View Filing Data

3,112,000,000

3,031,000,000

^[1]

Dedicated assets in support of certain benefit plans

1,060,000,000

1,131,000,000

^[1]

Other investments

2,845,000,000

2,848,000,000

^[1]

Goodwill

847,000,000

931,000,000

^[1]

Other intangible assets

407,000,000

415,000,000

^[1]

Sundry

701,000,000

561,000,000

^[1]

459,000,000

512,000,000

^[1]

Total investments and other assets

9,646,000,000

^[1]

Property, plant and equipment:

Property, plant and equipment

37,280,000,000

35,407,000,000

^[1]

Less accumulated depreciation and amortization

(9,966,000,000)

(9,505,000,000)

^[1]

Property, plant and equipment, net

27,314,000,000

25,902,000,000

^[1]

Total assets

40,566,000,000

39,732,000,000

^[1]

Current liabilities:

Short-term debt

1,097,000,000

1,733,000,000

^[1]

Accounts payable - trade

1,091,000,000

1,198,000,000

^[1]

Accounts payable - other

143,000,000

155,000,000

^[1]

Due to unconsolidated affiliates

2,000,000

^[1]

Dividends and interest payable

343,000,000

282,000,000

^[1]

Accrued compensation and benefits

356,000,000

373,000,000

^[1]

Current portion of long-term debt

1,168,000,000

469,000,000

^[1]

Fixed-price contracts and other derivatives, current liabilities

73,000,000

55,000,000

^[1]

Customer deposits

152,000,000

153,000,000

^[1]

Other current liabilities

695,000,000

649,000,000

^[1]

Total current liabilities

5,118,000,000

5,069,000,000

^[1]

Long-term debt

12,527,000,000

12,167,000,000

^[1]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

145,000,000

144,000,000

^[1]

Pension and other postretirement benefit obligations, net of plan assets

1,114,000,000

1,064,000,000

^[1]

Deferred income taxes, net noncurrent liabilities

3,057,000,000

3,003,000,000

^[1]

Deferred investment tax credits

34,000,000

37,000,000

^[1]

Regulatory liabilities arising from removal obligations

2,715,000,000

2,741,000,000

^[1]

Asset retirement obligations

2,068,000,000

2,048,000,000

^[1]

Fixed-price contracts and other derivatives, noncurrent liabilities

300,000,000

255,000,000

^[1]

Deferred credits and other

1,092,000,000

1,104,000,000

^[1]

Total deferred credits and other liabilities

10,525,000,000

10,396,000,000

^[1]

Equity:

Preferred stock

^[1]

Common stock

2,587,000,000

2,484,000,000

^[1]

Retained earnings

9,799,000,000

9,339,000,000

^[1]

Accumulated other comprehensive income (loss)

^[2]

(761,000,000)

(497,000,000)

^[1]

Total shareholders' equity

11,625,000,000

11,326,000,000

^[1]

Preferred stock of subsidiaries

20,000,000

^[1]

Other noncontrolling interests

751,000,000

754,000,000

^[1]

Total equity

12,396,000,000

12,100,000,000

^[1]

Total liabilities and equity

40,566,000,000

39,732,000,000

^[1]

Cash and cash equivalents

Current assets:

20,000,000

8,000,000

^[1]

Restricted cash

9,000,000

8,000,000

^[1]

Trade accounts receivable

411,000,000

285,000,000

^[1]

Other accounts and notes receivable

27,000,000

35,000,000

^[1]

Due from unconsolidated affiliates

1,000,000

^[1]

Income taxes receivable

13,000,000

^[1]

Inventories

71,000,000

73,000,000

^[1]

Regulatory balancing accounts, undercollected

495,000,000

711,000,000

^[1]

Fixed-price contracts and other derivatives, current assets

146,000,000

54,000,000

^[1]

20,000,000

44,000,000

^[1]

Other current assets

135,000,000

125,000,000

^[1]

Total current assets

1,348,000,000

1,344,000,000

^[1]

Investments And Other Assets [Abstract]

Restricted cash, noncurrent

12,000,000

11,000,000

^[1]

Deferred taxes recoverable in rates

870,000,000

824,000,000

^[1]

1,000,000,000

1,086,000,000

^[1]

Total investments and other assets

1,060,000,000

1,131,000,000

^[1]

Sundry

376,000,000

282,000,000

^[1]

3,318,000,000

3,334,000,000

^[1]

Property, plant and equipment:

Property, plant and equipment

16,131,000,000

15,478,000,000

^[1]

Less accumulated depreciation and amortization

(4,105,000,000)

(3,860,000,000)

^[1]

Property, plant and equipment, net

12,026,000,000

11,618,000,000

^[1]

Total assets

16,692,000,000

16,296,000,000

^[1]

Current liabilities:

Short-term debt

44,000,000

246,000,000

^[1]

Accounts payable - trade

408,000,000

441,000,000

^[1]

Due to unconsolidated affiliates

22,000,000

21,000,000

^[1]

Income taxes payable

30,000,000

^[1]

Deferred income taxes, net current liabilities

243,000,000

53,000,000

^[1]

Accrued compensation and benefits

110,000,000

124,000,000

^[1]

Current portion of long-term debt

301,000,000

365,000,000

^[1]

Fixed-price contracts and other derivatives, current liabilities

62,000,000

40,000,000

^[1]

Customer deposits

71,000,000

^[1]

Other current liabilities

264,000,000

237,000,000

^[1]

Interest payable

49,000,000

40,000,000

^[1]

Asset Retirement Obligation Current

108,000,000

120,000,000

^[1]

Total current liabilities

1,682,000,000

1,788,000,000

^[1]

Long-term debt

4,477,000,000

4,319,000,000

^[1]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

43,000,000

41,000,000

^[1]

Pension and other postretirement benefit obligations, net of plan assets

227,000,000

216,000,000

^[1]

Deferred income taxes, net noncurrent liabilities

2,155,000,000

2,121,000,000

^[1]

Deferred investment tax credits

19,000,000

22,000,000

^[1]

Regulatory liabilities arising from removal obligations

1,538,000,000

1,557,000,000

^[1]

Asset retirement obligations

740,000,000

754,000,000

^[1]

Fixed-price contracts and other derivatives, noncurrent liabilities

170,000,000

153,000,000

^[1]

Deferred credits and other

352,000,000

333,000,000

^[1]

Total deferred credits and other liabilities

5,244,000,000

5,197,000,000

^[1]

Equity:

Common stock

1,338,000,000

^[1]

Retained earnings

3,899,000,000

3,606,000,000

^[1]

Accumulated other comprehensive income (loss)

(12,000,000)

^[2]

(12,000,000)

^[1]

Total shareholders' equity

5,225,000,000

4,932,000,000

^[1]

Other noncontrolling interests

64,000,000

60,000,000

^[1]

Total equity

5,289,000,000

4,992,000,000

^[1]

Total liabilities and equity

16,692,000,000

16,296,000,000

^[1]

Cash and cash equivalents

Current assets:

123,000,000

85,000,000

^[1]

Trade accounts receivable

301,000,000

586,000,000

^[1]

Other accounts and notes receivable

69,000,000

51,000,000

^[1]

Due from unconsolidated affiliates

220,000,000

4,000,000

^[1]

Income taxes receivable

25,000,000

5,000,000

^[1]

Inventories

192,000,000

181,000,000

^[1]

Regulatory balancing accounts, undercollected

90,000,000

35,000,000

^[1]

Investments And Other Assets [Abstract]

7,000,000

5,000,000

^[1]

Other current assets

39,000,000

36,000,000

^[1]

Total current assets

1,066,000,000

988,000,000

^[1]

Regulatory assets arising from pension and other postretirement benefit obligations

665,000,000

617,000,000

^[1]

Total investments and other assets

543,000,000

472,000,000

^[1]

Sundry

176,000,000

140,000,000

^[1]

1,384,000,000

1,229,000,000

^[1]

Property, plant and equipment:

Property, plant and equipment

13,739,000,000

12,886,000,000

^[1]

Less accumulated depreciation and amortization

(4,834,000,000)

(4,642,000,000)

^[1]

Property, plant and equipment, net

8,905,000,000

8,244,000,000

^[1]

Total assets

11,355,000,000

10,461,000,000

^[1]

Current liabilities:

Short-term debt

50,000,000

^[1]

Accounts payable - trade

355,000,000

532,000,000

^[1]

Accounts payable - other

77,000,000

88,000,000

^[1]

Due to unconsolidated affiliates

51,000,000

13,000,000

^[1]

Deferred income taxes, net current liabilities

171,000,000

53,000,000

^[1]

Accrued compensation and benefits

144,000,000

129,000,000

^[1]

Current portion of long-term debt

9,000,000

Customer deposits

74,000,000

75,000,000

^[1]

Other current liabilities

164,000,000

149,000,000

^[1]

Total current liabilities

1,045,000,000

1,089,000,000

^[1]

Long-term debt

2,498,000,000

1,906,000,000

^[1]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

102,000,000

^[1]

Pension and other postretirement benefit obligations, net of plan assets

682,000,000

633,000,000

^[1]

Deferred income taxes, net noncurrent liabilities

1,270,000,000

1,212,000,000

^[1]

Deferred investment tax credits

14,000,000

16,000,000

^[1]

Regulatory liabilities arising from removal obligations

1,158,000,000

1,167,000,000

^[1]

Asset retirement obligations

1,286,000,000

1,255,000,000

^[1]

Deferred credits and other

293,000,000

300,000,000

^[1]

Total deferred credits and other liabilities

4,805,000,000

4,685,000,000

^[1]

Equity:

Preferred stock

22,000,000

^[1]

Common stock

866,000,000

^[1]

Retained earnings

2,137,000,000

1,911,000,000

^[1]

Accumulated other comprehensive income (loss)

(18,000,000)

^[2]

(18,000,000)

^[1]

Total shareholders' equity

3,007,000,000

2,781,000,000

^[1]

Total equity

3,007,000,000

2,781,000,000

^[1]

Total liabilities and equity

$ 11,355,000,000

$ 10,461,000,000

^[1]

[1]	Derived from audited financial statements.
[2]	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Property, plant and equipment related to VIE	$ 390	$ 410
Long-term debt related to VIE	$ 307	$ 315
Shareholders' equity:
Preferred stock, shares authorized	50	50
Preferred stock, shares issued	0	0
Common stock, shares authorized	750	750
Common stock, shares outstanding	248	246
San Diego Gas and Electric Company [Member]
Property, plant and equipment related to VIE	$ 390	$ 410
Long-term debt related to VIE	$ 307	$ 315
Shareholders' equity:
Common stock, shares authorized	255	255
Common stock, shares outstanding	117	117
Southern California Gas Company [Member]
Shareholders' equity:
Common stock, shares authorized	100	100
Common stock, shares outstanding	91	91

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

REVENUES

Utilities

$ 2,213

$ 2,463

$ 6,768

$ 7,318

Energy-related businesses

268

352

762

970

Total revenues

2,481

2,815

7,530

8,288

Utilities [Abstract]

Cost of natural gas

(201)

(293)

(786)

(1,308)

Cost of electric fuel and purchased power

(666)

(680)

(1,645)

(1,761)

Cost of natural gas, electric fuel and purchased power

(91)

(163)

(262)

(427)

Other cost of sales

(34)

(42)

(111)

(122)

Operation and maintenance

(701)

(726)

(2,072)

(2,131)

Depreciation and amortization

(315)

(292)

(925)

(866)

Plant closure adjustment (loss)

Franchise fees and other taxes

(111)

(104)

(314)

(301)

Gain on sale of equity interest and assets

Equity (losses) earnings before income tax

Equity (losses) earnings, other

Other income (expense), net

118

Interest income

Income (loss) before income taxes and equity earnings of certain unconsolidated subsidiaries

(143)

(144)

(416)

(418)

270

447

1,272

1,210

Equity earnings, net of income tax

(15)

(71)

(276)

(291)

Net income (loss)

282

383

1,060

941

Losses (earnings) attributable to noncontrolling interests

(34)

(35)

(79)

(76)

Basic earnings per common share

(1)

Earnings (losses)

$ 248

$ 348

$ 980

$ 864

Basic earnings per common share:

$ 1

$ 1.41

$ 3.95

$ 3.52

Basic earnings per common share, weighted-average number of shares outstanding (thousands)

^[1]

248,432

246,137

248,090

245,703

Diluted earnings per common share:

Diluted earnings per common share

$ 0.99

$ 1.39

$ 3.91

$ 3.45

Diluted earnings per common share, weighted-average number of shares outstanding (thousands)

251,024

250,771

250,665

250,278

Dividends declared per share of common stock

$ 0.7

$ 0.66

$ 2.1

$ 1.98

Total utility operating revenues

Utility operating revenues

Electric

$ 1,140

$ 1,133

$ 2,819

$ 2,892

Natural gas

100

349

391

1,230

1,233

3,168

3,283

Utility operating expenses

Utility cost of natural gas

112

165

Utility cost of electric fuel and purchased power

427

441

906

1,036

Utility operation and maintenance

251

276

723

784

Utility depreciation

152

134

446

395

Utility franchise fees and other taxes

193

177

Utility plant closure (adjustment) loss

(21)

(13)

Total utility operating expenses

930

957

2,359

2,544

Utility operating income (loss)

300

276

809

739

Equity (losses) earnings before income tax

Other income (expense), net

Income (loss) before income taxes and equity earnings of certain unconsolidated subsidiaries

(51)

(155)

(152)

257

234

680

616

Losses (earnings) attributable to noncontrolling interests

(75)

(65)

(217)

Net income (loss)

182

169

463

399

(12)

(20)

Earnings (losses)

170

157

443

379

Total utility operating revenues

Utility operating revenues

620

855

2,448

2,857

Utility operating expenses

Utility cost of natural gas

163

237

626

1,066

Utility operation and maintenance

325

326

985

968

Utility depreciation

116

109

342

321

Utility franchise fees and other taxes

Total utility operating expenses

633

702

2,047

2,453

Utility operating income (loss)

(13)

153

401

404

Equity (losses) earnings before income tax

Other income (expense), net

Interest income

Income (loss) before income taxes and equity earnings of certain unconsolidated subsidiaries

(23)

(17)

(61)

(50)

(28)

142

368

367

Preferred dividend requirements

(44)

(91)

(110)

Net income (loss)

(8)

277

257

Earnings (losses)

(8)

277

257

(1)

Earnings (losses) attributable to common shares

$ (8)

$ 98

$ 276

$ 256

[1]

Includes fully vested restricted stock units of 504 and 222 held in our Deferred Compensation Plan for the three months ended September 30, 2015 and 2014, respectively, and 486 and 209 for the nine months ended September 30, 2015 and 2014, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Net income	$ 282,000,000	$ 383,000,000	$ 1,060,000,000	$ 941,000,000
Comprehensive income, net of income tax
Preferred dividends of subsidiary	0	0	(1,000,000)	(1,000,000)
Before-Tax Amount [Member]
Net income	263,000,000	419,000,000	1,257,000,000	1,156,000,000
Comprehensive income, net of income tax
Foreign currency translation adjustments	(92,000,000)	(100,000,000)	(197,000,000)	(141,000,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	7,000,000	8,000,000	11,000,000	21,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(128,000,000)	(4,000,000)	(122,000,000)	(24,000,000)
Other Comprehensive Income (Loss), Net of Tax, Total	(213,000,000)	(96,000,000)	(308,000,000)	(144,000,000)
Total Comprehensive Income	50,000,000	323,000,000	949,000,000	1,012,000,000
Preferred dividends of subsidiary			(1,000,000)	(1,000,000)
Total comprehensive income, after preferred dividends of subsidiaries			948,000,000	1,011,000,000
Income Tax (Expense) Benefit [Member]
Net income	(15,000,000)	(71,000,000)	(276,000,000)	(291,000,000)
Comprehensive income, net of income tax
Foreign currency translation adjustments	0	0	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(2,000,000)	(3,000,000)	(4,000,000)	(8,000,000)
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	50,000,000	1,000,000	48,000,000	9,000,000
Other Comprehensive Income (Loss), Net of Tax, Total	48,000,000	(2,000,000)	44,000,000	1,000,000
Total Comprehensive Income	33,000,000	(73,000,000)	(232,000,000)	(290,000,000)
Preferred dividends of subsidiary			0	0
Total comprehensive income, after preferred dividends of subsidiaries			(232,000,000)	(290,000,000)
Net-of-Tax Amount [Member]
Net income	248,000,000	348,000,000	981,000,000	865,000,000
Comprehensive income, net of income tax
Foreign currency translation adjustments	(92,000,000)	(100,000,000)	(197,000,000)	(141,000,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	5,000,000	5,000,000	7,000,000	13,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(78,000,000)	(3,000,000)	(74,000,000)	(15,000,000)
Other Comprehensive Income (Loss), Net of Tax, Total	(165,000,000)	(98,000,000)	(264,000,000)	(143,000,000)
Total Comprehensive Income	83,000,000	250,000,000	717,000,000	722,000,000
Preferred dividends of subsidiary			(1,000,000)	(1,000,000)
Total comprehensive income, after preferred dividends of subsidiaries			716,000,000	721,000,000
Noncontrolling Interests [Member]
Net income	34,000,000	35,000,000	79,000,000	76,000,000
Comprehensive income, net of income tax
Foreign currency translation adjustments	(8,000,000)	(11,000,000)	(21,000,000)	(12,000,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	0	0	0	0
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(3,000,000)	3,000,000	(2,000,000)	2,000,000
Other Comprehensive Income (Loss), Net of Tax, Total	(11,000,000)	(8,000,000)	(23,000,000)	(10,000,000)
Total Comprehensive Income	23,000,000	27,000,000	56,000,000	66,000,000
Preferred dividends of subsidiary			0	0
Total comprehensive income, after preferred dividends of subsidiaries			56,000,000	66,000,000
Total Equity [Member]
Net income	282,000,000	383,000,000	1,060,000,000	941,000,000
Comprehensive income, net of income tax
Foreign currency translation adjustments	(100,000,000)	(111,000,000)	(218,000,000)	(153,000,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	5,000,000	5,000,000	7,000,000	13,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(81,000,000)	0	(76,000,000)	(13,000,000)
Other Comprehensive Income (Loss), Net of Tax, Total	(176,000,000)	(106,000,000)	(287,000,000)	(153,000,000)
Total Comprehensive Income	106,000,000	277,000,000	773,000,000	788,000,000
Preferred dividends of subsidiary			(1,000,000)	(1,000,000)
Total comprehensive income, after preferred dividends of subsidiaries			772,000,000	787,000,000
San Diego Gas and Electric Company [Member]
Net income	182,000,000	169,000,000	463,000,000	399,000,000
San Diego Gas and Electric Company [Member] \| Before-Tax Amount [Member]
Net income	245,000,000	222,000,000	660,000,000	596,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		1,000,000		3,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	0	0		0
Other Comprehensive Income (Loss), Net of Tax, Total	0	1,000,000		3,000,000
Total Comprehensive Income	245,000,000	223,000,000	660,000,000	599,000,000
San Diego Gas and Electric Company [Member] \| Income Tax (Expense) Benefit [Member]
Net income	(75,000,000)	(65,000,000)	(217,000,000)	(217,000,000)
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		0		(1,000,000)
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	0	0		0
Other Comprehensive Income (Loss), Net of Tax, Total	0	0		(1,000,000)
Total Comprehensive Income	(75,000,000)	(65,000,000)	(217,000,000)	(218,000,000)
San Diego Gas and Electric Company [Member] \| Net-of-Tax Amount [Member]
Net income	170,000,000	157,000,000	443,000,000	379,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		1,000,000		2,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	0	0		0
Other Comprehensive Income (Loss), Net of Tax, Total	0	1,000,000		2,000,000
Total Comprehensive Income	170,000,000	158,000,000	443,000,000	381,000,000
San Diego Gas and Electric Company [Member] \| Noncontrolling Interests [Member]
Net income	12,000,000	12,000,000	20,000,000	20,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		0		0
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(1,000,000)	4,000,000		3,000,000
Other Comprehensive Income (Loss), Net of Tax, Total	(1,000,000)	4,000,000		3,000,000
Total Comprehensive Income	11,000,000	16,000,000	20,000,000	23,000,000
San Diego Gas and Electric Company [Member] \| Total Equity [Member]
Net income	182,000,000	169,000,000	463,000,000	399,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		1,000,000		2,000,000
Other Comprehensive Income (Loss), Derivatives Qualifying As Hedges, Net of Tax	(1,000,000)	4,000,000		3,000,000
Other Comprehensive Income (Loss), Net of Tax, Total	(1,000,000)	5,000,000		5,000,000
Total Comprehensive Income	181,000,000	174,000,000	463,000,000	404,000,000
Southern California Gas Company [Member]
Net income	(8,000,000)	98,000,000	277,000,000	257,000,000
Southern California Gas Company [Member] \| Before-Tax Amount [Member]
Net income	(28,000,000)	142,000,000	368,000,000	367,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		4,000,000		4,000,000
Other Comprehensive Income (Loss), Net of Tax, Total		4,000,000		4,000,000
Total Comprehensive Income	(28,000,000)	146,000,000	368,000,000	371,000,000
Southern California Gas Company [Member] \| Income Tax (Expense) Benefit [Member]
Net income	20,000,000	(44,000,000)	(91,000,000)	(110,000,000)
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		(2,000,000)		(2,000,000)
Other Comprehensive Income (Loss), Net of Tax, Total		(2,000,000)		(2,000,000)
Total Comprehensive Income	20,000,000	(46,000,000)	(91,000,000)	(112,000,000)
Southern California Gas Company [Member] \| Net-of-Tax Amount [Member]
Net income	(8,000,000)	98,000,000	277,000,000	257,000,000
Comprehensive income, net of income tax
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax		2,000,000		2,000,000
Other Comprehensive Income (Loss), Net of Tax, Total		2,000,000		2,000,000
Total Comprehensive Income	$ (8,000,000)	$ 100,000,000	$ 277,000,000	$ 259,000,000

