View Filing Data

Less accumulated depreciation and amortization

33,251

31,192

^[1],[2]

(8,261)

(7,727)

^[1],[2]

Property, plant and equipment, net

24,990

23,465

^[1],[2]

Total assets

35,390

33,249

^[1],[2]

Current liabilities:

Short-term debt

584

449

^[1],[2]

Accounts payable - trade

970

983

^[1],[2]

Accounts payable - other

126

124

^[1],[2]

Income taxes payable

^[1],[2]

Deferred income taxes, net current liabilities

155

173

^[1],[2]

Dividends and interest payable

309

219

^[1],[2]

Accrued compensation and benefits

273

323

^[1],[2]

Regulatory balancing accounts, overcollected

117

105

^[1],[2]

Current portion of long-term debt

709

336

^[1],[2]

Fixed-price contracts and other derivatives, current liabilities

^[1],[2]

Customer deposits

150

142

^[1],[2]

Reserve for wildfire litigation (Note 10)

284

586

^[1],[2]

Other current liabilities

590

615

^[1],[2]

Total current liabilities

4,349

4,152

^[1],[2]

Long-term debt

11,193

10,078

^[1],[2]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

146

142

^[1],[2]

Pension and other postretirement benefit obligations, net of plan assets

1,337

1,423

^[1],[2]

Deferred income taxes, net noncurrent liabilities

1,609

1,520

^[1],[2]

Deferred investment tax credits

^[1],[2]

Regulatory liabilities arising from removal obligations

2,673

2,551

^[1],[2]

Asset retirement obligations

1,981

1,905

^[1],[2]

Other regulatory liabilities

^[1],[2]

Noncurrent reserve for wildfire litigation (Note 10)

127

^[1],[2]

Fixed-price contracts and other derivatives, noncurrent liabilities

270

301

^[1],[2]

Deferred credits and other

1,028

774

^[1],[2]

Total deferred credits and other liabilities

9,273

8,762

^[1],[2]

Contingently redeemable preferred stock of subsidiary

^[1],[2]

Equity:

Common stock

2,178

2,104

^[1],[2]

Retained earnings

8,293

8,162

^[1],[2]

Deferred compensation

^[1],[2]

(2)

Accumulated other comprehensive income (loss)

(389)

(489)

^[1],[2]

Total shareholders' equity

10,082

9,775

^[1],[2]

Preferred stock of subsidiaries

^[1],[2]

Other noncontrolling interests

394

383

^[1],[2]

Total equity

10,496

10,178

^[1],[2]

Total liabilities and equity

35,390

33,249

^[1],[2]

San Diego Gas and Electric Company and Subsidiary [Member]

Current assets:

Cash and cash equivalents

^[2]

Restricted cash

^[2]

Other accounts and notes receivable

^[2]

Trade accounts receivable

294

267

^[2]

Inventories

^[2]

Due from unconsolidated affiliates

^[2]

Income taxes receivable

171

102

^[2]

Regulatory balancing accounts, net

301

^[2]

Regulatory assets arising from fixed-price contracts and other derivatives - current

^[2]

Regulatory assets

^[2]

Fixed-price contracts and other derivatives, current assets

^[2]

Settlement receivable related to wildfire litigation

180

^[2]

Other current assets

109

^[2]

Total current assets

1,307

795

^[2]

Investments And Other Assets [Abstract]

Restricted cash, noncurrent

^[2]

Deferred taxes recoverable in rates

647

570

^[2]

Regulatory assets arising from fixed-price contracts and other derivatives - noncurrent

138

191

^[2]

Regulatory assets arising from pension and other postretirement benefit obligations

287

309

^[2]

Regulatory assets arising from wildfire litigation costs

326

594

^[2]

Other regulatory assets

252

160

^[2]

Nuclear decommissioning trusts

892

804

^[2]

Sundry

^[2]

Total investments and other assets

2,651

2,720

^[2]

Property, plant and equipment:

Less accumulated depreciation and amortization

13,827

13,003

^[2]

(3,196)

(2,963)

^[2]

Property, plant and equipment, net

10,631

10,040

^[2]

Total assets

14,589

13,555

^[2]

Current liabilities:

Short-term debt

Accounts payable - trade

304

375

^[2]

Due to unconsolidated affiliates

^[2]

Deferred income taxes, net current liabilities

^[2]

Dividends and interest payable

^[2]

Accrued compensation and benefits

124

^[2]

Current portion of long-term debt

^[2]

Fixed-price contracts and other derivatives, current liabilities

^[2]

Customer deposits

^[2]

Reserve for wildfire litigation (Note 10)

284

586

^[2]

Other current liabilities

117

107

^[2]

Total current liabilities

1,065

1,436

^[2]

Long-term debt

4,293

4,058

^[2]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

^[2]

Pension and other postretirement benefit obligations, net of plan assets

323

342

^[2]

Deferred income taxes, net noncurrent liabilities

1,515

1,167

^[2]

Deferred investment tax credits

^[2]

Regulatory liabilities arising from removal obligations

1,575

1,462

^[2]

Asset retirement obligations

724

693

^[2]

Noncurrent reserve for wildfire litigation (Note 10)

127

^[2]

Fixed-price contracts and other derivatives, noncurrent liabilities

220

243

^[2]

Deferred credits and other

421

178

^[2]

Total deferred credits and other liabilities

4,949

4,141

^[2]

Contingently redeemable preferred stock

^[2]

Equity:

Common stock

1,338

^[2]

Retained earnings

2,785

2,411

^[2]

Accumulated other comprehensive income (loss)

(10)

^[2]

Total shareholders' equity

4,113

3,739

^[2]

Other noncontrolling interests

102

^[2]

Total equity

4,203

3,841

^[2]

Total liabilities and equity

14,589

13,555

^[2]

Cash and cash equivalents

Current assets:

257

^[2]

Other accounts and notes receivable

^[2]

Trade accounts receivable

273

578

^[2]

Inventories

166

151

^[2]

Due from unconsolidated affiliates

280

^[2]

Income taxes receivable

^[2]

Regulatory assets

^[2]

Other current assets

^[2]

Total current assets

1,105

922

^[2]

Investments And Other Assets [Abstract]

Regulatory assets arising from pension and other postretirement benefit obligations

730

808

^[2]

Other regulatory assets

117

137

^[2]

Sundry

^[2]

Total investments and other assets

858

953

^[2]

Property, plant and equipment:

Less accumulated depreciation and amortization

10,919

10,565

^[2]

(4,098)

(3,965)

^[2]

Property, plant and equipment, net

6,821

6,600

^[2]

Total assets

8,784

8,475

^[2]

Current liabilities:

Accounts payable - trade

254

315

^[2]

Accounts payable - other

^[2]

Due to unconsolidated affiliates

^[2]

Deferred income taxes, net current liabilities

^[2]

Accrued compensation and benefits

102

^[2]

Regulatory balancing accounts, net credit

117

105

^[2]

