Other (expense) income, net	254	132
As previously reported [Member] | Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Standards
Net cash used in operating activities		(178)		(255)
Dividends received from subsidiaries		175		350
Net cash used in investing activities		627		(155)
As previously reported [Member] | Parent Company [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Standards
Operation and maintenance	(87)	(81)
Other (expense) income, net	107	(2)
Recast [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Standards
Other (expense) income, net	233	138
Recast [Member] | Parent Company [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Standards
Operation and maintenance	(80)	(76)
Other (expense) income, net	$ 100	(7)
Effect of adoption [Member] | Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
New Accounting Standards
Net cash used in operating activities		175		350
Dividends received from subsidiaries		(175)		(350)
Net cash used in investing activities		$ (175)		$ (350)
[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.