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$ 1,060

$ 941

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

925

866

Deferred income taxes and investment tax credits

179

131

Gain on sale of equity interest and assets

(62)

(48)

Plant closure (adjustment) loss

(21)

(13)

Equity earnings

(143)

(84)

Fixed-price contracts and other derivatives

(20)

(19)

Other

Net change in other working capital components

260

(215)

Changes in other assets

(112)

Changes in other liabilities

(5)

Net cash provided by operating activities

2,089

1,661

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(2,227)

(2,320)

Expenditures for investments

(183)

(192)

Proceeds from sale of equity interest and assets, net of cash sold

347

Distributions from investments

Purchases of nuclear decommissioning and other trust assets

(407)

(505)

Proceeds from sales by nuclear decommissioning and other trusts

431

498

Decrease in restricted cash

156

Increase in restricted cash

(81)

(139)

Advances to unconsolidated affiliates

(24)

(100)

Proceeds From Payments For Long Term Loans For Related Parties

Other cash flows from investing activities

Net cash used in investing activities

(1,979)

(2,466)

CASH FLOWS FROM FINANCING ACTIVITIES

Common dividends paid

(468)

(450)

Preferred dividends paid by subsidiaries

(1)

Proceeds from issuances of common stock

Issuances of long-term debt

(74)

(38)

2,058

3,063

Payments on long-term debt

(1,316)

(1,845)

Increase (decrease) in short-term debt, net

(201)

(111)

Other cash flows from financing activities

(57)

(84)

(5)

Net cash provided by (used in) financing activities

572

Effect of exchange rate changes on cash and cash equivalents

(12)

(4)

Increase (decrease) in cash and cash equivalents

127

(237)

Cash and cash equivalents, beginning of period

570

^[1]

904

Cash and cash equivalents, end of period

697

667

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

355

359

Income tax payments, net of refunds

154

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES

Accrued capital expenditures

459

385

Redemption of industrial development bonds

Increase in capital lease obligations for investments in property, plant and equipment

Dividends declared but not paid

179

166

Financing of build-to-suit property

Common dividends issued in stock

Acquisition Of Business [Abstract]

Assets acquired

Accrued purchase price

(5)

Liabilities Assumed

(2)

Cash paid

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

463

399

Adjustments to reconcile net income to net cash provided by operating activities:

Utility depreciation and amortization

446

395

Deferred income taxes and investment tax credits

170

193

Utility plant closure (adjustment) loss

(21)

(13)

Fixed-price contracts and other derivatives

(3)

(5)

Other

(14)

(30)

Net change in other working capital components

136

(252)

Changes in other assets

(93)

106

Changes in other liabilities

Net cash provided by operating activities

1,094

821

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(835)

(790)

Purchases of nuclear decommissioning trust assets

(404)

(501)

Proceeds from sales by nuclear decommissioning trusts

431

498

Decrease in restricted cash

109

Increase in restricted cash

(29)

(96)

Other cash flows from investing activities

(16)

Net cash used in investing activities

(810)

(796)

CASH FLOWS FROM FINANCING ACTIVITIES

Common dividends paid

(150)

Issuances of long-term debt

388

100

Payments on long-term debt

(294)

(22)

Increase (decrease) in short-term debt, net

(202)

(59)

Net cash provided by (used in) financing activities

(14)

(38)

(272)

(19)

Increase (decrease) in cash and cash equivalents

Cash and cash equivalents, beginning of period

^[1]

Cash and cash equivalents, end of period

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

141

136

Income tax payments, net of refunds

(4)

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES

Accrued capital expenditures

142

118

Increase in capital lease obligations for investments in property, plant and equipment

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

277

257

Adjustments to reconcile net income to net cash provided by operating activities:

Utility depreciation and amortization

342

321

Deferred income taxes and investment tax credits

Other

(18)

(2)

Net change in other working capital components

(19)

Changes in other assets

(57)

(70)

Changes in other liabilities

Net cash provided by operating activities

690

596

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(946)

(764)

Increase in loans to affiliates, net

(250)

(281)

Net cash used in investing activities

(1,196)

(1,045)

CASH FLOWS FROM FINANCING ACTIVITIES

Preferred dividends paid

(1)

Issuances of long-term debt

599

747

Payments on long-term debt

(250)

Increase (decrease) in short-term debt, net

(50)

(42)

Other cash flows from financing activities

(4)

(7)

Net cash provided by (used in) financing activities

544

447

Increase (decrease) in cash and cash equivalents

(2)

Cash and cash equivalents, beginning of period

^[1]

Cash and cash equivalents, end of period

123

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

Income tax payments, net of refunds

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES

Accrued capital expenditures

172

137

Dividends declared but not paid

$ 50

$ 0

[1]	Derived from audited financial statements.

GENERAL	3 Months Ended
GENERAL	Sep. 30, 2015
Notes to Consolidated Financial Statements [Abstract]
General	NOTE 1. GENERAL IMPACT OF SEASONALIZATION AT SEMPRA ENERGY AND SOUTHERN CALIFORNIA GAS COMPANY In the first quarter of 2015, Southern California Gas Company (SoCalGas) adopted a California Public Utilities Commission (CPUC) decision in the Triennial Cost Allocation Proceeding (TCAP) requiring SoCalGas to recognize annual authorized revenue for core natural gas customers using seasonal factors established in the TCAP, instead of recognizing such revenue ratably over the year as was previously required. This “seasonalization” resulted in $158 million lower operating revenues and $113 million lower earnings for both Sempra Energy and SoCalGas for the three months ended September 30, 2015 compared to the same period in 2014, and $67 million lower operating revenues and $48 million lower earnings for both Sempra Energy and SoCalGas for the first nine months of 2015 compared to the same period in 2014. While this seasonalization will cause variability in comparable revenue and earnings from quarter to quarter within the year, it will not impact full-year 2015 results nor have any impact on cash flows. Accordingly, substantially all of SoCalGas’ annual earnings will be recognized in the first and fourth quarters of the year. We discuss the CPUC decision further in Note 10. PRINCIPLES OF CONSOLIDATION Sempra Energy Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are San Diego Gas & Electric Company (SDG&E) and SoCalGas, which are separate, reportable segments; Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural Gas reportable segments. We provide descriptions of each of our segments in Note 12. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova further in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2014 (the Annual Report), which includes the combined reports for Sempra Energy, SDG&E and SoCalGas. Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 3 and 4 herein and in the Notes to Consolidated Financial Statements in the Annual Report. SDG&E SDG&E’s Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss in Note 5 under “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy. SoCalGas SoCalGas’ Condensed Consolidated Financial Statements include its accounts and the de minimis accounts of inactive subsidiaries. SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra Energy. BASIS OF PRESENTATION This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity. We have prepared the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after September 30, 2015 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature. All December 31, 2014 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2014 Consolidated Financial Statements in the Annual Report. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the Securities and Exchange Commission. We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes. You should read the information in this Quarterly Report in conjunction with the Annual Report. Regulated Operations Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas México, S. de R.L. de C.V. (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Sempra Natural Gas’ Mobile Gas and Willmut Gas, and Sempra Mexico’s Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

NEW ACCOUNTING STANDARDS	3 Months Ended
NEW ACCOUNTING STANDARDS	Sep. 30, 2015
Notes to Consolidated Financial Statements [Abstract]
New Accounting Standards	NOTE 2. NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures. SEMPRA ENERGY, SDG&E AND SOCALGAS Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09) and ASU 2015-14, “Revenue from Contracts with Customers: Deferral of the Effective Date” (ASU 2015-14): ASU 2014-09 provides accounting guidance for revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. ASU 2015-14 defers the effective date of ASU 2014-09 by one year for all entities and permits early adoption on a limited basis. For public entities, ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We have not yet selected the year in which we will adopt the standard or our transition method, nor have we determined the effect of the standard on our ongoing financial reporting. ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) and ASU 2015-15, “Interest - Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (ASU 2015-15): ASU 2015-03 provides guidance on the financial statement presentation of debt issuance costs and requires an entity to present debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related long-term debt liability. This guidance must be applied using a full retrospective approach for all periods presented in the period of adoption. We will adopt ASU 2015-03 for our annual reporting period ending December 31, 2015, and the adoption will not affect our results of operations or cash flows. Deferred debt issuance costs that are the subject of ASU 2015-03 are included in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets and total $78 million, $32 million, and $18 million at September 30, 2015, respectively, and $72 million, $33 million, and $15 million at December 31, 2014, respectively. ASU 2015-15 clarifies ASU 2015-03 to provide additional guidance related to line-of-credit arrangements and states that the Securities and Exchange Commission staff would not object to an entity continuing to defer and present costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. We will adopt ASU 2015-15 for our annual reporting period ending December 31, 2015 and will continue to include deferred costs related to our line-of-credit arrangements that are the subject of ASU 2015-15 in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets. ASU 2015-16, “Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments” (ASU 2015-16): ASU 2015-16 eliminates the requirement that acquirers in a business combination account for measurement-period adjustments retrospectively. Instead, the acquirers will recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts that would have been recorded in previous periods if the accounting had been completed at the acquisition date. We will adopt ASU 2015-16 for our annual reporting period ending December 31, 2015. Any subsequent measurement-period adjustments to the purchase price allocation related to the acquisition of Gasoductos de Chihuahua that we discuss in Note 3 will occur after the adoption of ASU 2015-16 and will be recognized in the period in which the adjustments are determined.

Notes to Consolidated Financial Statements [Abstract]

Tabular disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22580-107794

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e765-108305

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22499-107794

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e725-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

+ Details

RECENT INVESTMENT ACTIVITY

3 Months Ended

Sep. 30, 2015

Recent Investment Activity

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

PENDING ACQUISITION

Sempra Mexico

IEnova and Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company), are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). On July 31, 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest for $1.325 billion (excluding the assumption of approximately $170 million of net debt), increasing its interest from 50 percent to 100 percent. GdC develops and operates energy infrastructure in Mexico. The assets involved in the acquisition include three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excludes the Los Ramones Norte pipeline that IEnova will continue to develop under a separate joint venture with PEMEX, through which IEnova’s interest in the project will remain at the current 25 percent. IEnova shareholders approved the transaction in September 2015. The transaction is subject to satisfactory completion of the Mexican anti-trust review and other customary closing conditions and is expected to close by the end of 2015.

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

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

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

MESQUITE POWER SALE

Sempra Natural Gas

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

SALE OF EQUITY INTERESTS AND JOINT VENTURE INVESTMENT

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

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

Sempra Mexico

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

Sempra Renewables

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

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

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

INVESTMENTS IN UNCONSOLIDATED ENTITIES	3 Months Ended
INVESTMENTS IN UNCONSOLIDATED ENTITIES	Sep. 30, 2015
Notes to Consolidated Financial Statements [Abstract]
Investments in Unconsolidated Entities	NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES We provide additional information concerning our equity method investments in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report. SEMPRA RENEWABLES In addition to Sempra Renewables’ investment in the California solar partnership discussed in Note 3 above, during the nine months ended September 30, 2015 and 2014, Sempra Renewables invested cash of $18 million and $76 million, respectively, in its other renewable energy joint ventures. SEMPRA NATURAL GAS During the nine months ended September 30, 2015, Sempra Natural Gas invested $10 million of cash in its joint venture, Cameron LNG Holdings, LLC (Cameron LNG Holdings or Cameron LNG JV), and capitalized $36 million of interest related to this equity method investment that has not commenced planned principal operations. In April 2015, Sempra Natural Gas invested $113 million of cash in its equity method investment, Rockies Express Pipeline LLC, a partnership that operates the Rockies Express pipeline, to repay project debt that matured in early 2015.

OTHER FINANCIAL DATA

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

Other Financial Data

NOTE 5. OTHER FINANCIAL DATA

INVENTORIES

The components of inventories by segment are as follows:

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

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The decrease in goodwill from $931 million at December 31, 2014 to $847 million at September 30, 2015 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in Other Comprehensive Income (Loss).

VARIABLE INTEREST ENTITIES (VIE)

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

the purpose and design of the VIE;
the nature of the VIE’s risks and the risks we absorb;
the power to direct activities that most significantly impact the economic performance of the VIE; and
the obligation to absorb losses or right to receive benefits that could be significant to the VIE.

SDG&E

Tolling Agreements

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based upon our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. We determine if SDG&E is the primary beneficiary in these cases based on a qualitative approach in which we consider the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE, as we discuss below.

Otay Mesa VIE

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

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy have consolidated Otay Mesa VIE. Otay Mesa VIE’s equity of $64 million at September 30, 2015 and $60 million at December 31, 2014 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

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

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

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

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

Sempra Natural Gas

Cameron LNG JV

Sempra Energy’s equity method investment in Cameron LNG JV is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV was $956 million and $1,007 million at September 30, 2015 and December 31, 2014, respectively. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary at September 30, 2015. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.

Sempra Energy’s other operating units also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based upon the qualitative and quantitative analyses described above. Certain of these entities are service companies that are VIEs. As the primary beneficiary of these service companies, we consolidate them; however, their financial statements are not material to the financial statements of Sempra Energy. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.

PENSION AND OTHER POSTRETIREMENT BENEFITS

Net Periodic Benefit Cost

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

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2015		2014		2015		2014
Service cost	$	27	$	23	$	5	$	6
Interest cost		38		39		10		13
Expected return on assets		(42)		(42)		(17)		(15)
Amortization of:
Prior service cost (credit)		3		3		(1)		(2)
Actuarial loss		9		3		―		―
Settlements and special termination benefits		4		5		―		5
Regulatory adjustment		(27)		6		4		5
Total net periodic benefit cost	$	12	$	37	$	1	$	12

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

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

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

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

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

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2015:

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy
	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2015:
Pension plans	$	27	$	2	$	1
Other postretirement benefit plans		3		―		―
Total expected contributions in 2015:
Pension plans	$	36	$	3	$	7
Other postretirement benefit plans		11		7		1

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $459 million and $512 million at September 30, 2015 and December 31, 2014, respectively.

EARNINGS PER SHARE

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

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

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

Earnings per share:
Basic		$	1.00	$	1.41	$	3.95	$	3.52
Diluted			0.99		1.39		3.91		3.45
(1)	Includes fully vested restricted stock units of 504 and 222 held in our Deferred Compensation Plan for the three months ended September 30, 2015 and 2014, respectively, and 486 and 209 for the nine months ended September 30, 2015 and 2014, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation of dilutive common stock equivalents excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). We had no such antidilutive stock options outstanding for the three months or nine months ended September 30, 2015 or 2014. For the three months and nine months ended September 30, 2015 and 2014, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were no antidilutive RSAs or RSUs from the application of unearned compensation in the treasury stock method for the three months and nine months ended September 30, 2015. There were no such antidilutive RSAs or RSUs for the three months or nine months ended September 30, 2014.

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

Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our TSR RSUs and EPS RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative indices, dilutive TSR RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all performance-based RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 2,001,020 and 2,047,656 for the three months and nine months ended September 30, 2015, respectively, and 844,251 and 971,943 for the three months and nine months ended September 30, 2014, respectively.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $7 million and $8 million for the three-month periods ended September 30, 2015 and 2014, respectively, and $22 million for each of the nine-month periods ended September 30, 2015 and 2014. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s compensation committee granted 301,319 TSR RSUs, 76,675 EPS RSUs and 133,159 RSUs issued either as service-based awards or in connection with certain other performance goals during the nine months ended September 30, 2015, primarily in January.

During the nine months ended September 30, 2015, IEnova issued 278,538 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which awards are cash settled at vesting based on the price of IEnova common stock.

CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and, primarily at the California Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects.

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

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

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

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

COMPREHENSIVE INCOME

The following tables present the changes in Accumulated Other Comprehensive Income (Loss) (AOCI) by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests:

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
				Pension and other
				postretirement benefits
		Foreign								Total
		currency		Unamortized		Unamortized				accumulated other
		translation		net actuarial		prior service		Financial		comprehensive
		adjustments		gain (loss)		cost		instruments		income (loss)
		Three months ended September 30, 2015 and 2014
2015:
Balance as of June 30, 2015		$	(427)	$	(81)	$	(2)	$	(86)	$	(596)
Other comprehensive loss before
reclassifications			(92)		―		―		(79)		(171)
Amounts reclassified from accumulated other
comprehensive income			―		5		―		1		6
Net other comprehensive (loss) income			(92)		5		―		(78)		(165)
Balance as of September 30, 2015		$	(519)	$	(76)	$	(2)	$	(164)	$	(761)
2014:
Balance as of June 30, 2014		$	(170)	$	(65)	$	―	$	(38)	$	(273)
Other comprehensive loss before
reclassifications			(100)		―		―		(2)		(102)
Amounts reclassified from accumulated other
comprehensive income (loss)			―		5		―		(1)		4
Net other comprehensive (loss) income			(100)		5		―		(3)		(98)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

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

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
			Sempra Energy		Non-
			shareholders’		controlling		Total
			equity		interests(1)		equity
Balance at December 31, 2014		$	11,326	$	774	$	12,100
Comprehensive income			717		56		773
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			39		―		39
Common stock dividends declared			(520)		―		(520)
Issuance of common stock			82		―		82
Repurchases of common stock			(74)		―		(74)
Tax benefit related to share-based compensation			56		―		56
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(60)		(60)
Balance at September 30, 2015		$	11,625	$	771	$	12,396
Balance at December 31, 2013		$	11,008	$	842	$	11,850
Comprehensive income			722		66		788
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			35		―		35
Common stock dividends declared			(486)		―		(486)
Issuance of common stock			71		―		71
Repurchases of common stock			(38)		―		(38)
Tax benefit related to share-based compensation			22		―		22
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(85)		(85)
Balance at September 30, 2014		$	11,333	$	824	$	12,157
(1)	Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under "Other Noncontrolling Interests."

SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST ― SDG&E
(Dollars in millions)
		SDG&E		Non-
		shareholder’s		controlling		Total
		equity		interest		equity
Balance at December 31, 2014	$	4,932	$	60	$	4,992
Comprehensive income		443		20		463
Common stock dividends declared		(150)		―		(150)
Distributions to noncontrolling interest		―		(16)		(16)
Balance at September 30, 2015	$	5,225	$	64	$	5,289
Balance at December 31, 2013	$	4,628	$	91	$	4,719
Comprehensive income		381		23		404
Distributions to noncontrolling interest		―		(37)		(37)
Balance at September 30, 2014	$	5,009	$	77	$	5,086

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

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

Preferred Stock

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

Other Noncontrolling Interests

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

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

TRANSACTIONS WITH AFFILIATES

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

DUE FROM UNCONSOLIDATED AFFILIATES(1)
(Dollars in millions)
			September 30, 2015		December 31, 2014
Sempra South American Utilities:
Eletrans S.A.:
4% Note(2)		$	65	$	41
Sempra Mexico:
Affiliate of joint venture with Petróleos Mexicanos(3):
Note due November 13, 2017(4)(5)			3		44
Note due November 14, 2018(4)			41		40
Note due November 14, 2018(4)			34		33
Note due November 14, 2018(4)			8		8
Energía Sierra Juárez:
Note due June 15, 2018(6)			24		22
Other(7)			3		38
Total		$	178	$	226
(1)	Amounts include principal balances plus accumulated interest outstanding.
(2)	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A., an affiliate of Chilquinta Energía.
(3)	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company).
(4)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.69 percent at September 30, 2015), to finance the Los Ramones Norte pipeline project.
(5)	In May 2015, $41 million was paid with proceeds from project financing at the affiliate.
(6)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.57 percent at September 30, 2015), to finance the first phase of the Energía Sierra Juárez wind project.
(7)	Amounts represent accounts receivable from various Sempra Renewables and Sempra Mexico joint venture investments.

Service Agreements

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

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


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

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


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


Income taxes due from Sempra Energy(1)		$	29	$	9
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.
(2)	Net receivable includes a loan to Sempra Energy of $250 million at September 30, 2015 at an interest rate of 0.10 percent.

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

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

OTHER INCOME, NET

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

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

INCOME TAXES

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

Changes in Income Tax Expense and Effective Income Tax Rates

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted are factored into the forecasted effective tax rate, and their impact is recognized proportionately over the year. The forecasted items, anticipated on a full year basis, may include, among others:

utility self-developed software expenditures
repairs to certain utility plant assets
renewable energy income tax credits
deferred income tax benefits related to renewable energy projects
exclusions from taxable income of the equity portion of AFUDC
depreciation on a certain portion of utility plant assets

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

Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, remeasurement of deferred tax asset valuation allowances, Mexican currency translation and inflation adjustments, and deferred income tax benefit associated with the impairment of a book investment) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.

Sempra Energy Consolidated

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

$12 million higher favorable resolution of prior years’ income tax items in 2015;
$9 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and
$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

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

$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in San Onofre Nuclear Generating Station (SONGS) that we discuss in Note 9;
$19 million higher favorable resolution of prior years’ income tax items in 2015;
$22 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and
$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

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

SDG&E

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

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

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

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

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

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

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

SoCalGas

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

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

lower flow-through component of state income taxes.

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

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

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

For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment:

repairs expenditures related to a certain portion of utility plant assets
the equity portion of AFUDC
a portion of the cost of removal of utility plant assets
utility self-developed software expenditures
depreciation on a certain portion of utility plant assets

state income taxes

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico and Sempra Natural Gas has similar flow-through treatment.

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

DEBT AND CREDIT FACILITIES	3 Months Ended
DEBT AND CREDIT FACILITIES	Sep. 30, 2015
Notes to Consolidated Financial Statements [Abstract]
Debt and Credit Facilities	NOTE 6. DEBT AND CREDIT FACILITIES LINES OF CREDIT At September 30, 2015, Sempra Energy Consolidated had an aggregate of $4.1 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the major components of which we detail below. Available unused credit on these lines at September 30, 2015 was approximately $3.3 billion. Some of Sempra Energy’s subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $945 million at September 30, 2015. Available unused credit on these lines totaled $485 million at September 30, 2015. Sempra Energy Line of Credit at September 30, 2015 Sempra Energy had a $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. served as administrative agent for the syndicate of 24 lenders. Borrowings bore interest at benchmark rates plus a margin that varied with market index rates and Sempra Energy’s credit ratings. The facility required Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. The facility also provided for issuance of up to $635 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. At September 30, 2015, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility. Amended and Restated Line of Credit Effective October 13, 2015 On October 13, 2015, Sempra Energy entered into an amended and restated, five-year syndicated revolving credit agreement expiring in October 2020. The credit facility permits borrowings of up to $1 billion. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders and no single lender has greater than a 7-percent share. The credit facility amends, restates and supersedes Sempra Energy’s $1.067 billion credit agreement that was to expire in 2017. Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. Sempra Global Line of Credit at September 30, 2015 Sempra Global had a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. served as administrative agent for the syndicate of 25 lenders. Sempra Energy guaranteed Sempra Global’s obligations under the credit facility. Borrowings bore interest at benchmark rates plus a margin that varied with market index rates and Sempra Energy’s credit ratings. The facility required Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. At September 30, 2015, Sempra Global had $734 million of commercial paper outstanding supported by the facility. Amended and Restated Line of Credit Effective October 13, 2015 On October 13, 2015, Sempra Global entered into an amended and restated, five-year syndicated revolving credit agreement expiring in October 2020. The credit facility permits borrowings of up to $2.21 billion. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders and no single lender has greater than a 7-percent share. The credit facility amends, restates and supersedes Sempra Global’s $2.189 billion credit agreement that was to expire in 2017. Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. California Utilities Line of Credit at September 30, 2015 SDG&E and SoCalGas had a combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. served as administrative agent for the syndicate of 24 lenders. The agreement permitted each utility to individually borrow up to $658 million, subject to a combined limit of $877 million for both utilities. It also provided for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $300 million for both utilities. The amount of borrowings otherwise available under the facility was reduced by the amount of outstanding letters of credit. Borrowings under the facility bore interest at benchmark rates plus a margin that varied with market index rates and the borrowing utility’s credit ratings. The agreement required each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, the California Utilities were in compliance with this and all other financial covenants under the credit facility. Each utility’s obligations under the agreement were individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility. At September 30, 2015, SDG&E had $44 million of commercial paper outstanding, supported by the facility. SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at September 30, 2015 was $614 million and $658 million at SDG&E and SoCalGas, respectively, subject to the $877 million maximum combined credit limit. Amended and Restated Line of Credit Effective October 13, 2015 On October 13, 2015, SDG&E and SoCalGas entered into a combined $1 billion, amended and restated, five-year syndicated revolving credit agreement expiring in October 2020. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $750 million, subject to a combined limit of $1 billion for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The credit facility amends, restates and supersedes the California Utilities’ $877 million credit agreement that was to expire in 2017. Borrowings bear interest at benchmark rates plus a margin that varies with the borrowing utility’s credit rating. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. Each utility’s obligations under the agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility. Sempra Mexico In 2014, IEnova entered into an agreement for a $200 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México. Also in 2014, IEnova entered into an agreement for a $100 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Sumitomo Mitsui Banking Corporation. Both revolving credit facilities were entered into to finance working capital and for general corporate purposes. In August 2015, IEnova entered into a $400 million, five-year revolving credit agreement to replace, and repay the $210 million in outstanding borrowings under, the two existing revolving credit facilities described above. The lenders are Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México, The Bank of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. At September 30, 2015, IEnova had $290 million of outstanding borrowings supported by the facility, and available unused credit on the line was $110 million. WEIGHTED AVERAGE INTEREST RATES The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 0.66 percent and 0.70 percent at September 30, 2015 and December 31, 2014, respectively. The weighted average interest rate on total short-term debt at SDG&E was 0.15 percent at September 30, 2015. At December 31, 2014, the weighted average interest rates on total short-term debt at SDG&E and SoCalGas were 0.27 percent and 0.25 percent, respectively. LONG-TERM DEBT Sempra Energy In March 2015, Sempra Energy publicly offered and sold $500 million of 2.40-percent, fixed-rate notes maturing in 2020. Sempra Energy used the proceeds from this offering to repay outstanding commercial paper. SDG&E In March 2015, SDG&E publicly offered and sold $140 million of first mortgage bonds maturing in 2017 at a variable rate of three-month LIBOR plus 0.20 percent (0.53 percent at September 30, 2015) and $250 million of 1.914-percent amortizing first mortgage bonds maturing in 2022. SDG&E used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes. On August 28, 2015, SDG&E redeemed, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $169 million. The coupon rates of these instruments ranged from 4.9 percent to 5.5 percent, with maturities ranging from 2021 to 2027. SoCalGas In June 2015, SoCalGas publicly offered and sold $250 million of 1.55-percent and $350 million of 3.20-percent first mortgage bonds maturing in 2018 and 2025, respectively. SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes. Sempra South American Utilities In May and June 2015, Luz del Sur borrowed $13 million and $22 million, respectively, under a bank loan facility. The loans accrue interest at 5.18 percent and mature in May 2018 and June 2018, respectively. In August 2015, Luz del Sur borrowed $9 million under a bank loan facility. The loan accrues interest at 6.70 percent and matures in February 2018. In September 2015, Luz del Sur publicly offered and sold $25 million of corporate bonds at 8.75 percent maturing in September 2026. Sempra Natural Gas In June 2015, Sempra Natural Gas reduced its other long-term debt by $79 million through redemption of its investment in industrial development bonds at Mississippi Hub, LLC. Sempra Natural Gas plans to redeem, prior to maturity, $55 million of industrial development bonds payable at Bay Gas Storage Company, Ltd. Accordingly, the debt is classified as current portion of long-term debt at September 30, 2015 on Sempra Energy’s Condensed Consolidated Balance Sheet. The redemption is anticipated to occur during the fourth quarter of 2015. INTEREST RATE SWAPS We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.

DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

Derivative Financial Instruments

NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not presented below.

We record all derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows.

In certain cases, we apply the normal purchase or sale exception to derivative accounting and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that a given future revenue or expense item may vary, and other criteria.

We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:

The California Utilities use energy derivatives, both natural gas and electricity, for the benefit of customers, with the objective of managing price risk and basis risks, and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.
SDG&E is allocated and may purchase congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations.
Sempra Mexico and Sempra Natural Gas may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (LNG), natural gas transportation, power generation, and Sempra Natural Gas’ storage. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.

From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel.

We summarize net energy derivative volumes at September 30, 2015 and December 31, 2014 as follows:

NET ENERGY DERIVATIVE VOLUMES

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

Energy-Related Businesses:
Sempra Natural Gas – natural gas		39 million MMBtu	29 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales.

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.

Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries. Interest rate derivatives are generally accounted for as hedges, and although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to energy derivatives. Separately, Otay Mesa VIE has entered into interest rate swap agreements to moderate its exposure to interest rate changes. This activity was designated as a cash flow hedge as of April 1, 2011.

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

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

FOREIGN CURRENCY DERIVATIVES

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

In addition, Sempra South American Utilities may utilize foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk. We discuss such swaps at Chilquinta Energía’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

FINANCIAL STATEMENT PRESENTATION

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2015
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	7	$	―	$	(16)	$	(159)
Commodity contracts not subject to rate recovery			6		―		―		―
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			―		―		(3)		―
Commodity contracts not subject to rate recovery			166		31		(147)		(18)
Associated offsetting commodity contracts			(137)		(18)		137		18
Associated offsetting cash collateral			―		―		3		―
Commodity contracts subject to rate recovery			7		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			48		99		(59)		(195)
Additional cash collateral for commodity contracts
not subject to rate recovery			3		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			15		―		―		―
Total(4)		$	66	$	99	$	(59)	$	(195)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(15)	$	(29)
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery			―		―		(1)		―
Associated offsetting cash collateral			―		―		1		―
Commodity contracts subject to rate recovery			6		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			5		86		(48)		(65)
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	20	$	86	$	(48)	$	(65)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery		$	―	$	―	$	(2)	$	―
Associated offsetting cash collateral			―		―		2		―
Commodity contracts subject to rate recovery			1		―		―		―
Net amounts presented on the balance sheet			1		―		―		―
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			1		―		―		―
Total		$	3	$	―	$	―	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2014
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	10	$	3	$	(17)	$	(109)
Commodity contracts not subject to rate recovery			25		―		―		―
Derivatives not designated as hedging instruments:
Interest rate instruments			8		27		(7)		(22)
Commodity contracts not subject to rate recovery			143		32		(135)		(29)
Associated offsetting commodity contracts			(129)		(27)		129		27
Associated offsetting cash collateral			(11)		―		―		―
Commodity contracts subject to rate recovery			36		76		(36)		(20)
Associated offsetting commodity contracts			(3)		(1)		3		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			79		110		(40)		(139)
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	93	$	110	$	(40)	$	(139)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(31)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery			32		76		(32)		(20)
Associated offsetting commodity contracts			―		(1)		―		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			32		75		(25)		(37)
Additional cash collateral for commodity contracts
subject to rate recovery			12		―		―		―
Total(4)		$	44	$	75	$	(25)	$	(37)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		$	4	$	―	$	(4)	$	―
Associated offsetting commodity contracts			(3)		―		3		―
Net amounts presented on the balance sheet			1		―		(1)		―
Additional cash collateral for commodity contracts
subject to rate recovery			2		―		―		―
Total		$	3	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and in Other Comprehensive Income (Loss) (OCI) and Accumulated Other Comprehensive Income (Loss) (AOCI) for the three months and nine months ended September 30 were

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

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

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

For Sempra Energy Consolidated, we expect that losses of $20 million, which are net of income tax benefit, that are currently recorded in AOCI (including $13 million in noncontrolling interests, substantially all of which is related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

SoCalGas expects that negligible losses, which are net of income tax benefit, currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.

For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at September 30, 2015 is approximately 13 years and 4 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum term of hedged interest rate variability is 20 years, and is related to debt at Sempra Renewables’ equity method investees.

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

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

CONTINGENT FEATURES

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

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

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

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

Notes to Consolidated Financial Statements [Abstract]

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
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+ Details

FAIR VALUE MEASUREMENTS

3 Months Ended

Sep. 30, 2015

Fair Value Measurements

NOTE 8. FAIR VALUE MEASUREMENTS

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

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 under “Financial Statement Presentation.”

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014 in the tables below include the following:

Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We may also manage foreign exchange rate exposures using derivatives. We primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below under “Level 3 Information.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates.

Investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).

There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented, nor any changes in valuation techniques used in recurring fair value measurements.

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

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

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

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

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

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

Level 3 Information

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

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

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

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-priced electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (CAISO), an objective source. Annual auction prices are published once a year, typically in the middle of November, and remain in effect for the following calendar year. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. From January 1, 2015 to December 31, 2015, the auction prices range from $(16) per MWh to $8 per MWh at a given location, and from January 1, 2014 to December 31, 2014, the auction prices ranged from $(6) per MWh to $12 per MWh at a given location. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7.

Long-term electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs that range from $24.15 per MWh to $60.01 per MWh. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively.

Realized gains and losses associated with CRRs and long-term electricity positions are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2015 and December 31, 2014:

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

		December 31, 2014
		Carrying		Fair value
		amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)(2)		$	12,347	$	―	$	12,782	$	917	$	13,699
Preferred stock of subsidiary			20		―		23		―		23
SDG&E:
Total long-term debt(2)(3)		$	4,461	$	―	$	4,563	$	425	$	4,988
SoCalGas:
Total long-term debt(4)		$	1,913	$	―	$	2,124	$	―	$	2,124
Preferred stock			22		―		25		―		25
(1)	Before reductions for unamortized discount (net of premium) of $21 million at both September 30, 2015 and December 31, 2014, and excluding build-to-suit and capital lease obligations of $375 million and $310 million at September 30, 2015 and December 31, 2014, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(2)	Level 3 instruments include $317 million and $325 million at September 30, 2015 and December 31, 2014, respectively, related to Otay Mesa VIE.
(3)	Before reductions for unamortized discount of $10 million and $11 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $231 million and $234 million at September 30, 2015 and December 31, 2014, respectively.
(4)	Before reductions for unamortized discount of $7 million and $8 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $2 million and $1 million at September 30, 2015 and December 31, 2014, respectively.

We base the fair value of certain long-term debt and preferred stock on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).

We provide the fair values for the securities held in the nuclear decommissioning trust funds related to SONGS in Note 9 below.

Notes to Consolidated Financial Statements [Abstract]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

NUCLEAR PLANT

3 Months Ended

Sep. 30, 2015

Nuclear Plant

NOTE 9. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

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

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

SONGS Outage and Retirement

Background

As part of the Steam Generator Replacement Project (SGRP), the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. In March 2012, in response to the shutdown of SONGS, the NRC issued a Confirmatory Action Letter (CAL) which, among other things, outlined the requirements for Edison to meet before the NRC would approve a restart of either of the Units.

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

The replacement steam generators were designed and provided by Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking damages as well. SDG&E is participating in the arbitration as a claimant and respondent. We discuss these proceedings in Note 11.

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

SONGS OII

In November 2012, in response to the outage, the CPUC issued the SONGS OII, pursuant to California Public Utilities’ Code Section 455.5, which applies to cost recovery issues resulting from long-term outages of operating assets. The SONGS OII consolidated most SONGS outage-related issues into a single proceeding. The SONGS OII, among other things, designated all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 as subject to refund to customers, pending the outcome of all phases of the proceeding. The SONGS OII proceeding was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA).

Entry Into Settlement Agreement

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

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

As approved by the CPUC, the Amended Settlement Agreement constitutes a complete and final resolution of the SONGS OII and related CPUC proceedings regarding the SGRP at SONGS and the related outage and subsequent shutdown of SONGS. This resolution also required the compliance filing referenced below under “Accounting and Financial Impacts.” The Amended Settlement Agreement does not affect on-going or future proceedings before the NRC, or litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries as described below) or proceedings addressing decommissioning activities and costs.

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

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

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

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

Accounting and Financial Impacts

Through September 30, 2015, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $127 million, including a reduction in the after-tax loss of $13 million recorded in the first quarter of 2015 based on the CPUC’s approval in March 2015 of SDG&E’s compliance filing and establishment of the SONGS settlement revenue requirement.

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

The regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $272 million ($42 million current and $230 million long-term) at September 30, 2015 and is recorded on the Condensed Consolidated Balance Sheets in Other Current Assets and Regulatory Assets Noncurrent, respectively, at Sempra Energy, and in Regulatory Assets Current and Other Regulatory Assets Noncurrent, respectively, at SDG&E.

Settlement with Nuclear Electric Insurance Limited (NEIL)

As we discuss in Note 11, NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E’s share of which is approximately $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, the recovery will be allocated 95 percent to SDG&E’s customers, through ERRA, and 5 percent to SDG&E, after reimbursement of the costs incurred in pursuing the claims. SDG&E will record the recoveries from NEIL during the fourth quarter of 2015.

NRC Proceedings

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

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

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

Nuclear Decommissioning and Funding

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

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work will be done when Units 2 and 3 are decommissioned. At September 30, 2015, the fair value of SDG&E’s NDT assets was $1.1 billion. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In February 2014, SDG&E filed a request with the CPUC for such authorization for costs incurred in 2013. In April 2015, SDG&E withdrew its pending request and filed a new request based on updated decommissioning cost information, seeking authorization to access trust funds for up to $55 million in decommissioning costs incurred in 2013. The CPUC authorized the request in July 2015. In August 2015, SDG&E withdrew $37 million of the authorized amount, $34 million of which will be funded to customers through the ERRA balancing account. Another $3 million of the amount withdrawn was used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $18 million of the CPUC authorization is expected to be withdrawn pending satisfactory clarification by the Internal Revenue Service (IRS) that certain spent fuel costs and other costs are eligible decommissioning costs, payable from qualified nuclear decommissioning trusts. We are uncertain as to when such clarification will be provided.

In October 2015, SDG&E filed a request with the CPUC seeking authorization to access trust funds for $36 million for SONGS Units 2 and 3 decommissioning costs incurred in 2014. If the Commission approves the request, SDG&E intends to withdraw $23 million, which will be funded to customers through the ERRA balancing account or used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $13 million will be withdrawn pending satisfactory clarification by the IRS, as discussed above.

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

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

Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT:

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

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

SALES OF SECURITIES
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Proceeds from sales(1)		$	210	$	148	$	431	$	498
Gross realized gains			18		5		24		9
Gross realized losses			(6)		(3)		(13)		(8)
(1)	Excludes securities that are held to maturity.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

We provide additional information about SONGS in Note 11.

CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

Sempra Utilities' Regulatory Matters

NOTE 10. CALIFORNIA UTILITIES' REGULATORY MATTERS

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

JOINT MATTERS

CPUC General Rate Case (GRC)

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

The California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements. In February 2015, the CPUC issued a scoping memo setting the schedule for the proceeding, including the issuance of a proposed decision by the end of 2015. In March 2015, the California Utilities revised their requests to make various updates and reflect the impact of the Tax Increase Prevention Act signed into law in December 2014. At SoCalGas, this resulted in a reduction of $10 million compared to its original request, or a total revenue requirement in 2016 of $2.342 billion. This is an increase of $246 million or 12 percent over 2015, excluding the impact of the 2015 revenue requirement increase discussed below under “SoCalGas Matters — Increase to CPUC-Authorized Annual Revenue Requirement.” At SDG&E, the March 2015 revised request resulted in a reduction of $6 million compared to its original request, or a total revenue requirement in 2016 of $1.905 billion. This is an increase of $111 million or 6 percent over 2015. This increase includes an adjustment of $16 million to the comparable 2015 estimated revenue requirement since the November 2014 filings.

In September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a reduction of $133 million compared to its original request, or a total revenue requirement in 2016 of $2.219 billion. This is an increase of $122 million or 6 percent over 2015. For SDG&E, the settlement proposes a reduction of $100 million compared to its original request (as revised), or a total revenue requirement in 2016 of $1.811 billion. This is an increase of $17 million, or one percent over 2015. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. The California Utilities also filed a separate agreement, reached with ORA, proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018.

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

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

Natural Gas Pipeline Operations Safety Assessments

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

approved the utilities’ model for implementing PSEP;
approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in the regulatory accounts authorized by the CPUC;
approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and
established the criteria to determine the amounts that would not be eligible for cost recovery, including:

certain costs incurred or to be incurred searching for pipeline test records,
the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and
any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of September 30, 2015, SDG&E and SoCalGas have recorded PSEP costs of $7 million and $153 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with the TCAP decision, SDG&E and SoCalGas are authorized to file an application with the CPUC for recovery of such costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ending December 31, 2015. SoCalGas and SDG&E currently expect to file such applications no later than the second quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e., a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017).

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

In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. In June 2015, SDG&E and SoCalGas agreed to remove certain projects from the filing and defer their review to future proceedings and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. In August 2015, the ORA, TURN and the Southern California Generation Coalition (SCGC) served testimony to the CPUC that recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. In August 2015, the California Utilities also provided testimony to the CPUC, contesting the proposed disallowances. We expect a decision on this application in the first half of 2016.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN alleged that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, the ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record in the proceeding open to admit additional evidence on the limited issue of pressure testing of pipelines installed between January 1, 1956 and July 1, 1961. As part of this review, the CPUC will allow parties to submit additional evidence relevant to this narrow issue to ensure a complete record, with no additional discovery allowed. The ORA and TURN filed their responses on May 1, 2015. In October 2015, the CPUC issued a proposed decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipeline. At September 30, 2015, SoCalGas and SDG&E estimate amounts related to these costs to be approximately $5 million and $3 million, respectively.

Southern Gas System Reliability Project

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

Pipeline Safety & Reliability Project

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

Utility Incentive Mechanisms

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

Natural Gas Procurement

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

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

Energy Efficiency Programs

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

SDG&E MATTERS

SONGS

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

2007 Wildfire Cost Recovery

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to Federal Energy Regulatory Commission (FERC)-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). In a prior decision, the CPUC granted SDG&E authority to record its costs associated with the October 2007 wildfires in the WEMA and to seek rate recovery subject to a reasonableness review of the costs. SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period.

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

Power Procurement and Resource Planning

Cleveland National Forest Transmission Projects

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

Sycamore-Peñasquitos Transmission Project

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

South Orange County Reliability Enhancement

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

Electric Vehicle Charging Program

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

Distribution Resource Plan

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

Sunrise Powerlink Electric Transmission Line

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

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

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

SOCALGAS MATTERS

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

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

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

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

Increase to CPUC-Authorized Annual Revenue Requirement

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

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

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

Commitments and Contingencies

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

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

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.”

A September 2008 staff report issued by the CPUC’s Consumer Protection and Safety Division, now known as the Safety and Enforcement Division, reached substantially the same conclusions as the Cal Fire reports, but also contended that the power lines involved in the Witch and Rice fires and the lashing wire involved in the Guejito fire were not properly designed, constructed and maintained. In April 2010, proceedings initiated by the CPUC to determine if any of its rules were violated were settled with SDG&E’s payment of $14.75 million.

Numerous parties sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. They asserted various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved almost all of these lawsuits. One case remains subject to a damages-only trial, where the value of any compensatory damages resulting from the fires will be determined. Two appeals are pending after judgment in the trial court.

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

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

SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, at September 30, 2015, Sempra Energy and SDG&E have recorded assets of $362 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $359 million related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid and reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties. On September 25, 2015, SDG&E filed an application with the CPUC seeking authority to recover these costs, as we discuss in Note 10.

Recovery of the regulatory assets related to the wildfire reserves will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recovery in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at September 30, 2015, the resulting after-tax charge against earnings would have been up to approximately $213 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations and cash flows.

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

Smart Meters Patent Infringement Lawsuit

In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma, alleging that SDG&E’s recently installed smart meters infringed certain patents. The meters were purchased from a third party vendor that has agreed to defend and indemnify SDG&E. The lawsuit seeks injunctive relief and recovery of unspecified amounts of damages.

Lawsuit Against Mitsubishi Heavy Industries, Ltd.

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

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in a wind farm project and its purchase of renewable energy credits from that project. SDG&E’s contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement are subject to the satisfaction of certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement and not make the investment. In December 2013, SDG&E received a closing notice from the project developer indicating that all such conditions had been met. SDG&E responded to the closing notice asserting that the contractual conditions had not been satisfied. On December 19, 2013, SDG&E filed a complaint against the project developer in San Diego Superior Court, asking that the court determine that SDG&E is entitled to terminate both the investment contract and the power purchase agreement due to the project developer’s failure to satisfy certain conditions. The project developer filed a separate complaint against SDG&E in Montana state court asking that court to determine that SDG&E breached the investment contract and the power purchase agreement, and asking for several categories of relief, including requiring SDG&E to invest in the project, requiring SDG&E to continue performing under the power purchase agreement, and payment of damages.

On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer is disputing SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims. On July 18, 2014, the Montana Supreme Court determined that the parties’ contractual agreement to resolve any disputes in San Diego was mandatory, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial in January 2016.

Concluded Matter

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

SoCalGas

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp. and Pfizer, Inc., are defendants in seven Los Angeles County Superior Court lawsuits filed beginning in April 2011 seeking recovery of unspecified amounts of damages, including punitive damages, as a result of plaintiffs’ exposure to PCBs (polychlorinated biphenyls). The lawsuits allege plaintiffs were exposed to PCBs not only through the food chain and other various sources but from PCB-contaminated natural gas pipelines owned and operated by SoCalGas. This contamination allegedly caused plaintiffs to develop cancer and other serious illnesses. Plaintiffs assert various bases for recovery, including negligence and products liability. SoCalGas has settled five of the seven lawsuits for an amount that is not significant.

Sempra Mexico

Permit Challenges and Property Disputes

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

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

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

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

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

Sempra Natural Gas

Since April 2012, a total of 13 lawsuits have been filed against Mobile Gas in Mobile County Circuit Court alleging that in the first half of 2008 Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Six of the lawsuits have been settled. The remaining seven lawsuits, which include more than 1,000 individual plaintiffs, allege nuisance, fraud and negligence causes of action, and seek unspecified compensatory and punitive damages. An initial trial involving approximately ten plaintiffs is scheduled for January 2016.

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

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities LLP (RBS Sempra Commodities), a limited liability partnership in the process of being liquidated. The Royal Bank of Scotland plc (RBS), our partner in the joint venture, was notified by the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigating value-added tax (VAT) refund claims made by various businesses in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactions by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued a protective assessment of £86 million for the VAT paid in connection with these transactions. In October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tier Tribunal. As a condition of the appeal, RBS was required to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax. In June 2015, liquidators for three companies that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly filed a claim in the High Court of Justice against RBS and RBS Sempra Commodities alleging that RBS Sempra Commodities’ and RBS SEE’s participation in transactions involving the sale and purchase of carbon credits resulted in the companies’ incurring VAT liability they were unable to pay. In October 2015, the liquidators’ counsel filed an amended claim adding seven additional trading companies to the claim and asserting damages of £156 million for all 10 companies. Additionally, the claimants dropped RBS Sempra Commodities LLP as a defendant, adding the successor to RBS SEE and JP Morgan, Mercuria Energy Europe Trading Limited (Mercuria), in its stead. JP Morgan has notified us that Mercuria has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from us. Our remaining balance in RBS Sempra Commodities is accounted for under the equity method. The investment balance of $71 million at September 30, 2015 reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters. We discuss RBS Sempra Commodities further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

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

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

CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first nine months of 2015 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

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

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

LNG Purchase Agreement

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

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

Purchased-Power Contracts

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

Operating Leases

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

Capital Leases – Power Purchase Agreements

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

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

Construction and Development Projects

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

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

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

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

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

OTHER COMMITMENTS

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

GUARANTEES

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

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’s contribution could be up to $50.93 million. This amount is subject to an annual maximum of $7.6 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through Nuclear Electric Insurance Limited (NEIL). The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $9.7 million of retrospective premiums based on overall member claims. See Note 9 under “Settlement with NEIL” for discussion of an agreement between the SONGS co-owners and NEIL to settle all claims under the NEIL policies associated with the SONGS outage.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

U.S. DEPARTMENT OF ENERGY (DOE) NUCLEAR FUEL DISPOSAL

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

In October 2015, the California Coastal Commission approved Edison’s application for the proposed expansion of an Independent Spent Fuel Storage Installation (ISFSI) at SONGS. The ISFSI is proposed to be installed beginning in 2016, fully loaded with spent fuel by 2020, and operated until 2049, when it is assumed that the Federal Department of Energy will have taken custody of all the SONGS spent fuel. The facility would then be decommissioned, and the site restored.

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

SEGMENT INFORMATION

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

Segment Information

NOTE 12. 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 transmission pipelines and propane and ethane systems, a natural gas distribution utility, electric generation facilities (including wind), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.
Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Minnesota, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.
Sempra Natural Gas develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States. Sempra Natural Gas also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015, as we discuss in Note 3.

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

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

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

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

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

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

Recent Investment Activity (Tables) [Abstract]

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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+ Details

SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Sep. 30, 2015
Significant Accounting Policies
New Accounting Standards Policy	NOTE 2. NEW ACCOUNTING STANDARDS We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures. SEMPRA ENERGY, SDG&E AND SOCALGAS Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09) and ASU 2015-14, “Revenue from Contracts with Customers: Deferral of the Effective Date” (ASU 2015-14): ASU 2014-09 provides accounting guidance for revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. ASU 2015-14 defers the effective date of ASU 2014-09 by one year for all entities and permits early adoption on a limited basis. For public entities, ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We have not yet selected the year in which we will adopt the standard or our transition method, nor have we determined the effect of the standard on our ongoing financial reporting. ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) and ASU 2015-15, “Interest - Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (ASU 2015-15): ASU 2015-03 provides guidance on the financial statement presentation of debt issuance costs and requires an entity to present debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related long-term debt liability. This guidance must be applied using a full retrospective approach for all periods presented in the period of adoption. We will adopt ASU 2015-03 for our annual reporting period ending December 31, 2015, and the adoption will not affect our results of operations or cash flows. Deferred debt issuance costs that are the subject of ASU 2015-03 are included in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets and total $78 million, $32 million, and $18 million at September 30, 2015, respectively, and $72 million, $33 million, and $15 million at December 31, 2014, respectively. ASU 2015-15 clarifies ASU 2015-03 to provide additional guidance related to line-of-credit arrangements and states that the Securities and Exchange Commission staff would not object to an entity continuing to defer and present costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. We will adopt ASU 2015-15 for our annual reporting period ending December 31, 2015 and will continue to include deferred costs related to our line-of-credit arrangements that are the subject of ASU 2015-15 in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets. ASU 2015-16, “Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments” (ASU 2015-16): ASU 2015-16 eliminates the requirement that acquirers in a business combination account for measurement-period adjustments retrospectively. Instead, the acquirers will recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts that would have been recorded in previous periods if the accounting had been completed at the acquisition date. We will adopt ASU 2015-16 for our annual reporting period ending December 31, 2015. Any subsequent measurement-period adjustments to the purchase price allocation related to the acquisition of Gasoductos de Chihuahua that we discuss in Note 3 will occur after the adoption of ASU 2015-16 and will be recognized in the period in which the adjustments are determined.
Consolidation Variable Interest Entity Policy	VARIABLE INTEREST ENTITIES (VIE) We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess the purpose and design of the VIE; the nature of the VIE’s risks and the risks we absorb; the power to direct activities that most significantly impact the economic performance of the VIE; and the obligation to absorb losses or right to receive benefits that could be significant to the VIE.
Noncontrolling Interest Policy	Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as noncontrolling interests. As a result, noncontrolling interests are reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to noncontrolling interests are separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income or loss attributable to noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss).
Earnings Per Share Policy	Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation of dilutive common stock equivalents excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. Our performance-based RSUs include awards that vest at the end of three-year (for awards granted in 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices (Total Shareholder Return or TSR RSUs) or based on the compound annual growth rate of Sempra Energy’s EPS (EPS RSUs). The comparative market indices for the TSR RSUs are the Standard & Poor’s (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our EPS RSU targets. TSR RSUs represent the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of Sempra Energy common stock if performance targets are met. EPS RSUs represent the right to receive from zero to 2.0 shares of Sempra Energy common stock if performance targets are met. If performance falls between the targets specified for each performance metric, we calculate the payout using linear interpolation. Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate. Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our TSR RSUs and EPS RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method.
Interim period effective tax rate policy	Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted are factored into the forecasted effective tax rate, and their impact is recognized proportionately over the year. The forecasted items, anticipated on a full year basis, may include, among others: utility self-developed software expenditures repairs to certain utility plant assets renewable energy income tax credits deferred income tax benefits related to renewable energy projects exclusions from taxable income of the equity portion of AFUDC depreciation on a certain portion of utility plant assets U.S. tax on repatriation of current year earnings from non-U.S. subsidiaries Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, remeasurement of deferred tax asset valuation allowances, Mexican currency translation and inflation adjustments, and deferred income tax benefit associated with the impairment of a book investment) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense. For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment: repairs expenditures related to a certain portion of utility plant assets the equity portion of AFUDC a portion of the cost of removal of utility plant assets utility self-developed software expenditures depreciation on a certain portion of utility plant assets state income taxes The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico and Sempra Natural Gas has similar flow-through treatment.
Fair Value Measurement Policy	Recurring Fair Value Measures The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels. The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 under “Financial Statement Presentation.” The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014 in the tables below include the following: Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2). We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We may also manage foreign exchange rate exposures using derivatives. We primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below under “Level 3 Information.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates. Investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-priced electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (CAISO), an objective source. Annual auction prices are published once a year, typically in the middle of November, and remain in effect for the following calendar year. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. 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. Long-term electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs that range from $24.15 per MWh to $60.01 per MWh. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. Realized gains and losses associated with CRRs and long-term electricity positions are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. Fair Value of Financial Instruments The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. We base the fair value of certain long-term debt and preferred stock on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).
Derivatives Policy	We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not presented below. We record all derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows. In certain cases, we apply the normal purchase or sale exception to derivative accounting and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below. HEDGE ACCOUNTING We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that a given future revenue or expense item may vary, and other criteria. We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria. ENERGY DERIVATIVES Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows: The California Utilities use energy derivatives, both natural gas and electricity, for the benefit of customers, with the objective of managing price risk and basis risks, and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas. SDG&E is allocated and may purchase congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations. Sempra Mexico and Sempra Natural Gas may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (LNG), natural gas transportation, power generation, and Sempra Natural Gas’ storage. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations. From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel. In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales. INTEREST RATE DERIVATIVES We are exposed to interest rates primarily as a result of our current and expected use of financing. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries. Interest rate derivatives are generally accounted for as hedges, and although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to energy derivatives. Separately, Otay Mesa VIE has entered into interest rate swap agreements to moderate its exposure to interest rate changes. FOREIGN CURRENCY DERIVATIVES We are exposed to exchange rate movements at our Mexican subsidiaries, which have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts. We may also utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. In addition, Sempra South American Utilities may utilize foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk.
Legal Costs Policy	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.
Segment Policy	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.

RECENT INVESTMENT ACTIVITY (Tables)

3 Months Ended

Sep. 30, 2015

Schedule of Business Acquisition Table

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

OTHER FINANCIAL DATA (Tables)

3 Months Ended

Sep. 30, 2015

Other Financial Data (Tables) [Abstract]

Net Periodic Benefit Cost Table

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2015		2014		2015		2014
Service cost	$	27	$	23	$	5	$	6
Interest cost		38		39		10		13
Expected return on assets		(42)		(42)		(17)		(15)
Amortization of:
Prior service cost (credit)		3		3		(1)		(2)
Actuarial loss		9		3		―		―
Settlements and special termination benefits		4		5		―		5
Regulatory adjustment		(27)		6		4		5
Total net periodic benefit cost	$	12	$	37	$	1	$	12

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

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

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

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

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

Contributions to Benefit Plans Table

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy
	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2015:
Pension plans	$	27	$	2	$	1
Other postretirement benefit plans		3		―		―
Total expected contributions in 2015:
Pension plans	$	36	$	3	$	7
Other postretirement benefit plans		11		7		1

Earnings Per Share Computations Table

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

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

Earnings per share:
Basic		$	1.00	$	1.41	$	3.95	$	3.52
Diluted			0.99		1.39		3.91		3.45
(1)	Includes fully vested restricted stock units of 504 and 222 held in our Deferred Compensation Plan for the three months ended September 30, 2015 and 2014, respectively, and 486 and 209 for the nine months ended September 30, 2015 and 2014, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

Capitalized Financing Costs Table

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

Changes in Components of Accumulated Comprehensive Income Table

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
				Pension and other
				postretirement benefits
		Foreign								Total
		currency		Unamortized		Unamortized				accumulated other
		translation		net actuarial		prior service		Financial		comprehensive
		adjustments		gain (loss)		cost		instruments		income (loss)
		Three months ended September 30, 2015 and 2014
2015:
Balance as of June 30, 2015		$	(427)	$	(81)	$	(2)	$	(86)	$	(596)
Other comprehensive loss before
reclassifications			(92)		―		―		(79)		(171)
Amounts reclassified from accumulated other
comprehensive income			―		5		―		1		6
Net other comprehensive (loss) income			(92)		5		―		(78)		(165)
Balance as of September 30, 2015		$	(519)	$	(76)	$	(2)	$	(164)	$	(761)
2014:
Balance as of June 30, 2014		$	(170)	$	(65)	$	―	$	(38)	$	(273)
Other comprehensive loss before
reclassifications			(100)		―		―		(2)		(102)
Amounts reclassified from accumulated other
comprehensive income (loss)			―		5		―		(1)		4
Net other comprehensive (loss) income			(100)		5		―		(3)		(98)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)

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

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

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

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

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

Reclassifications out of AOCI Table

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

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

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

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

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

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

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

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

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

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

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

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

Shareholders' Equity and Noncontrolling Interests Table

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
			Sempra Energy		Non-
			shareholders’		controlling		Total
			equity		interests(1)		equity
Balance at December 31, 2014		$	11,326	$	774	$	12,100
Comprehensive income			717		56		773
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			39		―		39
Common stock dividends declared			(520)		―		(520)
Issuance of common stock			82		―		82
Repurchases of common stock			(74)		―		(74)
Tax benefit related to share-based compensation			56		―		56
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(60)		(60)
Balance at September 30, 2015		$	11,625	$	771	$	12,396
Balance at December 31, 2013		$	11,008	$	842	$	11,850
Comprehensive income			722		66		788
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			35		―		35
Common stock dividends declared			(486)		―		(486)
Issuance of common stock			71		―		71
Repurchases of common stock			(38)		―		(38)
Tax benefit related to share-based compensation			22		―		22
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(85)		(85)
Balance at September 30, 2014		$	11,333	$	824	$	12,157
(1)	Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under "Other Noncontrolling Interests."

SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST ― SDG&E
(Dollars in millions)
		SDG&E		Non-
		shareholder’s		controlling		Total
		equity		interest		equity
Balance at December 31, 2014	$	4,932	$	60	$	4,992
Comprehensive income		443		20		463
Common stock dividends declared		(150)		―		(150)
Distributions to noncontrolling interest		―		(16)		(16)
Balance at September 30, 2015	$	5,225	$	64	$	5,289
Balance at December 31, 2013	$	4,628	$	91	$	4,719
Comprehensive income		381		23		404
Distributions to noncontrolling interest		―		(37)		(37)
Balance at September 30, 2014	$	5,009	$	77	$	5,086

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

Amounts Due To and From Affiliates at SDG&E and SoCalGas Table

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


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

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


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


Income taxes due from Sempra Energy(1)		$	29	$	9
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.
(2)	Net receivable includes a loan to Sempra Energy of $250 million at September 30, 2015 at an interest rate of 0.10 percent.

Revenues From Unconsolidated Affiliates at SDG&E and SoCalGas Table

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

Other Income and Expense Table

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

Income Tax Expense and Effective Income Tax Rates Table

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

Variable Interest Entity Table

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

Ownership Interests Held By Others Table

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

Inventory Table

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

Afiliate Loans Table

DUE FROM UNCONSOLIDATED AFFILIATES(1)
(Dollars in millions)
			September 30, 2015		December 31, 2014
Sempra South American Utilities:
Eletrans S.A.:
4% Note(2)		$	65	$	41
Sempra Mexico:
Affiliate of joint venture with Petróleos Mexicanos(3):
Note due November 13, 2017(4)(5)			3		44
Note due November 14, 2018(4)			41		40
Note due November 14, 2018(4)			34		33
Note due November 14, 2018(4)			8		8
Energía Sierra Juárez:
Note due June 15, 2018(6)			24		22
Other(7)			3		38
Total		$	178	$	226
(1)	Amounts include principal balances plus accumulated interest outstanding.
(2)	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A., an affiliate of Chilquinta Energía.
(3)	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company).
(4)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.69 percent at September 30, 2015), to finance the Los Ramones Norte pipeline project.
(5)	In May 2015, $41 million was paid with proceeds from project financing at the affiliate.
(6)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.57 percent at September 30, 2015), to finance the first phase of the Energía Sierra Juárez wind project.
(7)	Amounts represent accounts receivable from various Sempra Renewables and Sempra Mexico joint venture investments.

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Sep. 30, 2015

Derivative Financial Instruments (Tables) [Abstract]

Commodity Derivative Volumes Table

NET ENERGY DERIVATIVE VOLUMES

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

Energy-Related Businesses:
Sempra Natural Gas – natural gas		39 million MMBtu	29 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

Notional Amounts of Interest Rate Derivatives Table

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

Derivative Instruments on the Condensed Consolidated Balance Sheets Table

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2015
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	7	$	―	$	(16)	$	(159)
Commodity contracts not subject to rate recovery			6		―		―		―
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			―		―		(3)		―
Commodity contracts not subject to rate recovery			166		31		(147)		(18)
Associated offsetting commodity contracts			(137)		(18)		137		18
Associated offsetting cash collateral			―		―		3		―
Commodity contracts subject to rate recovery			7		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			48		99		(59)		(195)
Additional cash collateral for commodity contracts
not subject to rate recovery			3		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			15		―		―		―
Total(4)		$	66	$	99	$	(59)	$	(195)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(15)	$	(29)
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery			―		―		(1)		―
Associated offsetting cash collateral			―		―		1		―
Commodity contracts subject to rate recovery			6		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			5		86		(48)		(65)
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	20	$	86	$	(48)	$	(65)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery		$	―	$	―	$	(2)	$	―
Associated offsetting cash collateral			―		―		2		―
Commodity contracts subject to rate recovery			1		―		―		―
Net amounts presented on the balance sheet			1		―		―		―
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			1		―		―		―
Total		$	3	$	―	$	―	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2014
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	10	$	3	$	(17)	$	(109)
Commodity contracts not subject to rate recovery			25		―		―		―
Derivatives not designated as hedging instruments:
Interest rate instruments			8		27		(7)		(22)
Commodity contracts not subject to rate recovery			143		32		(135)		(29)
Associated offsetting commodity contracts			(129)		(27)		129		27
Associated offsetting cash collateral			(11)		―		―		―
Commodity contracts subject to rate recovery			36		76		(36)		(20)
Associated offsetting commodity contracts			(3)		(1)		3		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			79		110		(40)		(139)
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	93	$	110	$	(40)	$	(139)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(31)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery			32		76		(32)		(20)
Associated offsetting commodity contracts			―		(1)		―		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			32		75		(25)		(37)
Additional cash collateral for commodity contracts
subject to rate recovery			12		―		―		―
Total(4)		$	44	$	75	$	(25)	$	(37)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		$	4	$	―	$	(4)	$	―
Associated offsetting commodity contracts			(3)		―		3		―
Net amounts presented on the balance sheet			1		―		(1)		―
Additional cash collateral for commodity contracts
subject to rate recovery			2		―		―		―
Total		$	3	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

Fair Value Hedge Impact on the Condensed Consolidated Statements of Operations Table

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

Cash Flow Hedge Impact on the Condensed Consolidated Statements of Operations Table

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

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

Undesignated Derivative Impact on the Condensed Consolidated Statements of Operations Table

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

FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Sep. 30, 2015

Fair Value Measurements (Tables) [Abstract]

Recurring Fair Value Measures Table

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

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

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

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

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

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

Recurring Fair Value Measures Level 3 Rollforward Table

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

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

Fair Value of Financial Instruments Table

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

		December 31, 2014
		Carrying		Fair value
		amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)(2)		$	12,347	$	―	$	12,782	$	917	$	13,699
Preferred stock of subsidiary			20		―		23		―		23
SDG&E:
Total long-term debt(2)(3)		$	4,461	$	―	$	4,563	$	425	$	4,988
SoCalGas:
Total long-term debt(4)		$	1,913	$	―	$	2,124	$	―	$	2,124
Preferred stock			22		―		25		―		25
(1)	Before reductions for unamortized discount (net of premium) of $21 million at both September 30, 2015 and December 31, 2014, and excluding build-to-suit and capital lease obligations of $375 million and $310 million at September 30, 2015 and December 31, 2014, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(2)	Level 3 instruments include $317 million and $325 million at September 30, 2015 and December 31, 2014, respectively, related to Otay Mesa VIE.
(3)	Before reductions for unamortized discount of $10 million and $11 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $231 million and $234 million at September 30, 2015 and December 31, 2014, respectively.
(4)	Before reductions for unamortized discount of $7 million and $8 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $2 million and $1 million at September 30, 2015 and December 31, 2014, respectively.

NUCLEAR PLANT (Tables)

3 Months Ended

Sep. 30, 2015

Schedule of Nuclear Decommissioning Trusts Investments [Abstract]

Schedule of Nuclear Decommissioning Trusts Investments

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

Schedule of Sales of Securities By Nuclear Decommissioning Trusts [Abstract]

Schedule of Sales of Securities By Nuclear Decommissioning Trusts

SALES OF SECURITIES
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Proceeds from sales(1)		$	210	$	148	$	431	$	498
Gross realized gains			18		5		24		9
Gross realized losses			(6)		(3)		(13)		(8)
(1)	Excludes securities that are held to maturity.

Regulatory Matters (Tables) [Abstract]

Tabular disclosure of available-for-sale securities which includes, but is not limited to, changes in the cost basis and fair value, fair value and gross unrealized gain (loss), fair values by type of security, contractual maturity and classification, amortized cost basis, contracts to acquire securities to be accounted for as available-for-sale, debt maturities, transfers to trading, change in net unrealized holding gain (loss) net of tax, continuous unrealized loss position fair value, aggregate losses qualitative disclosures, other than temporary impairment (OTTI) losses or other disclosures related to available for sale securities.

+ References + Details

CALIFORNIA UTILITIES' REGULATORY MATTERS (Tables)

3 Months Ended

Sep. 30, 2015

Schedule of Sunrise Powerlink Total Project Cost

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

COMMITMENTS AND CONTINGENCIES (Tables)

3 Months Ended

Sep. 30, 2015

Commitments And Contingencies (Tables) [Abstract]

Schedule Of Capital Leases, Future Minimum Payments Due

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

SEGMENT INFORMATION (Tables)

3 Months Ended

Sep. 30, 2015

Segment Information (Tables) [Abstract]

Segment Information Table

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

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

GENERAL (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
GENERAL (Details) - USD ($) $ in Millions	Sep. 30, 2015	Sep. 30, 2015
Seasonality [Line Items]
Higher (Lower) Earnings Due To Seasonality	$ (113)	$ (48)
Higher (Lower) Utility Revenue Due to Seasonality	(158)	(67)
Southern California Gas Company [Member]
Seasonality [Line Items]
Higher (Lower) Earnings Due To Seasonality	(113)	(48)
Higher (Lower) Utility Revenue Due to Seasonality	$ (158)	$ (67)

New Accounting Policy (details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
New Accounting Policy [Line Items]
Deferred Finance Costs Net	$ 78	$ 72
San Diego Gas and Electric Company [Member]
New Accounting Policy [Line Items]
Deferred Finance Costs Net	32	33
Southern California Gas Company [Member]
New Accounting Policy [Line Items]
Deferred Finance Costs Net	$ 18	$ 15

RECENT INVESTMENT ACTIVITY (Details) - USD ($)			9 Months Ended
RECENT INVESTMENT ACTIVITY (Details) - USD ($)	Jul. 16, 2014	Mar. 13, 2014	Sep. 30, 2014
Deconsolidation of business [Line Items]
Proceeds from sale, net of transaction costs			$ 94,000,000
Cash			(4,000,000)
Other current assets			(11,000,000)
Property, plant and equipment, net			(384,000,000)
Other assets			(27,000,000)
Accounts payable and accrued expenses			92,000,000
Due to affiliate			39,000,000
Long-term debt including current portion			179,000,000
Other liabilities			10,000,000
Accumulated other comprehensive income			(7,000,000)
Gain on sale of equity interests			(46,000,000)
Equity method investments upon deconsolidation			$ (65,000,000)
Energia Sierra Juarez [Member]
Deconsolidation of business [Line Items]
Proceeds from sale, net of transaction costs	$ 26,000,000
Cash	(2,000,000)
Other current assets	(11,000,000)
Property, plant and equipment, net	(137,000,000)
Other assets	(16,000,000)
Accounts payable and accrued expenses	10,000,000
Due to affiliate	39,000,000
Long-term debt including current portion	82,000,000
Other liabilities	7,000,000
Accumulated other comprehensive income	(5,000,000)
Gain on sale of equity interests	(19,000,000)
Equity method investments upon deconsolidation	(26,000,000)
Proceeds from sale, net of cash sold	$ 24,000,000
Mesquite Power [Member]
Deconsolidation of business [Line Items]
Gain on sale of equity interests		$ 61,000,000
Proceeds from sale		347,000,000
Gain on sale, after tax		36,000,000
Copper Mountain Solar 3 [Member]
Deconsolidation of business [Line Items]
Proceeds from sale, net of transaction costs		68,000,000
Cash		(2,000,000)
Other current assets		0
Property, plant and equipment, net		(247,000,000)
Other assets		(11,000,000)
Accounts payable and accrued expenses		82,000,000
Due to affiliate		0
Long-term debt including current portion		97,000,000
Other liabilities		3,000,000
Accumulated other comprehensive income		(2,000,000)
Gain on sale of equity interests		(27,000,000)
Equity method investments upon deconsolidation		(39,000,000)
Proceeds from sale, net of cash sold		66,000,000
Gain on sale, after tax		$ 16,000,000

RECENT INVESTMENT ACTIVITY 2 (Details) - USD ($) $ in Millions		9 Months Ended
	Jul. 16, 2014	Sep. 30, 2015	Mar. 13, 2014
Energia Sierra Juarez wind project [Member]
Business Acquisition [Line Items]
Equity Method Investment Ownership Percentage	50.00%
Deconsolidation Gain Or Loss Amount After Tax	$ 14
Gain attributable to remeasurement, after tax	$ 7
Copper Mountain Solar 3 [Member]
Business Acquisition [Line Items]
Equity Method Investment Ownership Percentage			50.00%
California Solar Partnership [Member]
Business Acquisition [Line Items]
Equity Method Investment Ownership Percentage		50.00%
Equity Investment In Solar Projects		$ 109
Additional Equity investment in solar projects		12
Black Oak Getty Wind [Member]
Business Acquisition [Line Items]
Total business acquisition costs		$ 8
Ownership Percentage in consolidated entity		100.00%

RECENT INVESTMENT ACTIVITY 3 (Details) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2015	Jul. 31, 2015
IEnova [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Percentage in consolidated entity	25.00%
Business Acquisition Purchase Price Allocation Equity Method Investment	$ 1,325
Net Debt Not Assumed By Investee	170
Ownership percentage before acquisition		50.00%
Business Acquisition Percentage Of Voting Interests Acquired		100.00%
Equity Method Investment Ownership Percentage		50.00%
Expected Maximum Amount of Bank Commitments	$ 1,000
PEMEX [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Percentage in consolidated entity	50.00%

INVESTMENTS IN UNCONSOLIDATED ENTITIES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investments in Joint Ventures, capitalized interest	$ 18	$ 6	$ 52	$ 22
Sempra Renewables [Member]
Schedule of Equity Method Investments [Line Items]
Payments To Acquire Equity Method Investments			18	$ 76
Cameron LNG [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments in Joint Ventures, capitalized interest			36
Payments To Acquire Equity Method Investments			10
Sempra Natural Gas [Member]
Schedule of Equity Method Investments [Line Items]
Payments To Acquire Equity Method Investments			$ 113

OTHER FINANCIAL DATA - VARIABLE INTEREST ENTITIES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Operating expenses
Cost Of Electric Fuel And Purchased Power From Utilities	$ 666	$ 680	$ 1,645	$ 1,761
Other operation and maintenance	701	726	2,072	2,131
Depreciation and amortization	315	292	925	866
Other income (expense), net	12	29	88	118
Interest expense	143	144	416	418
Net income	282	383	1,060	941
Earnings attributable to noncontrolling interest	(34)	(35)	(79)	(76)
Earnings attributable to common shares	248	348	980	864
Otay Mesa VIE [Member]
Operating expenses
Cost Of Electric Fuel And Purchased Power From Utilities	(27)	(27)	(66)	(67)
Other operation and maintenance	3	3	13	13
Depreciation and amortization	7	7	19	21
Operating Expenses	(17)	(17)	(34)	(33)
Utility operating income	17	17	34	33
Interest expense	(5)	(5)	(14)	(13)
Net income	12	12	20	20
Earnings attributable to noncontrolling interest	(12)	(12)	(20)	(20)
Earnings attributable to common shares	0	$ 0	0	$ 0
Equity of variable interest entity	64		64		$ 60
Secured debt of variable interest entity	317		317
Cameron LNG Holdings [Member]
Schedule Of Equity Method And Other Investments [Line Items]
Equity Method And Other Investments	$ 956		$ 956		$ 1,007

OTHER FINANCIAL DATA - GOODWILL (Details)
$ in Millions

Sep. 30, 2015

USD ($)

Goodwill [Line Items]

Goodwill, Beginning Balance

$ 931

^[1]

Goodwill, Ending Balance

$ 847

[1]	Derived from audited financial statements.

OTHER FINANCIAL DATA - PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Benefits
Net Periodic Benefit Cost
Service cost	$ 27	$ 23	$ 86	$ 75
Interest cost	38	39	116	121
Expected return on assets	(42)	(42)	(130)	(128)
Amortization of prior service cost	3	3	8	8
Amortization of actuarial loss	9	3	28	13
Settlement	4	5	4	14
Regulatory adjustment	(27)	6	(86)	(18)
Total net periodic benefit cost	12	37	26	85
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			27
Expected contributions to benefit plans			36
Pension Benefits \| San Diego Gas and Electric Company [Member]
Net Periodic Benefit Cost
Service cost	6	8	22	23
Interest cost	9	10	29	32
Expected return on assets	(14)	(13)	(41)	(41)
Amortization of prior service cost			1	1
Amortization of actuarial loss	3	1	7	3
Settlement	0	0	0	2
Regulatory adjustment	(3)	6	(15)	7
Total net periodic benefit cost	1	12	3	27
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			2
Expected contributions to benefit plans			3
Pension Benefits \| Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	17	13	55	45
Interest cost	25	24	74	75
Expected return on assets	(25)	(26)	(79)	(78)
Amortization of prior service cost	2	2	6	6
Amortization of actuarial loss	5	1	16	5
Settlement	0	4	0	4
Regulatory adjustment	(24)	0	(71)	(25)
Total net periodic benefit cost	0	18	1	32
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			1
Expected contributions to benefit plans			7
Other Postretirement Benefits
Net Periodic Benefit Cost
Service cost	5	6	19	18
Interest cost	10	13	33	37
Expected return on assets	(17)	(15)	(51)	(47)
Amortization of prior service cost	(1)	(2)	(2)	(4)
Amortization of actuarial loss	0	0	0	0
Settlement	0	5	0	5
Regulatory adjustment	4	5	4	5
Total net periodic benefit cost	1	12	3	14
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			3
Expected contributions to benefit plans			11
Other Postretirement Benefits \| San Diego Gas and Electric Company [Member]
Net Periodic Benefit Cost
Service cost	1	2	5	5
Interest cost	2	3	6	7
Expected return on assets	(2)	(2)	(8)	(8)
Amortization of prior service cost			2	2
Amortization of actuarial loss	0	0	0	0
Settlement	0	5	0	5
Regulatory adjustment	(1)	4	(5)	1
Total net periodic benefit cost	0	12	0	12
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			0
Expected contributions to benefit plans			7
Other Postretirement Benefits \| Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	3	4	13	12
Interest cost	8	9	26	28
Expected return on assets	(14)	(12)	(42)	(38)
Amortization of prior service cost	(2)	(2)	(6)	(6)
Amortization of actuarial loss	0	0	0	0
Settlement	0	0	0	0
Regulatory adjustment	5	1	9	4
Total net periodic benefit cost	$ 0	$ 0	0	$ 0
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			0
Expected contributions to benefit plans			$ 1

OTHER FINANCIAL DATA - RABBI TRUST (Details) - USD ($)
$ in Millions

Sep. 30, 2015

Dec. 31, 2014

Rabbi Trust Disclosure [Abstract]

Rabbi Trust

$ 459

$ 512

^[1]

[1]	Derived from audited financial statements.