Current portion of long-term debt

254

257

^[2]

Customer deposits

^[2]

Other current liabilities

129

172

^[2]

Total current liabilities

1,068

1,147

^[2]

Long-term debt

1,409

1,064

^[2]

Deferred Credits And Other Liabilities [Abstract]

Customer advances for construction

113

110

^[2]

Pension and other postretirement benefit obligations, net of plan assets

756

833

^[2]

Deferred income taxes, net noncurrent liabilities

652

576

^[2]

Deferred investment tax credits

^[2]

Regulatory liabilities arising from removal obligations

1,084

1,075

^[2]

Asset retirement obligations

1,197

1,161

^[2]

Deferred taxes refundable in rates

^[2]

Deferred credits and other

195

206

^[2]

Total deferred credits and other liabilities

4,073

4,071

^[2]

Equity:

Preferred stock

^[2]

Common stock

866

^[2]

Retained earnings

1,366

1,326

^[2]

Accumulated other comprehensive income (loss)

(20)

(21)

^[2]

Total shareholders' equity

2,234

2,193

^[2]

Total equity

2,234

2,193

Total liabilities and equity

$ 8,784

$ 8,475

^[2]

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Derived from audited financial statements.

CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2012	Dec. 31, 2011
Property, plant and equipment related to VIE	$ 473	$ 494
Long-term debt related to VIE	$ 337	$ 345
Shareholders' equity:
Preferred stock, shares authorized	50	50
Common stock, shares authorized	750	750
Common stock, shares outstanding	242	240
San Diego Gas and Electric Company and Subsidiary [Member]
Property, plant and equipment related to VIE	$ 473	$ 494
Long-term debt related to VIE	$ 337	$ 345
Shareholders' equity:
Common stock, shares authorized	255	255
Common stock, shares outstanding	117	117
Southern California Gas Company [Member]
Shareholders' equity:
Common stock, shares authorized	100	100
Common stock, shares outstanding	91	91

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

REVENUES

Utilities

$ 2,170

$ 2,065

^[1]

$ 6,099

$ 5,933

^[1]

Energy-related businesses

337

511

^[1]

880

1,499

^[1]

Total revenues

2,507

2,576

^[1]

6,979

7,432

^[1]

Utilities [Abstract]

Cost of natural gas

(212)

(322)

^[1]

(864)

(1,367)

^[1]

Cost of electric fuel and purchased power

(515)

(408)

^[1]

(1,252)

(976)

^[1]

Cost of natural gas, electric fuel and purchased power

(136)

(252)

^[1]

(346)

(694)

^[1]

Other cost of sales

(43)

(68)

^[1]

(117)

(123)

^[1]

Operation and maintenance

(732)

(691)

^[1]

(2,123)

(2,003)

^[1]

Depreciation and amortization

(280)

(251)

^[1]

(803)

(729)

^[1]

Franchise fees and other taxes

(89)

(84)

^[1]

(264)

(259)

^[1]

Equity (losses) earnings before income tax

Equity (losses) earnings before income tax, Rockies Express

(87)

^[1]

(366)

^[1]

Equity (losses) earnings before income tax, other

(7)

(22)

^[1]

(9)

(33)

^[1]

^[1]

277

Income before income taxes and equity earnings of certain unconsolidated subsidiaries

^[1]

137

^[1]

Interest income

^[1]

Interest expense

(126)

(118)

^[1]

(352)

(344)

^[1]

329

388

^[1]

634

1,317

^[1]

Income tax (expense) benefit

(49)

(75)

^[1]

(48)

(289)

^[1]

Equity earnings, net of income tax

^[1]

Losses (earnings) attributable to noncontrolling interests

290

319

^[1]

615

1,073

^[1]

(20)

(29)

^[1]

(44)

(21)

^[1]

(2)

(1)

^[1]

(5)

(6)

^[1]

Basic earnings per common share

$ 268

$ 289

^[1]

$ 566

$ 1,046

^[1]

Basic earnings per common share:

$ 1.11

$ 1.21

^[1]

$ 2.35

$ 4.36

^[1]

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

241,689

239,545

^[1]

241,133

239,693

^[1]

Diluted earnings per common share:

Diluted earnings per common share

$ 1.09

$ 1.20

^[1]

$ 2.31

$ 4.32

^[1]

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

245,802

241,880

^[1]

245,013

241,955

^[1]

Dividends declared per share of common stock

$ 0.60

$ 0.48

^[1]

$ 1.80

$ 1.44

^[1]

San Diego Gas and Electric Company and Subsidiary [Member]

Utility operating revenues

Electric

$ 998

$ 763

$ 2,349

$ 2,011

Natural gas

105

357

394

Total utility operating revenues

1,092

868

2,706

2,405

Utility operating expenses

Utility cost of natural gas

130

175

Utility cost of electric fuel and purchased power

301

207

604

534

Utility operation and maintenance

309

255

852

756

Utility franchise fees and other taxes

128

108

359

316

144

138

Total utility operating expenses

822

658

2,089

1,919

Utility operating income

270

210

617

486

Equity (losses) earnings before income tax

Income before income taxes and equity earnings of certain unconsolidated subsidiaries

Interest expense

(49)

(37)

(124)

(104)

226

199

552

437

Income tax (expense) benefit

(38)

(63)

(151)

(154)

Losses (earnings) attributable to noncontrolling interests

188

136

401

283

(12)

(21)

(23)

(6)

176

115

378

277

Earnings attributable to common shares

(2)

(4)

174

113

374

273

Total utility operating revenues

Utility operating revenues

728

844

2,328

2,776

Utility operating expenses

Utility cost of natural gas

175

267

703

1,133

Utility operation and maintenance

316

331

933

946

Utility franchise fees and other taxes

268

246

Total utility operating expenses

609

709

1,995

2,419

Utility operating income

119

135

333

357

Equity (losses) earnings before income tax

Income before income taxes and equity earnings of certain unconsolidated subsidiaries

Interest income

Interest expense

(17)

(51)

(52)

108

122

296

315

Income tax (expense) benefit

(37)

(41)

(105)

(106)

191

209

191

209

Earnings attributable to common shares

(1)

$ 71

$ 81

$ 190

$ 208

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

$ 290

$ 319

^[1]

$ 615

$ 1,073

^[1]

Reclassification to net income of foreign currency translation adjustments related to equity method investments

(139)

^[1]

125

(110)

^[1]

^[1],[2]

(54)

(7)

(39)

^[1]

(22)

(52)

^[1]

(10)

^[1]

(5)

^[1]

Total Comprehensive Income Before Preferred Stock Dividend Requirements

(177)

^[1]

(208)

^[1]

361

142

^[1]

713

865

^[1]

Comprehensive Income Net Of Tax

(2)

(1)

^[1]

(5)

(6)

^[1]

359

141

^[1]

708

859

^[1]

San Diego Gas and Electric Company and Subsidiary [Member]