OTHER FINANCIAL DATA - EARNINGS PER SHARE (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Earnings Per Share Numerator [Abstract]

Earnings

$ 248

$ 348

$ 980

$ 864

Earnings Per Share Denominator [Abstract]

Weighted-average common shares outstanding for basic EPS

^[1]

248,432,000

246,137,000

248,090,000

245,703,000

Weighted-average common shares outstanding for diluted EPS

251,024,000

250,771,000

250,665,000

250,278,000

Vested RSUs included in basic WASO

504,000

222,000

486,000

209,000

Dilutive effect of stock options, restricted stock awards and restricted stock units

2,592,000

4,634,000

2,575,000

4,575,000

Earnings Per Share [Abstract]

Basic earnings per common share

$ 1

$ 1.41

$ 3.95

$ 3.52

Diluted earnings per common share

$ 0.99

$ 1.39

$ 3.91

$ 3.45

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Shares excluded from potential dilutive shares

2,001,020

844,251

2,047,656

971,943

Performance RSU minimum [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Sharebased Compensation Arrangement By Sharebased Payment Award Award Vesting Rights Percentage

0.00%

Performance RSU max prior to 2014 [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Sharebased Compensation Arrangement By Sharebased Payment Award Award Vesting Rights Percentage

150.00%

Performance RSU max in 2014 and after [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Sharebased Compensation Arrangement By Sharebased Payment Award Award Vesting Rights Percentage

200.00%

Service and Other Awards max [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Sharebased Compensation Arrangement By Sharebased Payment Award Award Vesting Rights Percentage

100.00%

Out Of The Money Stock Options [Member]

Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]

Antidilutive securities excluded from computation of earnings per share

Employee Stock Option [Member]

Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]

Antidilutive securities excluded from computation of earnings per share

Restricted Stock [Member]

Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]

Antidilutive securities excluded from computation of earnings per share

Restricted Stock Units [Member]

Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]

Antidilutive securities excluded from computation of earnings per share

[1]

OTHER FINANCIAL DATA - SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense, net of income taxes	$ 7	$ 8	$ 22	$ 22
IENova Plans [Member] [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units granted			278,538
Service-Based [Member] \| Sempra Energy Plans [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units granted			133,159
Performance-Based, Total Shareholder Return [Member] \| Sempra Energy Plans [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units granted			301,319
Performance-Based, Earnings Per Share [Member] \| Sempra Energy Plans [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units granted			76,675

OTHER FINANCIAL DATA - CAPITALIZED FINANCING COSTS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	$ 6	$ 5	$ 19	$ 15
AFUDC related to equity	26	28	84	77
Other capitalized financing costs	18	6	52	22
Total capitalized financing costs	50	39	155	114
San Diego Gas and Electric Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	3	3	10	10
AFUDC related to equity	9	8	27	26
Total capitalized financing costs	12	11	37	36
Southern California Gas Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	3	2	9	5
AFUDC related to equity	10	7	29	18
Other capitalized financing costs	1	0	1	0
Total capitalized financing costs	$ 14	$ 9	$ 39	$ 23

OTHER FINANCIAL DATA - COMPREHENSIVE INCOME AND EQUITY (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

$ 12,100

^[1]

$ 11,850

Share-based compensation expense

773

788

(520)

(486)

$ 0

(1)

Issuance of common stock

Noncontrolling Interest Increase

(74)

(38)

(60)

(85)

Ownership Interests Held By Others [Line Items]

12,396

12,157

12,396

12,157

751

$ 754

4,992

^[1]

4,719

463

404

(150)

(16)

(37)

5,289

5,086

5,289

5,086

2,781

^[1]

2,549

277

259

Preferred dividend requirements

(50)

(1)

Total Shareholders' Equity

3,007

2,807

3,007

2,807

11,326

11,008

Share-based compensation expense

717

722

(520)

(486)

(1)

Issuance of common stock

Noncontrolling Interest Increase

(74)

(38)

Total Shareholders' Equity | San Diego Gas and Electric Company [Member]

11,625

11,333

11,625

11,333

4,932

4,628

443

381

(150)

Noncontrolling Interests [Member]

5,225

5,009

5,225

5,009

774

842

Share-based compensation expense

Issuance of common stock

Noncontrolling Interest Increase

(60)

(85)

Noncontrolling Interests [Member] | San Diego Gas and Electric Company [Member]

771

824

771

824

(16)

(37)

Ownership Interests Held By Others, Bay Gas Storage Company [Member]

$ 64

$ 77

$ 64

$ 77

Ownership Interests Held By Others [Line Items]

9.10%

Ownership Interests Held By Others, Southern Gas Transmission [Member]

$ 25

$ 23

Ownership Interests Held By Others [Line Items]

49.00%

Ownership Interests Held By Others, Liberty Gas Storage [Member]

$ 1

Ownership Interests Held By Others [Line Items]

23.70%

25.00%

Ownership Interests Held By Others, Tecsur [Member]

$ 12

$ 14

Ownership Interests Held By Others [Line Items]

9.80%

Ownership Interests Held By Others, Luz Del Sur [Member]

$ 3

$ 4

Ownership Interests Held By Others [Line Items]

16.40%

Ownership Interests Held By Others, Chilquinta Energia [Member]

$ 171

$ 177

Ownership Interests Held By Others [Line Items]

Percent of ownership held by others, minimum

^[2]

23.50%

23.60%

Percent of ownership held by others, maximum

^[2]

43.40%

Ownership Interests Held By Others [Line Items]

^[2]

$ 20

$ 23

Otay Mesa VIE [Member]

100.00%

Ownership Interests Held By Others IEnova [Member]

$ 64

$ 60

Ownership Interests Held By Others [Line Items]

18.90%

Accumulated Other Comprehensive Income Loss [Line Items]

$ 455

$ 452

[1]	Derived from audited financial statements.
[2]	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages amongst these subsidiaries.

OTHER FINANCIAL DATA - COMPREHENSIVE INCOME AND EQUITY 2 (Details) - USD ($)

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

$ (596,000,000)

$ (273,000,000)

^[2]

$ (497,000,000)

^[2]

$ (228,000,000)

Other Comprehensive Income Loss Before Reclassifications Net Of Tax

^[1]

(171,000,000)

(102,000,000)

(273,000,000)

(169,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

6,000,000

4,000,000

9,000,000

26,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

(165,000,000)

(98,000,000)

(264,000,000)

(143,000,000)

^[1]

(761,000,000)

(371,000,000)

(761,000,000)

(371,000,000)

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

(12,000,000)

^[1]

(8,000,000)

^[1]

(12,000,000)

^[2]

(9,000,000)

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

1,000,000

2,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

1,000,000

2,000,000

^[1]

(12,000,000)

(7,000,000)

(12,000,000)

(7,000,000)

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

(18,000,000)

^[1]

(18,000,000)

^[1]

(18,000,000)

^[2]

(18,000,000)

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

2,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

2,000,000

^[1]

(18,000,000)

(16,000,000)

(18,000,000)

(16,000,000)

Accumulated Translation Adjustment [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(427,000,000)

(170,000,000)

(322,000,000)

(129,000,000)

Other Comprehensive Income Loss Before Reclassifications Net Of Tax

^[1]

(92,000,000)

(100,000,000)

(197,000,000)

(141,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

(92,000,000)

(100,000,000)

(197,000,000)

(141,000,000)

^[1]

(519,000,000)

(270,000,000)

(519,000,000)

(270,000,000)

Accumulated Defined Benefit Plans Adjustment Net Unamortized Gain Loss [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(81,000,000)

(65,000,000)

(83,000,000)

(73,000,000)

Other Comprehensive Income Loss Before Reclassifications Net Of Tax

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

5,000,000

7,000,000

13,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

5,000,000

7,000,000

13,000,000

^[1]

(76,000,000)

(60,000,000)

(76,000,000)

(60,000,000)

Accumulated Defined Benefit Plans Adjustment Net Unamortized Gain Loss [Member] | San Diego Gas and Electric Company [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(13,000,000)

(9,000,000)

(13,000,000)

(10,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

1,000,000

2,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

1,000,000

2,000,000

^[1]

(13,000,000)

(8,000,000)

(13,000,000)

(8,000,000)

Accumulated Defined Benefit Plans Adjustment Net Unamortized Gain Loss [Member] | Southern California Gas Company [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(5,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

2,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

2,000,000

^[1]

(5,000,000)

(3,000,000)

(5,000,000)

(3,000,000)

Accumulated Defined Benefit Plans Adjustment Net Prior Service Cost Credit [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(2,000,000)

Other Comprehensive Income Loss Before Reclassifications Net Of Tax

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

^[1]

(2,000,000)

Accumulated Defined Benefit Plans Adjustment Net Prior Service Cost Credit [Member] | San Diego Gas and Electric Company [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

1,000,000

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

^[1]

1,000,000

Accumulated Defined Benefit Plans Adjustment Net Prior Service Cost Credit [Member] | Southern California Gas Company [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

1,000,000

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

^[1]

1,000,000

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(86,000,000)

(38,000,000)

(90,000,000)

(26,000,000)

Other Comprehensive Income Loss Before Reclassifications Net Of Tax

^[1]

(79,000,000)

(2,000,000)

(76,000,000)

(28,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

1,000,000

(1,000,000)

2,000,000

13,000,000

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

(78,000,000)

(3,000,000)

(74,000,000)

(15,000,000)

^[1]

(164,000,000)

(41,000,000)

(164,000,000)

(41,000,000)

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Southern California Gas Company [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, beginning balance

^[1]

(14,000,000)

Amounts Reclassified From Accumulated Other Comprehensive Income

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, ending balance

^[1]

^[1]

$ (14,000,000)

[1]	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.
[2]	Derived from audited financial statements.

OTHER FINANCIAL DATA - COMPREHENSIVE INCOME AND EQUITY 3 (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Equity earnings, net of income tax.

$ 27

$ 7

$ 64

$ 22

(143)

(144)

(416)

(418)

Revenues - energy related businesses

268

352

762

970

270

447

1,272

1,210

(15)

(71)

(276)

(291)

Grand total reclassifications for the period, net of tax

(34)

(35)

(79)

(76)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(51)

(155)

(152)

257

234

680

616

(75)

(65)

(217)

Grand total reclassifications for the period, net of tax

(12)

(20)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(23)

(17)

(61)

(50)

(28)

142

368

367

Grand total reclassifications for the period, net of tax

(44)

(91)

(110)

Accumulated Defined Benefit Plans Adjustment [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(2)

(3)

(4)

(8)

Accumulated Defined Benefit Plans Adjustment [Member] | San Diego Gas and Electric Company [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(1)

Accumulated Defined Benefit Plans Adjustment [Member] | Southern California Gas Company [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(2)

Accumulated Defined Benefit Plans Adjustment [Member] | Amortization of Actuarial Loss [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Pension and other postretirement benefit expense

^[1]

Accumulated Defined Benefit Plans Adjustment [Member] | Amortization of Actuarial Loss [Member] | San Diego Gas and Electric Company [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Pension and other postretirement benefit expense

^[1]

Accumulated Defined Benefit Plans Adjustment [Member] | Amortization of Actuarial Loss [Member] | Southern California Gas Company [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Pension and other postretirement benefit expense

^[1]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(1)

(8)

Net of Income Tax

(3)

(10)

(8)

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | San Diego Gas and Electric Company [Member]

(1)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(3)

(9)

(8)

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Interest Rate And Foreign Exchange Instruments [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Interest Rate Instruments [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Gain on sale of equity interests and assets

(3)

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Interest Rate Instruments [Member] | San Diego Gas and Electric Company [Member]

(9)

(7)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Revenues - energy related businesses

$ (3)

$ (2)

$ (10)

$ 8

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

OTHER FINANCIAL DATA - TRANSACTIONS WITH AFFILIATES (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Transactions With Affiliates Disclosure [Line Items]

^[1]

$ 178

$ 226

Transactions With Affiliates Disclosure [Line Items]

Revenues from unconsolidated affiliates

$ 2

$ 8

Transactions With Affiliates Disclosure [Line Items]

220

Revenues from unconsolidated affiliates

$ 17

$ 51

Due to/from Sempra Energy | San Diego Gas and Electric Company [Member]

Transactions With Affiliates Disclosure [Line Items]

Income taxes due from Sempra Energy

^[2]

Due to/from Sempra Energy | Southern California Gas Company [Member]

Transactions With Affiliates Disclosure [Line Items]

220

^[3]

220

^[3]

Income taxes due from Sempra Energy

^[2]

Loan to unconsolidated affiliate, principal

250

$ 250

Subsidiary Of Common Parent S D G E [Member] | Southern California Gas Company [Member]

0.10%

Transactions With Affiliates Disclosure [Line Items]

$ 0

Subsdiary Of Common Parent So Cal Gas [Member] | San Diego Gas and Electric Company [Member]

Transactions With Affiliates Disclosure [Line Items]

Subsidiary Of Common Parent Other Affiliates [Member] | San Diego Gas and Electric Company [Member]

Transactions With Affiliates Disclosure [Line Items]

Subsidiary Of Common Parent Other Affiliates [Member] | Southern California Gas Company [Member]

Transactions With Affiliates Disclosure [Line Items]

Transactions With Affiliates Disclosure [Line Items]

$ 50

$ 0

[1]	Amounts include principal balances plus accumulated interest outstanding.
[2]	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.
[3]	Net receivable includes a loan to Sempra Energy of $250 million at September 30, 2015 at an interest rate of 0.10 percent.

OTHER FINANCIAL DATA - TRANSACTIONS WITH AFFILIATES 2 (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Joint venture with PEMEX [Member]

^[1]

$ 178

$ 226

Transactions With Affiliates Disclosure [Line Items]

PEMEX Four year loan C [Member]

4.69%

Transactions With Affiliates Disclosure [Line Items]

PEMEX Three year loan A [Member]

^[1],[2],[3]

$ 8

Transactions With Affiliates Disclosure [Line Items]

Repayment Of Notes Receivable From Related Parties

^[1],[2],[3]

^[4]

PEMEX Four year loan B [Member]

Transactions With Affiliates Disclosure [Line Items]

PEMEX Four year loan A [Member]

^[1],[2],[3]

Transactions With Affiliates Disclosure [Line Items]

ESJ joint venture [Member]

^[1],[2],[3]

Transactions With Affiliates Disclosure [Line Items]

^[1],[5]

$ 24

Transactions With Affiliates Disclosure [Line Items]

6.57%

Eletrans [Member]

^[1],[6]

$ 65

Affiliate Of Investee [Member]

4.00%

Transactions With Affiliates Disclosure [Line Items]

Due From Joint Ventures Noncurrent

^[1],[7]

$ 3

$ 38

[1]	Amounts include principal balances plus accumulated interest outstanding.
[2]	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company).
[3]	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.69 percent at September 30, 2015), to finance the Los Ramones Norte pipeline project.
[4]	In May 2015, $41 million was paid with proceeds from project financing at the affiliate.
[5]	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.57 percent at September 30, 2015), to finance the first phase of the Energía Sierra Juárez wind project.
[6]	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A., an affiliate of Chilquinta Energía.
[7]	Amounts represent accounts receivable from various Sempra Renewables and Sempra Mexico joint venture investments.

OTHER FINANCIAL DATA - OTHER INCOME (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Component of Other Income, Nonoperating [Line Items]

AFUDC related to equity

$ 26

$ 28

$ 84

$ 77

Investment gains (losses)

^[1]

(12)

(3)

(5)

Gains (losses) on interest rate and foreign exchange instruments, net

(4)

(6)

(7)

Foreign currency gain (losses)

(3)

(2)

(6)

(1)

Sale of other investments

Electrical infrastructure relocation income

^[2]

Regulatory Interest, net

^[3]

Sundry, net

118

Component of Other Income, Nonoperating [Line Items]

AFUDC related to equity

Regulatory Interest, net

^[3]

Sundry, net

(2)

(1)

(4)

(2)

Component of Other Income, Nonoperating [Line Items]

AFUDC related to equity

Sundry, net

(2)

(1)

(4)

(5)

$ 8

$ 6

$ 25

$ 13

[1]	Represents investment (losses) gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
[2]	Income at Luz del Sur associated with the relocation of electrical infrastructure.
[3]	Interest on regulatory balancing accounts.

OTHER FINANCIAL DATA - INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	$ 15	$ 71	$ 276	$ 291
Effective income tax rate	6.00%	16.00%	22.00%	24.00%
Charge To Reduce Certain Tax Regulatory Assets Attributable To Nuclear Plant				$ 17
Lower Income Tax Expense on Repatriation of Foreign Earnings	$ 14		$ 14
Louisiana Valuation Allowance Release		$ 25		25
Income Tax Reconciliation Prior Year Income Taxes	12		19
Income Tax Reconciliation Other Adjustments	9		22
San Diego Gas and Electric Company [Member]
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	$ 75	$ 65	$ 217	$ 217
Effective income tax rate	29.00%	28.00%	32.00%	35.00%
Charge To Reduce Certain Tax Regulatory Assets Attributable To Nuclear Plant				$ 17
Income Tax Reconciliation Prior Year Income Taxes			$ 9
Southern California Gas Company [Member]
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	$ (20)	$ 44	$ 91	$ 110
Effective income tax rate	71.00%	31.00%	25.00%	30.00%
Income Tax Reconciliation Prior Year Income Taxes	$ 11		$ 14

OTHER FINANCIAL DATA - INVENTORY (Details) - USD ($)
$ in Millions

Sep. 30, 2015

Dec. 31, 2014

$ 261

$ 246

144

136

416

396

^[1]

S D G E Segment [Member]

So Cal Gas Segment [Member]

162

155

Sempra South American Utilities Segment [Member]

192

181

Sempra Mexico Segment [Member]

Sempra Natural Gas Segment [Member]

Sempra Renewables Segment [Member]

100

Schedule Of Commodity Derivative Volumes [Line Items]

$ 2

[1]	Derived from audited financial statements.

DEBT AND CREDIT FACILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Line Of Credit Facility, Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 4,100
Committed lines of credit, remaining borrowing capacity	$ 3,300
Weighted average interest rate on total short-term debt outstanding	0.66%	0.70%
Line Of Credit Facility, Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 1,067
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, capacity for issuance of letters of credit	$ 635
Committed lines of credit, outstanding borrowings	0
Amended And Restated Line Of Credit Facility Maximum Borrowing Capacity	1,000
Amended And Restated Credit Facility Letters Of Credit Capacity	400
Line Of Credit Facility, Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 2,189
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Outstanding commercial paper supported by committed lines of credit	$ 734
Amended And Restated Line Of Credit Facility Maximum Borrowing Capacity	2,210
Line Of Credit Facility, S D G E [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	$ 614
Outstanding commercial paper supported by committed lines of credit	$ 44
Weighted average interest rate on total short-term debt outstanding	0.15%	0.27%
Amended And Restated Line Of Credit Facility Maximum Borrowing Capacity	$ 750
Line Of Credit Facility, So Cal Gas [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	$ 658
Outstanding letters of credit	0
Weighted average interest rate on total short-term debt outstanding		0.25%
Amended And Restated Line Of Credit Facility Maximum Borrowing Capacity	750
Line Of Credit Facility, California Utilities Combined [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	877
Committed lines of credit, capacity for issuance of letters of credit	300
Amended And Restated Line Of Credit Facility Maximum Borrowing Capacity	1,000
Amended And Restated Credit Facility Letters Of Credit Capacity	250
Line Of Credit Facility, South American Utilities And Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	945
Committed lines of credit, remaining borrowing capacity	485
Line Of Credit Facility, IEnova Santander [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility Maximum Borrowing Capacity Prior Limit	200
Line Of Credit Facility, IEnova Sumitomo [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility Maximum Borrowing Capacity Prior Limit	100
Line Of Credit Facility Sempra Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	400
Committed lines of credit, remaining borrowing capacity	110
Committed lines of credit, outstanding borrowings	290
Retired Debt Instrument, Face Amount	$ 210

DEBT AND CREDIT FACILITIES 2 (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Debt Instrument [Line Items]
Redemption of industrial development bonds		$ 79	$ 0
Sempra Natural Gas [Member]
Debt Instrument [Line Items]
Redemption of industrial development bonds		79
Planned Early Redemption Of Long Term Debt Instruments	$ 55	55
Other Long Term Debt, Variable Rate Due 2017 [Member] \| San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 140	$ 140
Debt Instrument, Interest Rate At Period End	0.53%	0.53%
Debt Instrument, Variable Base Rate	0.20%	0.20%
Other Long Term Debt, Fixed Rate Due 2020 [Member] \| Sempra Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 500	$ 500
Debt Instrument, Interest Rate, Stated Percentage	2.40%	2.40%
Other Long Term Debt, Amortizing Fixed Rate Due 2022 [Member] \| San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 250	$ 250
Debt Instrument, Interest Rate, Stated Percentage	1.914%	1.914%
Other Long Term Debt, Fixed Rate Due 2025 [Member] \| Southern California Gas Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 350	$ 350
Debt Instrument, Interest Rate, Stated Percentage	3.20%	3.20%
Other Long Term Debt, Fixed Rate Due June 2018 [Member] \| Southern California Gas Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 250	$ 250
Debt Instrument, Interest Rate, Stated Percentage	1.55%	1.55%
Other Long Term Debt, Fixed Rate Due June 2018 [Member] \| South America Utilities [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 22	$ 22
Debt Instrument, Interest Rate, Stated Percentage	5.18%	5.18%
Other Long Term Debt Fixed Rate Due May 2018 [Member] \| South America Utilities [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 13	$ 13
Debt Instrument, Interest Rate, Stated Percentage	5.18%	5.18%
Other Long Term Debt Fixed Rate Due between 2021 and 2027 [Member] \| San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument Interest Rate Stated Percentage Rate Range Minimum	4.90%
Debt Instrument Interest Rate Stated Percentage Rate Range Maximum	5.50%
Planned Early Redemption Of Long Term Debt Instruments	$ 169	$ 169
Other Long Term Debt Fixed Rate Due February 2018 [Member] \| South America Utilities [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 9	$ 9
Debt Instrument, Interest Rate, Stated Percentage	6.70%	6.70%
Other Long Term Debt Fixed Rate Due September 2026 [Member] \| South America Utilities [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 25	$ 25
Debt Instrument, Interest Rate, Stated Percentage	8.75%	8.75%