188

136

401

283

(4)

(25)

(13)

(34)

Total Comprehensive Income Before Preferred Stock Dividend Requirements

(4)

(24)

(13)

(33)

184

112

388

250

191

209

Total Comprehensive Income Before Preferred Stock Dividend Requirements

192

211

Total Shareholders' Equity

270

290

^[1]

571

1,052

^[1]

Reclassification to net income of foreign currency translation adjustments related to equity method investments

(132)

^[1]

114

(109)

^[1]

^[1],[2]

(54)

(3)

(14)

^[1]

(9)

(18)

^[1]

(10)

^[1]

(5)

^[1]

Total Comprehensive Income Before Preferred Stock Dividend Requirements

(145)

^[1]

100

(173)

^[1]

337

145

^[1]

671

879

^[1]

Comprehensive Income Net Of Tax

(2)

(1)

^[1]

(5)

(6)

^[1]

335

144

^[1]

666

873

^[1]

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

176

115

378

277

Total Comprehensive Income Before Preferred Stock Dividend Requirements

176

116

378

278

Noncontrolling Interests

^[1]

(7)

^[1]

(1)

^[1]

(4)

(25)

^[1]

(13)

(34)

^[1]

Total Comprehensive Income Before Preferred Stock Dividend Requirements

(32)

^[1]

(2)

(35)

^[1]

(3)

^[1]

(14)

^[1]

Comprehensive Income Net Of Tax

(3)

^[1]

(14)

^[1]

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

(4)

(25)

(13)

(34)

Total Comprehensive Income Before Preferred Stock Dividend Requirements

(4)

(25)

(13)

(34)

$ 8

$ (4)

$ 10

$ (28)

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Related to the acquisition of Chilquinta Energía and Luz del Sur.

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

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

CASH FLOWS FROM OPERATING ACTIVITIES

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

$ 615

$ 1,073

^[1]

Depreciation and amortization

803

729

^[1]

Deferred income taxes and investment tax credits

(45)

211

^[1]

Fixed-price contracts and other derivatives

^[1]

(277)

Equity earnings

346

(41)

^[1]

(7)

^[1]

Other

(8)

(43)

^[1]

Net change in other working capital components

(373)

(75)

^[1]

Distributions from RBS Sempra Commodities LLP, operating activities

^[1]

Changes in other assets

202

^[1]

Changes in other liabilities

147

(11)

^[1]

Net cash provided by operating activities

1,688

1,643

^[1]

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(2,241)

(2,031)

^[1]

Expeditures for investments and acquisition of businesses, net of cash acquired

(359)

(696)

^[1]

Proceeds from sale of joint venture

Distributions from RBS Sempra Commodities LLP, investing activities

^[1]

374

Distributions from investments

^[1]

Purchases of nuclear decommissioning and other trust assets

(534)

(399)

^[1]

Proceeds from sales by nuclear decommissioning and other trusts

534

398

^[1]

Decrease in restricted cash

473

^[1]

Increase in restricted cash

(105)

(450)

^[1]

Other cash flows from investing activities

(12)

(20)

^[1]

Net cash used in investing activities

(2,576)

(2,304)

^[1]

CASH FLOWS FROM FINANCING ACTIVITIES

Common dividends paid

(405)

(325)

^[1]

Preferred dividends paid by subsidiaries

(5)

(6)

^[1]

Issuances of common stock

^[1]

Repurchases of common stock

(16)

(18)

^[1]

Redemption of subsidiary preferred stock

^[1]

(80)

Issuances of debt (maturities greater than 90 days)

2,294

1,525

^[1]

Payments on debt (maturities greater than 90 days)

(563)

(366)

^[1]

Increase (decrease) in short-term debt, net

(142)

(300)

^[1]

Purchase of noncontrolling interests

(36)

(10)

^[1]

^[1]

(43)

Other cash flows from financing activities

(20)

^[1]

Net cash provided by (used in) financing activities

1,157

404

^[1]

Effect of exchange rate changes on cash and cash equivalents

^[1]

Increase (decrease) in cash and cash equivalents

278

(255)

^[1]

Cash and cash equivalents, beginning of period

^[1]

252

^[2]

912

Cash and cash equivalents, end of period

530

657

^[1]

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

278

281

Income tax payments, net of refunds

106

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES

Accrued capital expenditures

315

306

U. S. Treasury grants receivable

^[3]

136

Cash grants previously recorded as investment tax credits

Acquisition Of Business [Abstract]

Assets acquired

2,831

Cash paid, net of cash acquired

(19)

(611)

Fair of equity method investments immediately prior to the acquisition

(882)

Fair value of noncontrolling interests

(279)

Additional consideration accrued

(32)

Liabilities Assumed

1,027

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES

Dividends declared but not paid

149

119

San Diego Gas and Electric Company and Subsidiary [Member]

CASH FLOWS FROM OPERATING ACTIVITIES

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

401

283

Deferred income taxes and investment tax credits

359

316

262

226

Fixed-price contracts and other derivatives

(9)

(13)

Other

(55)

(43)

Net change in other working capital components

(518)

Changes in other assets

201

Changes in other liabilities

129

Net cash provided by operating activities

770

819

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(998)

(1,162)

Purchases of nuclear decommissioning and other trust assets

(530)

(395)

Proceeds from sales by nuclear decommissioning and other trusts

524

389

Decrease in restricted cash

340

Increase in restricted cash

(62)

(355)

Net cash used in investing activities

(992)

(1,183)

CASH FLOWS FROM FINANCING ACTIVITIES

Capital contribution

200

Preferred dividends paid

(4)

Issuances of long-term debt

249

348

Payments on long-term debt

(7)

Increase (decrease) in short-term debt, net

Contributions from noncontrolling interests

Other cash flows from financing activities

(22)

(3)

(2)

Net cash provided by (used in) financing activities

215

540

Increase (decrease) in cash and cash equivalents

(7)

176

Cash and cash equivalents, beginning of period

^[2]

127

Cash and cash equivalents, end of period

303

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

Income tax payments, net of refunds

(121)

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES

Accrued capital expenditures

161

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES

Dividends declared but not paid

CASH FLOWS FROM OPERATING ACTIVITIES

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

191

209

Deferred income taxes and investment tax credits

268

246

Other

(9)

(4)

Net change in other working capital components

240

(46)

Changes in other assets

Changes in other liabilities

(6)

Net cash provided by operating activities

746

495

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

(462)

(499)

Increase (decrease) in loans to affiliates, net

(257)

(96)

Net cash used in investing activities

(719)

(595)

CASH FLOWS FROM FINANCING ACTIVITIES

Common dividends paid

(150)

(50)

Preferred dividends paid

(1)

Issuances of long-term debt

348

Payments on long-term debt

(250)

Debt issuances costs

(3)

Net cash provided by (used in) financing activities

194

(301)

Increase (decrease) in cash and cash equivalents

221

(401)

Cash and cash equivalents, beginning of period

^[2]

417

Cash and cash equivalents, end of period

257

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest payments, net of amounts capitalized

Income tax payments, net of refunds

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES

Accrued capital expenditures

$ 69

$ 81

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Derived from audited financial statements.
[3]	Cash grants, excluding $45 million previously recorded in 2011 as investment tax credits.

GENERAL

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

General

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION

2012 Business Segment Realignment

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

Sempra Energy

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

San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate, reportable segments;
Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and

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

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

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated subsidiaries in Note 4 herein and Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed on May 11, 2012, discussed below under “Basis of Presentation.”

SDG&E

SDG&E's Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss in Note 5 under “Variable Interest Entities.” SDG&E's common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.

SoCalGas

SoCalGas' Condensed Consolidated Financial Statements include its subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations. SoCalGas' common stock is wholly owned by Pacific Enterprises (PE), which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.

We have prepared the Condensed Consolidated Financial Statements in conformity with GAAP and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after September 30, 2012 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.

All December 31, 2011 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2011 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of GAAP and the Securities and Exchange Commission.

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

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas Mexico, S de RL de CV (Ecogas) in Northern Mexico, all natural gas distribution utilities. The California Utilities, Sempra Natural Gas' Mobile Gas and Willmut Gas, and Sempra Mexico's Ecogas prepare their financial statements in accordance with GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

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

Change in Accounting Principle

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

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

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

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

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

EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
		Three months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Income tax expense		$	68	$	7	$	75
Net income			326		(7)		319
Earnings			296		(7)		289

Basic earnings per common share		$	1.23	$	(0.02)	$	1.21
Diluted earnings per common share		$	1.22	$	(0.02)	$	1.20

		Nine months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Depreciation and amortization		$	730	$	(1)	$	729
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			1,316		1		1,317
Income tax expense			269		20		289
Net income			1,092		(19)		1,073
Earnings			1,065		(19)		1,046

Basic earnings per common share		$	4.44	$	(0.08)	$	4.36
Diluted earnings per common share		$	4.40	$	(0.08)	$	4.32

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Net income		$	1,092	$	(19)	$	1,073
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization			730		(1)		729
Deferred income taxes and investment tax credits			224		(13)		211
Net change in other working capital components (income taxes)			(108)		33		(75)

		As of December 31, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
Property, plant and equipment		$	31,303	$	(111)	$	31,192
Less accumulated depreciation and amortization			(7,731)		4		(7,727)
Property, plant and equipment, net		$	23,572	$	(107)	$	23,465

Income taxes payable		$	16	$	(11)	$	5
Deferred income taxes, noncurrent liability			1,554		(34)		1,520
Deferred credits and other			773		1		774
Retained earnings(1)			8,225		(63)		8,162
(1)	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

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Notes to Consolidated Financial Statements [Abstract]

NEW ACCOUNTING STANDARDS

3 Months Ended

Sep. 30, 2012

New Accounting Standards

NOTE 2. NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures.

SEMPRA ENERGY, SDG&E AND SOCALGAS

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

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

quantitative information about the unobservable inputs
a description of the valuation process
a qualitative discussion about the sensitivity of the measurements

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

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

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

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

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

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

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

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

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

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.

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Notes to Consolidated Financial Statements [Abstract]

RECENT INVESTMENT ACTIVITY

3 Months Ended

Sep. 30, 2012

Recent Investment Activity

NOTE 3. ACQUISITION AND INVESTMENT ACTIVITY

We discuss our investments in unconsolidated entities in Note 4.

Sempra South American Utilities

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

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

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

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

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

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

Sempra Natural Gas

Willmut Gas Company

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

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

INVESTMENTS IN UNCONSOLIDATED ENTITIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Investments in Unconsolidated Entities

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

Sempra Renewables

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

Sempra Natural Gas

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

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

RBS SEMPRA COMMODITIES

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

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

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

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

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

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

Notes to Consolidated Financial Statements [Abstract]

OTHER FINANCIAL DATA

3 Months Ended

Sep. 30, 2012

Other Financial Data

NOTE 5. OTHER FINANCIAL DATA

U. S. Treasury Grants Receivable

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

Inventories

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)

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

VARIABLE INTEREST ENTITIES (VIE)

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

the purpose and design of the VIE;
the nature of the VIE's risks and the risks we absorb;
the power to direct activities that most significantly impact the economic performance of the VIE; and

the obligation to absorb losses or right to receive benefits that could be significant to the VIE.

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

Otay Mesa VIE

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

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE's equity of $90 million at September 30, 2012 and $102 million at December 31, 2011 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $347 million at September 30, 2012, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC's property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.

Other Variable Interest Entities

SDG&E's power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary as of September 30, 2012. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.

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

The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on the table below generally correspond to SDG&E's Condensed Consolidated Statements of Operations.

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011

Operating revenues
Electric	$	―	$	―	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		―		―		―
Operating expenses
Cost of electric fuel and purchased power		(26)		(29)		(66)		(55)
Operation and maintenance		4		1		15		23
Depreciation and amortization		7		7		19		20
Total operating expenses		(15)		(21)		(32)		(12)
Operating income		15		21		32		12
Other income (expense), net		―		4		(1)		―
Interest expense		(3)		(4)		(8)		(6)
Income before income taxes/Net income		12		21		23		6
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings	$	―	$	―	$	―	$	―

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

GOODWILL

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

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

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

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

PENSION AND OTHER POSTRETIREMENT BENEFITS

Remeasurement

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

Employee Stock Ownership Plan (ESOP)

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

Net Periodic Benefit Cost

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

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

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

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

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2012:

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

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

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2012 and 2011. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011(1)		2012		2011(1)
Numerator:
Earnings/Income attributable to common shareholders		$	268	$	289	$	566	$	1,046

Denominator:
Weighted-average common shares
outstanding for basic EPS			241,689		239,545		241,133		239,693
Dilutive effect of stock options, restricted
stock awards and restricted stock units			4,113		2,335		3,880		2,262
Weighted-average common shares
outstanding for diluted EPS			245,802		241,880		245,013		241,955

Earnings per share:
Basic		$	1.11	$	1.21	$	2.35	$	4.36
Diluted		$	1.09	$	1.20	$	2.31	$	4.32
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized and minus tax shortfalls recognized are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). We had no such antidilutive stock options outstanding during the three months ended September 30, 2012 and 40,000 such antidilutive stock options outstanding during the nine months ended September 30, 2012. We had 2,112,880 and 2,111,839 such stock options outstanding during the three months and nine months ended September 30, 2011, respectively.

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

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized and minus tax shortfalls recognized related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits recognized or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were 3,387 antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months and 1,881 such antidilutive RSUs for the nine months ended September 30, 2012. There were 1,109 such antidilutive RSUs for the three months ended September 30, 2011 and no such antidilutive RSUs for the nine months ended September 30, 2011. There were no such antidilutive RSAs for the three months ended September 30, 2012 and 14,319 such antidilutive RSAs for the nine months ended September 30, 2012. There were no such antidilutive RSAs for the three months and nine months ended September 30, 2011.