DERIVATIVE FINANCIAL INSTRUMENTS (Details)

Sep. 30, 2015

Dec. 31, 2014

S D G E Segment [Member]

Commodity derivative volumes, natural gas (in millions of million British thermal units)

^[1]

Commodity derivative volumes, congestion revenue rights (in millions of megawatt hours)

^[2]

Commodity derivative volumes, electric power (in millions of megawatt hours)

^[2]

So Cal Gas Segment [Member]

Schedule Of Commodity Derivative Volumes [Line Items]

Commodity derivative volumes, natural gas (in millions of million British thermal units)

^[1]

Sempra Natural Gas Segment [Member]

Schedule Of Commodity Derivative Volumes [Line Items]

Commodity derivative volumes, natural gas (in millions of million British thermal units)

^[1]

[1]	Million British thermal units
[2]	Megawatt hours

DERIVATIVE FINANCIAL INSTRUMENTS 2 (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Cash Flow Hedges
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Derivative Liability Notional Amount	$ 389	$ 399
Cash Flow Hedges \| Maximum [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Maturities of interest rate derivatives	2028	2028
Cash Flow Hedges \| Minimum [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Maturities of interest rate derivatives	2015	2015
Fair Value Hedges
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Derivative Liability Notional Amount	$ 300	$ 300
Fair Value Hedges \| Maximum [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Maturities of interest rate derivatives	2016	2016
San Diego Gas and Electric Company [Member] \| Cash Flow Hedges
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Derivative Liability Notional Amount	$ 317	$ 325
San Diego Gas and Electric Company [Member] \| Cash Flow Hedges \| Maximum [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Maturities of interest rate derivatives	2019	2019
San Diego Gas and Electric Company [Member] \| Cash Flow Hedges \| Minimum [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Maturities of interest rate derivatives	2015	2015

DERIVATIVE FINANCIAL INSTRUMENTS 3 (Details) - USD ($)
$ in Millions

Sep. 30, 2015

Dec. 31, 2014

OtherCurrentAssetsMember

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

^[1],[2]

$ 7

$ 10

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[1]

^[1]

Associated offsetting commodity contracts not subject to rate recovery

^[1]

166

143

^[1]

(137)

(129)

Associated cash collateral commodity contracts not subject to rate recovery

^[1]

(11)

Associated cash collateral commodity contracts subject to rate recovery

^[1]

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

(1)

(3)

Additional margin posted for commodity contracts not subject to rate recovery

^[1]

^[1]

Additional margin posted for commodity contracts subject to rate recovery

^[1]

OtherCurrentAssetsMember | San Diego Gas and Electric Company [Member]

^[1],[3]

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[1],[2]

Associated cash collateral commodity contracts not subject to rate recovery

^[1]

^[1]

Associated cash collateral commodity contracts subject to rate recovery

^[1]

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

(1)

Additional margin posted for commodity contracts not subject to rate recovery

^[1]

^[1]

Additional margin posted for commodity contracts subject to rate recovery

^[1]

OtherCurrentAssetsMember | Southern California Gas Company [Member]

^[1],[3]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

Associated cash collateral commodity contracts not subject to rate recovery

^[1]

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

^[1]

(3)

Additional margin posted for commodity contracts not subject to rate recovery

^[1]

^[1]

Additional margin posted for commodity contracts subject to rate recovery

^[1]

OtherNoncurrentAssetsMember

^[1]

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

^[2]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

Associated offsetting commodity contracts not subject to rate recovery

(18)

(27)

Associated cash collateral commodity contracts not subject to rate recovery

Associated cash collateral commodity contracts subject to rate recovery

Associated offsetting commodity contracts subject to rate recovery

(1)

Additional margin posted for commodity contracts not subject to rate recovery

110

Additional margin posted for commodity contracts subject to rate recovery

OtherNoncurrentAssetsMember | San Diego Gas and Electric Company [Member]

^[3]

110

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[2]

Associated cash collateral commodity contracts not subject to rate recovery

Associated cash collateral commodity contracts subject to rate recovery

Associated offsetting commodity contracts subject to rate recovery

(1)

Additional margin posted for commodity contracts not subject to rate recovery

Additional margin posted for commodity contracts subject to rate recovery

OtherNoncurrentAssetsMember | Southern California Gas Company [Member]

^[3]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

Associated cash collateral commodity contracts not subject to rate recovery

Associated offsetting commodity contracts subject to rate recovery

Additional margin posted for commodity contracts not subject to rate recovery

Additional margin posted for commodity contracts subject to rate recovery

OtherCurrentLiabilitiesMember

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

^[2],[4]

(16)

(17)

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[4]

^[4]

(3)

(7)

Associated offsetting commodity contracts not subject to rate recovery

^[4]

(147)

(135)

^[4]

137

129

Associated cash collateral commodity contracts not subject to rate recovery

^[4]

Associated cash collateral commodity contracts subject to rate recovery

^[4]

(59)

(36)

^[4]

Associated offsetting commodity contracts subject to rate recovery

^[4]

Additional margin posted for commodity contracts not subject to rate recovery

^[4]

(59)

(40)

^[4]

Additional margin posted for commodity contracts subject to rate recovery

^[4]

OtherCurrentLiabilitiesMember | San Diego Gas and Electric Company [Member]

^[3],[4]

(59)

(40)

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[2],[4]

(15)

(16)

Associated cash collateral commodity contracts not subject to rate recovery

^[4]

(1)

^[4]

Associated cash collateral commodity contracts subject to rate recovery

^[4]

(59)

(32)

^[4]

Associated offsetting commodity contracts subject to rate recovery

^[4]

Additional margin posted for commodity contracts not subject to rate recovery

^[4]

(48)

(25)

^[4]

Additional margin posted for commodity contracts subject to rate recovery

^[4]

OtherCurrentLiabilitiesMember | Southern California Gas Company [Member]

^[3],[4]

(48)

(25)

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

Associated cash collateral commodity contracts not subject to rate recovery

^[4]

(2)

^[4]

Associated offsetting commodity contracts subject to rate recovery

^[4]

(4)

^[4]

Additional margin posted for commodity contracts not subject to rate recovery

^[4]

(1)

^[4]

Additional margin posted for commodity contracts subject to rate recovery

^[4]

OtherNoncurrentLiabilitiesMember

^[4]

(1)

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

^[2]

(159)

(109)

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

(22)

Associated offsetting commodity contracts not subject to rate recovery

(18)

(29)

Associated cash collateral commodity contracts not subject to rate recovery

Associated cash collateral commodity contracts subject to rate recovery

(65)

(20)

Associated offsetting commodity contracts subject to rate recovery

Additional margin posted for commodity contracts not subject to rate recovery

(195)

(139)

Additional margin posted for commodity contracts subject to rate recovery

OtherNoncurrentLiabilitiesMember | San Diego Gas and Electric Company [Member]

^[3]

(195)

(139)

Derivative Instruments in Hedges, at Fair Value, Net [Abstract]

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

^[2]

(29)

(31)

Associated cash collateral commodity contracts not subject to rate recovery

Associated cash collateral commodity contracts subject to rate recovery

(65)

(20)

Associated offsetting commodity contracts subject to rate recovery

Additional margin posted for commodity contracts not subject to rate recovery

(65)

(37)

Additional margin posted for commodity contracts subject to rate recovery

OtherNoncurrentLiabilitiesMember | Southern California Gas Company [Member]

^[3]

(65)

(37)

Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]

Associated cash collateral commodity contracts not subject to rate recovery

Associated offsetting commodity contracts subject to rate recovery

Additional margin posted for commodity contracts not subject to rate recovery

Additional margin posted for commodity contracts subject to rate recovery

Derivative Instruments, Gain (Loss) [Line Items]

$ 0

[1]	Included in Current Assets: Other for SoCalGas.
[2]	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
[3]	Normal purchase contracts previously measured at fair value are excluded.
[4]	Included in Current Liabilities: Other for SoCalGas.

DERIVATIVE FINANCIAL INSTRUMENTS 4 (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Gain (loss) on derivative recognized in earnings

$ 20

$ 19

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) on derivative recognized in earnings

Cash Flow Hedges

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

^[1]

$ (5)

$ (3)

(13)

(29)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

^[1]

(138)

(3)

(139)

(51)

Cash Flow Hedge Ineffectiveness

Cash Flow Hedges | Interest Expense | Interest Rate And Foreign Exchange Instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

^[1],[2]

(5)

(8)

(14)

(17)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

^[1],[2]

(10)

(5)

(22)

(15)

Cash Flow Hedges | Interest Expense | Interest Rate Instruments | San Diego Gas and Electric Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

^[1],[2]

(3)

(9)

(8)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

^[1],[2]

(4)

(9)

(5)

Cash Flow Hedges | Equity Earnings Before Income Tax [Member] | Interest Rate Instruments

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(3)

(2)

(9)

(7)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

(134)

(4)

(123)

(34)

Cash Flow Hedges | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(8)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

(5)

Cash Flow Hedges | Gain on sale of equity interest [Member] | Interest Rate Instruments

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)

Fair Value Hedges

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

^[3]

Fair Value Hedges | Interest Expense | Interest Rate Instruments

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

Fair Value Hedge Ineffectiveness

Fair Value Hedges | Other Income, Net | Interest Rate Instruments

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(1)

(2)

Undesignated Derivatives

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(15)

(4)

(78)

Undesignated Derivatives | San Diego Gas and Electric Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(28)

(1)

(101)

Undesignated Derivatives | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(1)

Undesignated Derivatives | Other Income, Net | Interest Rate And Foreign Exchange Instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(4)

(6)

(7)

(6)

Undesignated Derivatives | Equity Earnings Net Of Income Tax [Member] | Interest Rate And Foreign Exchange Instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(3)

(2)

(4)

Undesignated Derivatives | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

Undesignated Derivatives | Cost of Natural Gas, Electric Fuel and Purchased Power [Member] | Commodity Contracts Not Subject To Rate Recovery

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

Undesignated Derivatives | Cost of Electric Fuel and Purchased Power [Member] | Commodity Contracts Subject To Rate Recovery [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(27)

(1)

(100)

Undesignated Derivatives | Cost of Electric Fuel and Purchased Power [Member] | Commodity Contracts Subject To Rate Recovery [Member] | San Diego Gas and Electric Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(27)

(1)

(100)

Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(2)

(1)

Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery | San Diego Gas and Electric Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(1)

Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

(1)

Undesignated Derivatives | Cost of Natural Gas [Member] | Commodity Contracts Subject To Rate Recovery [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

Undesignated Derivatives | Cost of Natural Gas [Member] | Commodity Contracts Subject To Rate Recovery [Member] | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from AOCI into earnings (effective portion)

$ 0

$ 1

$ 2

[1]	There were negligible losses from ineffectiveness related to these hedges in 2015 and 2014.
[2]	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
[3]	There was no hedge ineffectiveness on these swaps in either the three months or nine months ended September 30, 2015 and negligible gains and $9 million of gains from hedge ineffectiveness in the three months and nine months ended September 30, 2014, respectively. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and are recorded in Other Income, Net.

DERIVATIVE FINANCIAL INSTRUMENTS 5 (Details) $ in Millions	9 Months Ended
DERIVATIVE FINANCIAL INSTRUMENTS 5 (Details) $ in Millions	Sep. 30, 2015 USD ($)
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 20
Maximum Length Time Hedged In Cash Flow Hedge	13 years
Joint Venture Maximum Length Of Time Hedged In Cash Flow Hedge	20 years
Cash Flow Hedge Gain (Loss) To Be Reclassified Within Twelve Months For Noncontrolling Interest	$ 13
San Diego Gas and Electric Company [Member]
Cash Flow Hedge Disclosure [Line Items]
Maximum Length Time Hedged In Cash Flow Hedge	4 years
Cash Flow Hedge Gain (Loss) To Be Reclassified Within Twelve Months For Noncontrolling Interest	$ 13
Southern California Gas Company [Member]
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 0

DERIVATIVE FINANCIAL INSTRUMENTS 6 (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	$ 8	$ 9
Additional Collateral Aggregate Fair Value	8
San Diego Gas and Electric Company [Member]
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	5	$ 2
Additional Collateral Aggregate Fair Value	$ 5

FAIR VALUE MEASUREMENTS 3 (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
FAIR VALUE MEASUREMENTS 3 (Details) - USD ($) $ in Millions	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 42	$ 85	$ 107	$ 99
Realized and unrealized gains (losses)	(49)	3	(103)	9
Allocated transmission instruments	0	9	1	10
Settlements	43	(10)	31	(31)
Balance at end of period	36	87	36	87
Change in unrealized gains (losses) relating to instruments still held at period end	(8)	0	(54)	0
CRR Auction Rate Per MWh, Minimum	(16)	(6)	(16)	(6)
CRR Auction Rate Per MWh, Maximum	$ 8	$ 12	$ 8	$ 12

FAIR VALUE MEASUREMENTS 4 (Details) - USD ($)
$ in Millions

Sep. 30, 2015

Dec. 31, 2014

Carrying Amount

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[1],[2]

$ 13,341

$ 12,347

Preferred Stock Of Subsidiaries Fair Value Disclosure

Debt Instrument Unamortized Discount

Capital Lease Obligations

375

310

Debt Instrument Carrying Amount

317

325

Carrying Amount | San Diego Gas and Electric Company [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[2],[3]

4,557

4,461

Debt Instrument Unamortized Discount

Capital Lease Obligations

231

234

Debt Instrument Carrying Amount

317

325

Carrying Amount | Southern California Gas Company [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[4]

2,512

1,913

Preferred Stock Of Subsidiaries Fair Value Disclosure

Debt Instrument Unamortized Discount

Capital Lease Obligations

Fair Value

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[1],[2]

14,396

13,699

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Level 1

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[1],[2]

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Level 2

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[1],[2]

13,693

12,782

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Level 3

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[1],[2]

703

917

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | San Diego Gas and Electric Company [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[2],[3]

4,969

4,988

Fair Value | San Diego Gas and Electric Company [Member] | Level 1

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[2],[3]

Fair Value | San Diego Gas and Electric Company [Member] | Level 2

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[2],[3]

4,652

4,563

Fair Value | San Diego Gas and Electric Company [Member] | Level 3

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[2],[3]

317

425

Fair Value | Southern California Gas Company [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[4]

2,658

2,124

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Southern California Gas Company [Member] | Level 1

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[4]

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Southern California Gas Company [Member] | Level 2

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[4]

2,658

2,124

Preferred Stock Of Subsidiaries Fair Value Disclosure

Fair Value | Southern California Gas Company [Member] | Level 3

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments, Total long-term debt

^[4]

Preferred Stock Of Subsidiaries Fair Value Disclosure

$ 0

[1]	Before reductions for unamortized discount (net of premium) of $21 million at both September 30, 2015 and December 31, 2014, and excluding build-to-suit and capital lease obligations of $375 million and $310 million at September 30, 2015 and December 31, 2014, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
[2]	Level 3 instruments include $317 million and $325 million at September 30, 2015 and December 31, 2014, respectively, related to Otay Mesa VIE.
[3]	Before reductions for unamortized discount of $10 million and $11 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $231 million and $234 million at September 30, 2015 and December 31, 2014, respectively.
[4]	Before reductions for unamortized discount of $7 million and $8 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $2 million and $1 million at September 30, 2015 and December 31, 2014, respectively.

NUCLEAR PLANT 1 (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Mar. 31, 2014

Jun. 30, 2013

Sep. 30, 2015

Sep. 30, 2014

Nuclear Plant Investment [Line Items]

Plant closure (adjustment) loss

$ 0

$ (21)

$ (13)

Loss (Adjustment) From Plant Closure, After Tax

$ (13)

$ 12

$ 9

Loss from plant closure, after-tax (cumulative)

127

$ 119

Charge To Reduce Certain Tax Regulatory Assets Attributable To Nuclear Plant

Regulatory Asset, Current, Nuclear Plant Closure

Regulatory Asset, Nuclear Plant Closure

272

Regulatory Asset, Noncurrent, Nuclear Plant Closure

230

Other Commitments [Line Items]

Five-year research funding commitment, annual amount

Nuclear Plant Decommissioning And Funding [Line Items]

Nuclear Plant Decommissioning And Funding [Line Items]

1,060

1,131

^[1]

1,060

Year 2013 [Member]

Authorized Annuial Recovery Amount, Nuclear Decommissioning Trust Funding

Withdrawal From Nuclear Decommissioning Trust Funds

Amount funded to customers through Energy Resource Recovery Account

Amount To Refund Regulatory Assets

Year 2014 [Member]

Nuclear Plant Decommissioning And Funding [Line Items]

Withdrawal From Nuclear Decommissioning Trust Funds

Requested Annuial Recovery Amount, Nuclear Decommissioning Trust Funding

Nuclear Plant Entire Ownership [Member]

Nuclear Plant Settlement [Line Items]

Nuclear Plant, Insurance Recovery

400

Nuclear Plant SDGE Ownership [Member]

Nuclear Plant Settlement [Line Items]

Nuclear Plant, Insurance Recovery

$ 80

Recovery Allocation Percentage

5.00%

Customers [Member]

Nuclear Plant Settlement [Line Items]

Recovery Allocation Percentage

95.00%

Nuclear Plant, SDGE [Member]

Nuclear Plant [Line Items]

Nuclear Plant, Ownership Percentage

20.00%

Nuclear Plant Investment [Line Items]

Utility plant closure (adjustment) loss

$ 0

$ (21)

(13)

Loss (Adjustment) From Plant Closure, After Tax

$ (13)

$ 9

Loss from plant closure, after-tax (cumulative)

127

$ 119

Charge To Reduce Certain Tax Regulatory Assets Attributable To Nuclear Plant

$ 17

Regulatory Asset, Current, Nuclear Plant Closure

Regulatory Asset, Nuclear Plant Closure

272

Regulatory Asset, Noncurrent, Nuclear Plant Closure

230

Other Commitments [Line Items]

Five-year research funding commitment, annual amount

Nuclear Plant Decommissioning And Funding [Line Items]

San Diego Gas and Electric Company [Member] | Year 2013 [Member]

1,060

$ 1,131

^[1]

1,060

Nuclear Plant Decommissioning And Funding [Line Items]

Authorized Annuial Recovery Amount, Nuclear Decommissioning Trust Funding

Withdrawal From Nuclear Decommissioning Trust Funds

Amount funded to customers through Energy Resource Recovery Account

Amount To Refund Regulatory Assets

San Diego Gas and Electric Company [Member] | Year 2014 [Member]

Nuclear Plant Decommissioning And Funding [Line Items]

Withdrawal From Nuclear Decommissioning Trust Funds

Requested Annuial Recovery Amount, Nuclear Decommissioning Trust Funding

$ 36

[1]	Derived from audited financial statements.

SONGS NDT 1 (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Schedule of Available-for-sale Securities [Line Items]

$ 681

$ 675

397

466

(18)

(10)

Schedule of Available-for-sale Securities [Line Items]

1,060

1,131

Proceeds from sales

^[1]

210

$ 148

431

$ 498

Gross realized gains

Gross realized losses

(6)

$ (3)

(13)

$ (8)

Total Debt Securities

451

430

(12)

(6)

Debt Securities Issued By The U.S. Treasury And Other U.S. Government Corporations And Agencies

454

445

Schedule of Available-for-sale Securities [Line Items]

^[2]

103

^[2]

^[2]

Schedule of Available-for-sale Securities [Line Items]

^[2]

109

Municipal Bonds

147

^[3]

147

^[3]

121

^[3]

^[3]

Schedule of Available-for-sale Securities [Line Items]

154

^[3]

154

^[3]

129

Other Debt Securities

214

^[3]

214

^[3]

206

^[3]

(12)

^[3]

(6)

Schedule of Available-for-sale Securities [Line Items]

205

^[3]

205

^[3]

207

Equity Securities

212

215

382

444

(6)

(4)

Cash And Cash Equivalents

588

655

Schedule of Available-for-sale Securities [Line Items]

CapitalLeasesFutureMinimumPaymentsDueCurrent

$ 18

$ 31

[1]	Excludes securities that are held to maturity.
[2]	Maturity dates are 2016-2065.
[3]	Maturity dates are 2015-2115.