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

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

RSAs have a maximum potential of 100 percent vesting. We include our performance-based RSUs in potential dilutive shares at zero to 150 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative index, dilutive RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, in potential dilutive shares at 100 percent.

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

COMMON STOCK REPURCHASE PROGRAM

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

PREFERRED STOCK OF SUBSIDIARY

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

SHARE-BASED COMPENSATION

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

CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and, primarily at the California Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects. The following table shows capitalized financing costs for the three months and nine months ended September 30, 2012 and 2011.

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

COMPREHENSIVE INCOME

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

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(7)		―		(7)		1		―		1
Financial instruments			(1)		―		(1)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	―	$	―	$	―

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

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

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

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

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

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

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

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

At September 30, 2012 and December 31, 2011, Sempra Energy Consolidated reported the following other noncontrolling ownership interests held by others recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy's Condensed Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
		Percent Ownership Held by Others			September 30, 2012		December 31, 2011
Bay Gas Storage, Ltd.(1)		9	%	$	19	$	17
Southern Gas Transmission Company(1)		49			1		1
Liberty Gas Storage, LLC(1)		25			13		9
Tecsur		10			4		4
Luz del Sur		20			230		216
Chilquinta Energía subsidiaries		15 - 43			37		34
Otay Mesa VIE (at SDG&E)		100			90		102
Total Sempra Energy				$	394	$	383
(1)	Part of Sempra Natural Gas.

TRANSACTIONS WITH AFFILIATES

Loans to Unconsolidated Affiliates

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

Investments

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

Other Affiliate Transactions

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

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	16	$	2
Due from various affiliates			1		65
		$	17	$	67

Due to Sempra Energy		$	20	$	14

Income taxes due from Sempra Energy(1)		$	149	$	97

SoCalGas
Current:
Due from Sempra Energy		$	280	$	23
Due from various affiliates			―		17
		$	280	$	40

Due to SDG&E		$	16	$	2

Income taxes due from Sempra Energy(1)		$	15	$	17
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies’ having always filed a separate return.

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

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
SDG&E	$	2	$	3	$	6	$	6
SoCalGas		17		13		48		38

Transactions with RBS Sempra Commodities

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

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended September 30, 2011(1)		Nine months ended September 30, 2011(1)
Revenues:
Sempra Mexico		$	―	$	37
Sempra Natural Gas			―		7

Cost of natural gas:
Sempra Mexico		$	3	$	74
Sempra Natural Gas			―		3
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

OTHER INCOME, NET

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

OTHER INCOME, NET
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	13	$	26	$	80	$	67
Investment gains (losses)(1)			17		(6)		27		13
Gains (losses) on interest rate and foreign exchange instruments, net			1		(26)		11		(14)
Regulatory interest, net(2)			―		―		1		1
Sundry, net			13		18		18		19
Total		$	44	$	12	$	137	$	86
SDG&E:
Allowance for equity funds used during construction		$	6	$	21	$	61	$	54
Regulatory interest, net(2)			―		―		1		1
Sundry, net			(1)		5		(3)		―
Total		$	5	$	26	$	59	$	55
SoCalGas:
Allowance for equity funds used during construction		$	7	$	5	$	19	$	13
Sundry, net			(1)		(2)		(5)		(4)
Total		$	6	$	3	$	14	$	9
(1)	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

INCOME TAXES

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

Changes in Effective Income Tax Rates

Sempra Energy Consolidated

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

$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and

higher income tax expense due to unfavorable resolution of prior years' income tax items.
The lower effective income tax rate in the nine months ended September 30, 2012 was primarily due to:

$54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain from our equity method investments related to our acquisition from AEI of its investments in Chile and Peru;
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;
higher income tax expense due to unfavorable resolution of prior years' income tax items; and

higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.
Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted are factored into the forecasted effective tax rate and their impact is spread evenly over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software, repairs to certain utility plant fixed assets, renewable energy income tax credits, deferred income tax benefits related to renewable energy projects, exclusions from taxable income of the equity portion of AFUDC, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years' income tax items, Mexican currency translation and inflation adjustments, deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.
We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.
Under the deferral method of accounting for ITC and under grant accounting for cash grants, a deferred income tax benefit, on day one, is reflected in income tax expense by recording a deferred tax asset when renewable energy assets are placed in service. This deferred tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the “day-one basis difference.” The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced 50 percent for grants and not at all for ITC.
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, which has a negative impact on Sempra Energy's effective income tax rate for 2012.
SDG&E
The decrease in the effective income tax rate in the three months ended September 30, 2012 was primarily due to:

$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
higher favorable resolutions of prior years' income tax items; offset by
the impact of Otay Mesa VIE, as we discuss below; and

lower exclusions from taxable income of the equity portion of AFUDC.
The decrease in the effective tax rate in the nine months ended September 30, 2012 was primarily due to:

$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;
the impact of Otay Mesa VIE, as we discuss below;
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
higher favorable resolutions of prior years' income tax items; offset by

lower exclusions from taxable income of the equity portion of AFUDC.
Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE's stand-alone effective income tax rate.
SoCalGas
While the effective income tax rate for the three months ended September 30, 2012 did not change significantly from the same period in 2011, it was impacted by:

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

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

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

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

lower deductions for self-developed software costs; offset by

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

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

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

repairs to a certain portion of utility plant fixed assets
the equity portion of AFUDC
cost of removal of utility plant assets
self-developed software costs

depreciation on a certain portion of utility plant fixed assets

DEBT AND CREDIT FACILITIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Debt and Credit Facilities

NOTE 6. DEBT AND CREDIT FACILITIES

Committed Lines of Credit

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

Sempra Energy

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

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy's credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. The facility also provides for issuance of up to $700 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.

At September 30, 2012, Sempra Energy had $47 million of letters of credit outstanding supported by the facility.

Sempra Global

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

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

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

California Utilities

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

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

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

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

GUARANTEES

RBS Sempra Commodities

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

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

WEIGHTED AVERAGE INTEREST RATES

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

LONG-TERM DEBT

Sempra Energy

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

SDG&E

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

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

SoCalGas

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

Sempra South American Utilities

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

Sempra Renewables

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

INTEREST RATE SWAPS

We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.

DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Derivative Financial Instruments

NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

HEDGE ACCOUNTING

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

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

ENERGY DERIVATIVES

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

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

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

We summarize net energy derivative volumes as of September 30, 2012 and December 31, 2011 as follows:


Segment and Commodity		September 30, 2012	December 31, 2011
California Utilities:
SDG&E:
Natural gas		23 million MMBtu	35 million MMBtu	(1)
Congestion revenue rights		18 million MWh	19 million MWh	(2)

Energy-Related Businesses:
Sempra Natural Gas:
Electric power		2 million MWh	5 million MWh
Natural gas		32 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

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

INTEREST RATE DERIVATIVES

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

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

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

		September 30, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-347	2019		285-355	2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

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

FINANCIAL STATEMENT PRESENTATION

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

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2012
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	6	$	15	$	(20)	$	(69)
Commodity contracts not subject to rate recovery			―		―		(3)		―
Total		$	6	$	15	$	(23)	$	(69)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(68)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments		$	8	$	43	$	(8)	$	(38)
Commodity contracts not subject to rate recovery			119		19		(131)		(31)
Associated offsetting commodity contracts			(111)		(15)		111		15
Commodity contracts subject to rate recovery			9		20		(39)		(7)
Associated offsetting commodity contracts			(5)		(1)		5		1
Total		$	20	$	66	$	(62)	$	(60)
SDG&E:
Commodity contracts subject to rate recovery		$	7	$	20	$	(37)	$	(7)
Associated offsetting commodity contracts			(4)		(1)		4		1
Total		$	3	$	19	$	(33)	$	(6)
SoCalGas:
Commodity contracts subject to rate recovery		$	2	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(1)		―		1		―
Total		$	1	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	5	$	11	$	(17)	$	(65)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(65)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments		$	8	$	41	$	(7)	$	(36)
Commodity contracts not subject to rate recovery			156		72		(148)		(94)
Associated offsetting commodity contracts			(120)		(68)		120		68
Commodity contracts subject to rate recovery			28		8		(62)		(24)
Associated offsetting commodity contracts			(10)		(2)		10		2
Total		$	62	$	51	$	(87)	$	(84)
SDG&E:
Commodity contracts subject to rate recovery		$	22	$	8	$	(55)	$	(24)
Associated offsetting commodity contracts			(5)		(2)		5		2
Total		$	17	$	6	$	(50)	$	(22)
SoCalGas:
Commodity contracts subject to rate recovery		$	6	$	―	$	(7)	$	―
Associated offsetting commodity contracts			(5)		―		5		―
Total		$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

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

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain on derivatives recognized in earnings				Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	5	$	7
Interest rate instruments		Other Income, Net		4		13		6		16
Total(1)			$	5	$	15	$	11	$	23
SoCalGas:
Interest rate instrument		Interest Expense	$	―	$	―	$	―	$	1
Interest rate instrument		Other Income, Net		―		―		―		(3)
Total(1)			$	―	$	―	$	―	$	(2)
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

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

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

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

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

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

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

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

CONTINGENT FEATURES

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

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

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

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

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Notes to Consolidated Financial Statements [Abstract]

FAIR VALUE MEASUREMENTS

3 Months Ended

Sep. 30, 2012

Fair Value Measurements

NOTE 8. FAIR VALUE MEASUREMENTS

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

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels.

The fair value of commodity derivative assets and liabilities is determined in accordance with our netting policy, as discussed below under “Derivative Positions Net of Cash Collateral.”

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

Our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011 in the tables below include the following:

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

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

There were no transfers into or out of Level 1, Level 2, or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Interest rate instruments			―		73		―		―		73
Commodity contracts subject to rate recovery			21		―		23		―		44
Commodity contracts not subject to rate recovery			19		19		―		―		38
Investments			1		―		―		―		1
Total		$	642	$	355	$	23	$	―	$	1,020
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	136	$	―	$	―	$	136
Commodity contracts subject to rate recovery			32		8		―		(32)		8
Commodity contracts not subject to rate recovery			9		30		―		(13)		26
Total		$	41	$	174	$	―	$	(45)	$	170

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Commodity contracts subject to rate recovery			19		―		23		―		42
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	622	$	263	$	23	$	―	$	908

Liabilities:
Interest rate instruments		$	―	$	85	$	―	$	―	$	85
Commodity contracts subject to rate recovery			32		7		―		(32)		7
Total		$	32	$	92	$	―	$	(32)	$	92

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826

Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

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

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Level 3 Information

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

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

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

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (ISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. Auction prices range from $(3) per MWh to $5 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7. The earnings impacts of CRRs are deferred and recorded in regulatory accounts to the extent they are recoverable or refundable through rates. Upon settlement, CRRs are included in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

Derivative Positions Net of Cash Collateral

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

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

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

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2012 and December 31, 2011:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	16	$	―	$	―	$	46	$	46
Total long-term debt(2)			11,727		―		12,556		755		13,311
Preferred stock of subsidiaries			99		―		108		―		108
SDG&E:
Total long-term debt(3)		$	4,137	$	―	$	4,308	$	347	$	4,655
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,662	$	―	$	1,872	$	―	$	1,872
Preferred stock			22		―		24		―		24

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

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

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

Nuclear Decommissioning Trusts

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

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

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

SALES OF SECURITIES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Proceeds from sales	$	204	$	294	$	524	$	384
Gross realized gains		3		27		12		29
Gross realized losses		(1)		(8)		(6)		(10)

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

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

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

Rockies Express

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

the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties;
Rockies Express' future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal;
prospects for generating attractive revenues and cash flows beyond 2019, including natural gas' future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and

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

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

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

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

RBS Sempra Commodities

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

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

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated		Fair
		Fair		Value	% of Fair Value		Range of
		Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369	Market approach	Level 2	67%	Equity sale offer price	100%


			Probability weighted	Level 3	33%	Combined transportation rate assumption(1)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

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.

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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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Notes to Consolidated Financial Statements [Abstract]

CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2012

Sempra Utilities' Regulatory Matters

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS

JOINT MATTERS

General Rate Case (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.

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

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

Cost of Capital

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

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

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

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

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

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

Natural Gas Pipeline Operations Safety Assessments

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

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

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

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

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

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

We provide additional information regarding these rulemaking proceedings and the California Utilities' PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Utility Incentive Mechanisms

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

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

Energy Efficiency

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

Natural Gas Procurement

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

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

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

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

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

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

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

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

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

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

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

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

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

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

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

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

Power Procurement and Resource Planning

Renewable Energy

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

South Orange County Reliability Enhancement

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

Incremental Insurance Premium Cost Recovery

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

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

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

Excess Wildfire Claims Cost Recovery

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

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

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

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

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

East County Substation

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

SOCALGAS MATTER

Aliso Canyon Natural Gas Storage Compressor Replacement

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

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

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Commitments and Contingencies

NOTE 10. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

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

SDG&E

2007 Wildfire Litigation

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

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

Numerous parties have sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. These include owners and insurers of properties that were destroyed or damaged in the fires and government entities seeking recovery of firefighting, emergency response, and environmental costs. They assert various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines.

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

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

SDG&E has settled all of the approximately 19,000 claims brought by homeowner insurers for damage to insured property relating to the three fires. Under the settlement agreements, SDG&E has paid or will pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers' claims against other parties potentially responsible for the fires.

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

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

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

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

SDG&E's cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries from utility customers, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy's and SDG&E's financial position, cash flows and results of operations.

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

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

Sunrise Powerlink Electric Transmission Line

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

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

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

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

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

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

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

In February 2011, opponents of the Sunrise Powerlink filed a lawsuit in Sacramento County Superior Court against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated CEQA. The Superior Court denied the plaintiffs' petition in July 2012, and the plaintiffs have appealed.

September 2011 Power Outage

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

Smart Meters Patent Infringement Lawsuit

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

SoCalGas

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

Sempra Natural Gas

Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.

Sempra Mexico

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul liquefied natural gas (LNG) terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally. Sempra Mexico expects additional Mexican court proceedings and governmental actions regarding the claimant's assertions as to whether the terminal's permits should be modified or revoked in any manner.

The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization (EIA) issued to Energía Costa Azul in 2003. These cases generally allege that the conditions and mitigation measures in the EIA are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. Also, there are two real property cases pending against Energía Costa Azul in which the plaintiffs seek to annul the recorded property titles for parcels on which the Energía Costa Azul LNG terminal is situated and to obtain possession of different parcels that allegedly sit in the same place. Sempra Mexico expects further proceedings on each of these matters.

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

Other Litigation

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

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

As described in Note 4, we hold a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom's Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. The letter states that HMRC is conducting a number of investigations into VAT tax refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued an assessment of £86 million for the VAT paid in connection with these transactions and identified several options for responding, including requesting a review by HMRC and appealing to an independent tribunal. HMRC indicated that the assessment was issued on a protective basis as discussion about the issues is continuing.

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

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E's contribution would be up to $47 million. This amount is subject to an annual maximum of $7 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $9.7 million.

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

We provide additional information about SONGS in Note 9.

CONTRACTUAL COMMITMENTS

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

Natural Gas Contracts

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

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

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

LNG Purchase Agreements

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

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

Purchased-Power Contracts

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

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

Operating Leases

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

Construction and Development Projects

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

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

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

Other

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

The entire disclosure for commitments and contingencies.

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Notes to Consolidated Financial Statements [Abstract]

SEGMENT INFORMATION

3 Months Ended

Sep. 30, 2012

Segment Information

NOTE 11. SEGMENT INFORMATION

We have six separately managed reportable segments, as follows:

SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San 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 operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane systems, a natural gas distribution utility, electric generation facilities, including wind, and a terminal for the import of LNG and sale of natural gas in Mexico.
Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.
Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation plant, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States.

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

We evaluate each segment's performance based on its contribution to Sempra Energy's reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities' operations are based on rates set by the CPUC and the FERC.

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

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

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

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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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Sep. 30, 2012
Significant Accounting Policies
Investment Tax Credit Policy [Text Block]	Change in Accounting Principle Effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method for Sempra Energy. Under the flow-through method, we reduced our income tax expense by the amount of ITC in the year in which the qualifying assets were placed in service. Under the deferral method, we record ITC in the year when the qualifying assets are placed in service as a reduction to the cost of the asset that generated the ITC. This results in lower book depreciation over the life of the asset. This change has no historical or prospective impact on the California Utilities because ITC is effectively deferred as a result of the application of regulatory accounting required under GAAP. The flow-through method and the deferral method are both acceptable under GAAP, but the deferral method is the preferred method. We believe that the deferral method is preferable for the ITC we receive because it recognizes ITC benefits over the same periods as the associated costs for which the ITC are intended to compensate. We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented. Upon adopting the deferral method, we recorded an adjustment for the cumulative effect of the change in accounting principle to reduce Sempra Energy Consolidated retained earnings as of January 1, 2011 by $37 million.
Consolidation Variable Interest Entity Policy	VARIABLE INTEREST ENTITIES (VIE) We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess the purpose and design of the VIE; the nature of the VIE's risks and the risks we absorb; the power to direct activities that most significantly impact the economic performance of the VIE; and the obligation to absorb losses or right to receive benefits that could be significant to the VIE.
Goodwill And Intangible Assets Goodwill Policy	GOODWILL Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested annually on October 1 for impairment. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.
Earnings Per Share Policy Text Block	EARNINGS PER SHARE The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2012 and 2011. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized and minus tax shortfalls recognized are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method.
Derivatives Policy Text Block	NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not presented below. We record all derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows. In certain cases, we apply the normal purchase or sale exception to derivative accounting and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below. HEDGE ACCOUNTING We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that a given future revenue or expense item may vary, and other criteria. We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instruments results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria. ENERGY DERIVATIVES Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business. INTEREST RATE DERIVATIVES We are exposed to interest rates primarily as a result of our current and expected use of financing. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, which are typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. FOREIGN CURRENCY DERIVATIVES We are exposed to exchange rate movements primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts.
Legal Costs Policy Text Block	LEGAL PROCEEDINGS We accrue losses for legal proceedings when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverages and could materially adversely affect our business, cash flows, results of operations, and financial condition. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

Disclosure of accounting policy for consolidation to describe the significant judgments and assumptions made in determining whether a variable interest held by the entity requires the variable interest entity to be consolidated and (or) disclose information about its involvement with the variable interest entity; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; and the significant factors considered and judgments made in determining that the power to direct the activities that significantly impact the economic performance of the variable interest entity are shared (as defined).

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-Name FASB Interpretation (FIN)
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 24
-Subparagraph e
-Appendix D

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 22E
-Subparagraph a
-Appendix D

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 22B
-Subparagraph a
-Appendix D

Disclosure of accounting policy for its derivative instruments and hedging activities.

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-Name FASB Interpretation (FIN)
-Number 39
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph n
-Article 4

Disclosure of accounting policy for computing basic and diluted earnings or loss per share for each class of common stock and participating security. Addresses all significant policy factors, including any antidilutive items that have been excluded from the computation and takes into account stock dividends, splits and reverse splits that occur after the balance sheet date of the latest reporting period but before the issuance of the financial statements.

Schedule Of Effective Change In Accounting Principle [Text Block]

GENERAL (Tables)

3 Months Ended

Sep. 30, 2012

General (Tables) [Abstract]

EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
		Three months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Income tax expense		$	68	$	7	$	75
Net income			326		(7)		319
Earnings			296		(7)		289

Basic earnings per common share		$	1.23	$	(0.02)	$	1.21
Diluted earnings per common share		$	1.22	$	(0.02)	$	1.20

		Nine months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Depreciation and amortization		$	730	$	(1)	$	729
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			1,316		1		1,317
Income tax expense			269		20		289
Net income			1,092		(19)		1,073
Earnings			1,065		(19)		1,046

Basic earnings per common share		$	4.44	$	(0.08)	$	4.36
Diluted earnings per common share		$	4.40	$	(0.08)	$	4.32

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Net income		$	1,092	$	(19)	$	1,073
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization			730		(1)		729
Deferred income taxes and investment tax credits			224		(13)		211
Net change in other working capital components (income taxes)			(108)		33		(75)

		As of December 31, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
Property, plant and equipment		$	31,303	$	(111)	$	31,192
Less accumulated depreciation and amortization			(7,731)		4		(7,727)
Property, plant and equipment, net		$	23,572	$	(107)	$	23,465

Income taxes payable		$	16	$	(11)	$	5
Deferred income taxes, noncurrent liability			1,554		(34)		1,520
Deferred credits and other			773		1		774
Retained earnings(1)			8,225		(63)		8,162
(1)	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

RECENT INVESTMENT ACTIVITY (Tables)

3 Months Ended

Sep. 30, 2012

Recent Investment Activity (Tables) [Abstract]

Schedule of Business Acquisition Proforma Information Table

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

Tabular disclosure of pro forma results of operations for a material business acquisition or series of individually immaterial business acquisitions that are material in the aggregate.