CALIFORNIA UTILITIES' REGULATORY MATTERS - SCHEDULE OF REGULATORY AMOUNTS 1 (Details) - Year 2016 [Member] - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
General Rate Case, Revenue Requirement, Revised Request	$ 1,905				$ 1,811
General Rate Case, Revenue Requirement Increase, Original Request	133
General Rate Case, Revenue Requirement Increase, Revised Request	$ 111				(100)
General Rate Case, Revenue Requirement Percentage Increase, Revised Request	6.00%
General Rate Case, Revised Request Decrease Compared To Original	$ 6
General Rate Case, Proposed Revenue Requirement Increase (Decrease)					$ 17
General Rate Case, Proposed Revenue Requirement Percentage Increase (Decrease)		4.30%	3.50%	3.50%	1.00%
General Rate Case, Adjustment To Decrease Estimated Revenue Requirement	16
General Rate Case, Proposed Rate Base Adjustment					$ 93
General Rate Case, Tax Memorandum Accounts Balance	34
Southern California Gas Company [Member]
General Rate Case [Line Items]
General Rate Case, Revenue Requirement, Revised Request	2,342				2,219
General Rate Case, Revenue Requirement Increase, Original Request	256
General Rate Case, Revenue Requirement Increase, Revised Request	$ 246				(133)
General Rate Case, Revenue Requirement Percentage Increase, Revised Request	12.00%
General Rate Case, Revised Request Decrease Compared To Original	$ 10
General Rate Case, Proposed Revenue Requirement Increase (Decrease)					$ 122
General Rate Case, Proposed Revenue Requirement Percentage Increase (Decrease)		4.30%	3.50%	3.50%	6.00%
General Rate Case, Proposed Rate Base Adjustment					$ 92
General Rate Case, Tax Memorandum Accounts Balance	$ 46

CALIFORNIA UTILITIES' REGULATORY MATTERS - SCHEDULE OF REGULATORY AMOUNTS 2 (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Mar. 31, 2015
San Diego Gas and Electric Company [Member] \| Years 2006 To 2008 [Member]
Utility Incentive Awards [Line Items]
Requested Energy Efficiency Awards	$ 16,200
Southern California Gas Company [Member] \| Year 2014 [Member]
Utility Incentive Awards [Line Items]
Recognized Gas Cost Incentive Mechanism Award		$ 13,700
Southern California Gas Company [Member] \| Year 2015 [Member]
Utility Incentive Awards [Line Items]
Requested Gas Cost Incentive Mechanism Award	7,250
Southern California Gas Company [Member] \| Years 2006 To 2008 [Member]
Utility Incentive Awards [Line Items]
Requested Energy Efficiency Awards	$ 17,300

CALIFORNIA UTILITIES' REGULATORY MATTERS - SCHEDULE OF UTILITY PROJECTS 1 (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jun. 11, 2014 USD ($)
Pipeline Safety Enhancement Plan [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Pipeline Safety Plan Regulatory Account	$ 7,000		$ 100
Recovery Requested, PSEP Costs	100
Pipeline Safety Enhancement Plan [Member] \| Southern California Gas Company [Member]
Schedule Of Utility Projects [Line Items]
Disallowed Costs Impact On Earnings After Tax		$ 5,000
Pipeline Safety Plan Regulatory Account	153,000		$ 46,000
Recovery Requested, PSEP Costs	26,800
ORA Recommended Disallowance	11,100
ORA Recommended Recovery	15,700
TURN Recommended Disallowance	2,300
TURN Recommended Recovery	24,500
South Orange County Reliability Enhancement [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost, Lower Range	350,000
Estimated Project Cost, Upper Range	400,000
Cleveland National Forest Transmissions Projects [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost, Lower Range	400,000
Estimated Project Cost, Upper Range	450,000
Southern Gas System Member [Member] \| Utility Subsidiaries [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost, Lower Range	800,000
Estimated Project Cost, Upper Range	850,000
Sycamore Penasquitos Transmission Project [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost, Lower Range	120,000
Estimated Project Cost, Upper Range	$ 150,000
Public Utilities Requested Basis Point Return On Equity Adder, Denied	100
Public Utilities Abandoned Plant Cost Recovery Approved, Percentage	100.00%
Revised Estimated Project Cost, Lower Range	$ 250,000
Revised Estimated Project Cost, Upper Range	300,000
Electric Vehicle Charging [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	103,000
Portion of Estimated Project Cost To Be Capitalized	$ 59,000
Number Of Charging Stations	5,500
Pipeline Safety And Reliability Project [Member] \| Utility Subsidiaries [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	$ 600,000
Wildfire Cost Recovery [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Incurred Costs	2,400,000
Requested Recovery	379,000
Insurance Reimbursement	1,100,000
Third Party Settlement Recoveries	824,000
FERC Jurisdictional Rates	$ 80,000
Voluntary Shareholder Contribution, Percentage	10.00%
WEMA Balance	$ 42,000
Pipeline Testing/Replacing 1956 to 1961 [Member] \| San Diego Gas and Electric Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	3,000
Pipeline Testing/Replacing 1956 to 1961 [Member] \| Southern California Gas Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	$ 5,000

CALIFORNIA UTILITIES' REGULATORY MATTERS - SCHEDULE OF UTILITY PROJECTS 2 (Details) - Sunrise Powerlink Electric Transmission Line [Member] - San Diego Gas and Electric Company [Member] $ in Thousands	Sep. 30, 2015 USD ($)
Schedule Of Utility Projects [Line Items]
Final Status Report	$ 1,887,400
2008 CPUC Approval Decision	1,883,000
Difference	4,400
Construction Costs And AFUDC [Member]
Schedule Of Utility Projects [Line Items]
Final Status Report	1,490,900
2008 CPUC Approval Decision	1,594,200
Difference	(103,300)
Undergrounding On Alpine Boulevard [Member]
Schedule Of Utility Projects [Line Items]
Final Status Report	11,700
2008 CPUC Approval Decision	91,000
Difference	(79,300)
Undergrounding Savings Per Quarter Mile	11,000
Mitigation And Monitoring Costs [Member]
Schedule Of Utility Projects [Line Items]
Final Status Report	384,800
2008 CPUC Approval Decision	197,800
Difference	$ 187,000

CALIFORNIA UTILITIES' REGULATORY MATTERS - SCHEDULE OF REGULATORY AMOUNTS 3 (Details) - Southern California Gas Company [Member] - USD ($) $ in Thousands	3 Months Ended				12 Months Ended				36 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Impact Of 2010 Tax Act [Line Items]
Increase Due To Bonus Depreciation Extension, Net Of Tax	$ 1,100	$ 600	$ 800	$ 1,400					$ 11,300
Increase Due To Bonus Depreciation Extension, Before Tax					$ 6,600	$ 6,400	$ 6,300	$ 6,400
First Quarter [Member]
Seasonal Factors [Line Items]
Percentage Revenue Recognized Straight Line		25.00%
Percentage Revenue Recognized Seasonal		34.00%
Second Quarter [Member]
Seasonal Factors [Line Items]
Percentage Revenue Recognized Straight Line		25.00%
Percentage Revenue Recognized Seasonal		21.00%
Third Quarter [Member]
Seasonal Factors [Line Items]
Percentage Revenue Recognized Straight Line		25.00%
Percentage Revenue Recognized Seasonal		16.00%
Fourth Quarter [Member]
Seasonal Factors [Line Items]
Percentage Revenue Recognized Straight Line		25.00%
Percentage Revenue Recognized Seasonal		29.00%

COMMITMENTS AND CONTINGENCIES - LEGAL PROCEEDINGS (Details) £ in Millions	3 Months Ended
	Sep. 30, 2015 USD ($)	Oct. 01, 2015 GBP (£)	Oct. 01, 2014 GBP (£)
Loss Contingencies [Line Items]
Loss Contingency Accrual, at Carrying Value	$ 52,000,000
San Diego Gas and Electric Company [Member]
Loss Contingencies [Line Items]
Loss Contingency Accrual, at Carrying Value	27,000,000
Southern California Gas Company [Member]
Loss Contingencies [Line Items]
Loss Contingency Accrual, at Carrying Value	13,000,000
Loss from Catastrophes [Member] \| San Diego Gas and Electric Company [Member]
Loss Contingencies [Line Items]
Payments for Legal Settlements in April 2010, CPUC Proceedings	$ 14,750,000
Number Of Remaining Cases Set for Trial	1
Claims Payments By Insurers To All Claimants	$ 1,600,000,000
Percentage of Total Claims to be Paid by Company	57.50%
Total Settled Claims	$ 1,300,000,000
Loss Contingency Number Of Plaintiffs	6,500
Loss Contingency, Number Of Claims	19,000
Liability Insurance Coverage, Maximum	$ 1,100,000,000
Litigation Settlement Amount, Gross, Recovered From Third Parties	824,000,000
Payments For Legal Settlements In Excess Of Recovered Amounts	496,000,000
Regulatory Assets Arising From Wildfire Litigation Costs	362,000,000
Potential After-Tax Charge for Nonrecovery of CPUC Regulatory Assets	213,000,000
Portion of Regulatory Assets Arising From Wildfire Litigation Related To CPUC Operations	$ 359,000,000
Number of Appeals Pending	2
Mobile Gas Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency Number Of Plaintiffs	1,000
Loss Contingency, Number Of Lawsuits	13
R B S [Member]
Loss Contingencies [Line Items]
VAT Tax Claim Paid Upon Appeal \| £		£ 156	£ 86
Investment in RBS Sempra Commodities LLP	$ 71,000,000
Rim Rock [Member] \| San Diego Gas and Electric Company [Member]
Loss Contingencies [Line Items]
Estimated Tax Equity Investment	$ 285,000,000
So Cal Gas PCB Litigation Member [Member] \| Southern California Gas Company [Member]
Loss Contingencies [Line Items]
Number of Lawsuits as a Defendant	7
Number of Lawsuits Settled	5
Mobile Gas Litigation [Member] [Member]
Loss Contingencies [Line Items]
Number of Lawsuits Settled	6
Number Of Lawsuits Remaining	7
Number Of Plaintiffs Scheduled For Trial	10

COMMITMENTS AND CONTINGENCIES - NUCLEAR INSURANCE (Details) - San Diego Gas and Electric Company [Member] $ in Thousands	Sep. 30, 2015 USD ($)
Schedule Of Nuclear Insurance [Line Items]
Nuclear Liability Insurance Coverage, Maximum	$ 375,000
Secondary Financial Protection, Maximum	13,200,000
Secondary Financial Protection, Company Contribution, Maximum	50,930
Secondary Financial Protection, Company Contribution, Annual Maximum	7,600
Nuclear Property Insurance Coverage, Maximum	2,750,000
Nuclear Property Damage Insurance, Premium Assessment	9,700
Nuclear Property Insurance Terrorism Coverage, Maximum	3,240,000
Nuclear Property Insurance, Deductible Per Event	$ 2,500

COMMITMENTS AND CONTINGENCIES - CONTRACTUAL COMMITMENTS 2 (Details)	3 Months Ended
	Sep. 30, 2015 USD ($)
San Diego Gas and Electric Company [Member] \| Purchased Power Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	$ (362,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, Current	22,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	26,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	(14,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Four Years	(16,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Five Years	(21,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	(359,000,000)
San Diego Gas and Electric Company [Member] \| Construction and Development Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	(66,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(144,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	25,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	19,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Four Years	12,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Five Years	17,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	5,000,000
Southern California Gas Company [Member] \| Natural Gas Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	(120,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(114,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	(1,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	(1,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Four Years	(1,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Five Years	(1,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	(2,000,000)
Southern California Gas Company [Member] \| Construction and Development Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	(137,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(164,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	20,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	7,000,000
Sempra Mexico [Member] \| Construction and Development Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	41,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(19,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	59,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	1,000,000
Sempra Natural Gas [Member] \| Natural Gas Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	(345,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(219,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	(41,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	(45,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Four Years	(33,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Five Years	1,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	(8,000,000)
Sempra Natural Gas [Member] \| Liquefied Natural Gas Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitments, Payments Due, Current	(322,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	(128,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Three Years	(163,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Four Years	(194,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Five Years	(195,000,000)
Increase (Decrease) In Contractual Commitments, Payments Due, In Thereafter	$ (1,400,000,000)
Escalation percentage beyond year 2024	1.00%
Sempra Natural Gas [Member] \| Construction and Development Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	$ 46,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, Current	46,000,000
Sempra Natural Gas [Member] \| Other Commitments [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Long Term Contracts	(33,000,000)
Sempra Renewables [Member] \| Construction and Development Contracts [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Contractual Commitment Amount	554,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, Current	90,000,000
Increase (Decrease) In Contractual Commitments, Payments Due, In Two Years	$ 464,000,000

COMMITMENTS AND CONTINGENCIES - CONTRACTUAL COMMITMENTS 3 (Details) - Sempra Renewables [Member] $ in Millions	Sep. 30, 2015 USD ($)
Operating Leases [Line Items]
Increase (Decrease) In Operating Lease Future Minimum Payments, Due Current	$ (1)
Increase (Decrease) In Operating Lease Future Minimum Payments, Due In Two Years	1
Increase (Decrease) In Operating Lease Future Minimum Payments, Due In Three Years	1
Increase (Decrease) In Operating Lease Future Minimum Payments, Due In Four Years	2
Increase (Decrease) In Operating Lease Future Minimum Payments, Due In Five Years	2
Increase (Decrease) In Operating Lease Future Minimum Payments, Due Thereafter	39
Increase (Decrease) In Operating Leases Amount	$ 44

COMMITMENTS AND CONTINGENCIES - CONTRACTUAL COMMITMENTS 4 (Details) - Pio Pico [Member]
$ in Millions

Sep. 30, 2015

USD ($)

Capital Leases [Line Items]

$ 0

CapitalLeasesFutureMinimumPaymentsDueInTwoYears

CapitalLeasesFutureMinimumPaymentsDueInThreeYears

CapitalLeasesFutureMinimumPaymentsDueInFourYears

CapitalLeasesFutureMinimumPaymentsDueInFiveYears

CapitalLeasesFutureMinimumPaymentsDueThereafter

1,460

CapitalLeasesFutureMinimumPaymentsDue

1,628

^[1]

CapitalLeasesFutureMinimumPaymentsExecutoryCosts

(392)

CapitalLeasesFutureMinimumPaymentsInterestIncludedInPayments

(736)

^[2]

CapitalLeasesFutureMinimumPaymentsPresentValueOfNetMinimumPayments

$ 500

[1]	This amount will be recorded over the life of the lease as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.
[2]	Amount necessary to reduce net minimum lease payments to estimated present value at the inception of the lease.

SEGMENT INFORMATION (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 2,481

$ 2,815

$ 7,530

$ 8,288

100.00%

$ 143

$ 144

$ 416

$ 418

Segment reporting information, Depreciation and Amortization

$ 315

$ 292

$ 925

$ 866

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

100.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 15

$ 71

$ 276

$ 291

Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 248

$ 348

$ 980

$ 864

100.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 2,227

$ 2,320

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

100.00%

Segment reporting information, Percentage of Consolidated Assets

$ 40,566

$ 39,732

^[1]

100.00%

Segment Reporting Information Investments In Equity Method Investees

$ 2,845

$ 2,848

S D G E Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 1,230

$ 1,233

$ 3,168

$ 3,283

50.00%

44.00%

42.00%

40.00%

Segment reporting information, Depreciation and Amortization

$ 51

$ 155

$ 152

$ 152

$ 134

$ 446

$ 395

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

48.00%

46.00%

48.00%

46.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 75

$ 65

$ 217

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 170

$ 157

$ 443

$ 379

69.00%

45.00%

44.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 835

$ 790

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

38.00%

34.00%

Segment reporting information, Percentage of Consolidated Assets

$ 16,692

$ 16,296

41.00%

Segment Reporting Information, Intersegment Revenues

$ 2

$ 7

So Cal Gas Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 620

$ 855

$ 2,448

$ 2,857

25.00%

30.00%

33.00%

35.00%

$ 23

$ 17

$ 61

$ 50

Segment reporting information, Depreciation and Amortization

$ 116

$ 109

$ 342

$ 321

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

37.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (20)

$ 44

$ 91

$ 110

Segment reporting information, Percentage of Consolidated Earnings (Losses)

^[2]

$ (8)

$ 98

$ 276

$ 256

^[2]

(3.00%)

28.00%

30.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 946

$ 764

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

42.00%

33.00%

Segment reporting information, Percentage of Consolidated Assets

$ 11,355

$ 10,461

28.00%

26.00%

Segment Reporting Information, Intersegment Revenues

$ 19

$ 17

$ 55

$ 51

Sempra South American Utilities Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 373

$ 379

$ 1,151

$ 1,147

15.00%

14.00%

15.00%

14.00%

$ 9

$ 7

$ 22

$ 24

Segment reporting information, Depreciation and Amortization

$ 12

$ 14

$ 37

$ 41

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

4.00%

5.00%

4.00%

5.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 16

$ 26

$ 50

$ 59

Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax

(3)

(2)

(4)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 43

$ 32

$ 129

$ 109

17.00%

9.00%

13.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 105

$ 126

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

5.00%

Segment reporting information, Percentage of Consolidated Assets

$ 3,265

$ 3,379

8.00%

9.00%

Segment Reporting Information Investments In Equity Method Investees

$ (11)

$ (8)

Sempra Mexico Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 193

$ 234

$ 508

$ 621

8.00%

7.00%

$ 7

$ 5

$ 18

$ 13

Segment reporting information, Depreciation and Amortization

$ 18

$ 16

$ 52

$ 47

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

6.00%

5.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (6)

$ 13

$ 7

$ 37

Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 63

$ 160

$ 139

25.00%

18.00%

16.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 185

$ 262

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

8.00%

11.00%

Segment reporting information, Percentage of Consolidated Assets

$ 3,713

$ 3,488

9.00%

Segment Reporting Information Investments In Equity Method Investees

$ 491

$ 434

Segment Reporting Information, Intersegment Revenues

$ 23

$ 68

Sempra Renewables Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 12

$ 10

$ 30

$ 25

0.00%

$ 1

$ 2

$ 3

Segment reporting information, Depreciation and Amortization

$ 2

$ 1

$ 5

$ 4

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

0.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (9)

$ (16)

$ (37)

$ (35)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 15

$ 17

$ 47

$ 63

6.00%

5.00%

7.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 47

$ 174

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

2.00%

8.00%

Segment reporting information, Percentage of Consolidated Assets

$ 1,351

$ 1,338

3.00%

Segment Reporting Information Investments In Equity Method Investees

$ 843

$ 911

Sempra Natural Gas Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 160

$ 252

$ 512

$ 748

6.00%

9.00%

7.00%

9.00%

$ 13

$ 25

$ 57

$ 90

Segment reporting information, Depreciation and Amortization

$ 12

$ 17

$ 36

$ 50

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

4.00%

6.00%

4.00%

6.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 0

$ (31)

$ 29

$ (22)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 1

$ 26

$ 43

$ 39

0.00%

8.00%

5.00%

4.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 61

$ 192

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

3.00%

8.00%

Segment reporting information, Percentage of Consolidated Assets

$ 5,552

$ 6,436

14.00%

16.00%

Segment Reporting Information Investments In Equity Method Investees

$ 1,435

$ 1,347

Segment Reporting Information, Intersegment Revenues

$ 107

151

$ 266

Adjustments and Eliminations [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 0

$ 1

$ (1)

0.00%

Intercompany Eliminations Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

$ (26)

$ (93)

$ (92)

Intersegment Revenues Segment [Member]

(18)

(22)

(62)

(84)

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

^[3]

$ (107)

$ (149)

$ (286)

$ (392)

^[3]

(4.00%)

(5.00%)

(4.00%)

(5.00%)

Intersegment Receivables Segment [Member]

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Percentage of Consolidated Assets

$ (2,480)

$ (2,561)

(6.00%)

All Other Segments [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

$ 65

$ 63

$ 193

$ 178

Segment reporting information, Depreciation and Amortization

(1)

$ 3

$ 1

$ 7

$ 8

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

1.00%

0.00%

1.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (41)

$ (30)

$ (81)

$ (75)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ (36)

$ (45)

$ (118)

$ (121)

(14.00%)

(13.00%)

(12.00%)

(14.00%)

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for property plant and equipment

$ 48

$ 12

Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment

2.00%

1.00%