Other Financial Data (Tables) [Abstract]

OTHER FINANCIAL DATA (Tables)

3 Months Ended

Sep. 30, 2012

Goodwill Table

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

Net Periodic Benefit Cost Table

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

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

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

Contributions to Benefit Plans Table

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

Earnings Per Share Computations Table

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011(1)		2012		2011(1)
Numerator:
Earnings/Income attributable to common shareholders		$	268	$	289	$	566	$	1,046

Denominator:
Weighted-average common shares
outstanding for basic EPS			241,689		239,545		241,133		239,693
Dilutive effect of stock options, restricted
stock awards and restricted stock units			4,113		2,335		3,880		2,262
Weighted-average common shares
outstanding for diluted EPS			245,802		241,880		245,013		241,955

Earnings per share:
Basic		$	1.11	$	1.21	$	2.35	$	4.36
Diluted		$	1.09	$	1.20	$	2.31	$	4.32
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

Total Shareholder Return Ranking Table

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

Capitalized Financing Costs Table

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

Income Tax Expense (Benefit) Associated with Other Comprehensive Income Table

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(7)		―		(7)		1		―		1
Financial instruments			(1)		―		(1)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	―	$	―	$	―

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

Shareholders' Equity and Noncontrolling Interests Table

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

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

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

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	16	$	2
Due from various affiliates			1		65
		$	17	$	67

Due to Sempra Energy		$	20	$	14

Income taxes due from Sempra Energy(1)		$	149	$	97

SoCalGas
Current:
Due from Sempra Energy		$	280	$	23
Due from various affiliates			―		17
		$	280	$	40

Due to SDG&E		$	16	$	2

Income taxes due from Sempra Energy(1)		$	15	$	17
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies’ having always filed a separate return.

Revenues From Unconsolidated Affiliates at SDG&E and SoCalGas Table

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
SDG&E	$	2	$	3	$	6	$	6
SoCalGas		17		13		48		38

Amounts Recorded For Transactions with RBS Sempra Commodities Table

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended September 30, 2011(1)		Nine months ended September 30, 2011(1)
Revenues:
Sempra Mexico		$	―	$	37
Sempra Natural Gas			―		7

Cost of natural gas:
Sempra Mexico		$	3	$	74
Sempra Natural Gas			―		3
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

Other Income and Expense Table

OTHER INCOME, NET
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	13	$	26	$	80	$	67
Investment gains (losses)(1)			17		(6)		27		13
Gains (losses) on interest rate and foreign exchange instruments, net			1		(26)		11		(14)
Regulatory interest, net(2)			―		―		1		1
Sundry, net			13		18		18		19
Total		$	44	$	12	$	137	$	86
SDG&E:
Allowance for equity funds used during construction		$	6	$	21	$	61	$	54
Regulatory interest, net(2)			―		―		1		1
Sundry, net			(1)		5		(3)		―
Total		$	5	$	26	$	59	$	55
SoCalGas:
Allowance for equity funds used during construction		$	7	$	5	$	19	$	13
Sundry, net			(1)		(2)		(5)		(4)
Total		$	6	$	3	$	14	$	9
(1)	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

Income Tax Expense and Effective Income Tax Rates Table

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

Variable Interest Entity Table

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011

Operating revenues
Electric	$	―	$	―	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		―		―		―
Operating expenses
Cost of electric fuel and purchased power		(26)		(29)		(66)		(55)
Operation and maintenance		4		1		15		23
Depreciation and amortization		7		7		19		20
Total operating expenses		(15)		(21)		(32)		(12)
Operating income		15		21		32		12
Other income (expense), net		―		4		(1)		―
Interest expense		(3)		(4)		(8)		(6)
Income before income taxes/Net income		12		21		23		6
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings	$	―	$	―	$	―	$	―

Ownership Interests Held By Others Table

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
		Percent Ownership Held by Others			September 30, 2012		December 31, 2011
Bay Gas Storage, Ltd.(1)		9	%	$	19	$	17
Southern Gas Transmission Company(1)		49			1		1
Liberty Gas Storage, LLC(1)		25			13		9
Tecsur		10			4		4
Luz del Sur		20			230		216
Chilquinta Energía subsidiaries		15 - 43			37		34
Otay Mesa VIE (at SDG&E)		100			90		102
Total Sempra Energy				$	394	$	383
(1)	Part of Sempra Natural Gas.

Schedule of Inventory

INVENTORY BALANCES
(Dollars in millions)

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

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Sep. 30, 2012

Derivative Financial Instruments (Tables) [Abstract]

Commodity Derivative Volumes Table


Segment and Commodity		September 30, 2012	December 31, 2011
California Utilities:
SDG&E:
Natural gas		23 million MMBtu	35 million MMBtu	(1)
Congestion revenue rights		18 million MWh	19 million MWh	(2)

Energy-Related Businesses:
Sempra Natural Gas:
Electric power		2 million MWh	5 million MWh
Natural gas		32 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

Notional Amounts of Interest Rate Derivatives Table

		September 30, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-347	2019		285-355	2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

Derivative Instruments on the Condensed Consolidated Balance Sheets Table

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2012
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	6	$	15	$	(20)	$	(69)
Commodity contracts not subject to rate recovery			―		―		(3)		―
Total		$	6	$	15	$	(23)	$	(69)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(68)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments		$	8	$	43	$	(8)	$	(38)
Commodity contracts not subject to rate recovery			119		19		(131)		(31)
Associated offsetting commodity contracts			(111)		(15)		111		15
Commodity contracts subject to rate recovery			9		20		(39)		(7)
Associated offsetting commodity contracts			(5)		(1)		5		1
Total		$	20	$	66	$	(62)	$	(60)
SDG&E:
Commodity contracts subject to rate recovery		$	7	$	20	$	(37)	$	(7)
Associated offsetting commodity contracts			(4)		(1)		4		1
Total		$	3	$	19	$	(33)	$	(6)
SoCalGas:
Commodity contracts subject to rate recovery		$	2	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(1)		―		1		―
Total		$	1	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	5	$	11	$	(17)	$	(65)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(65)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments		$	8	$	41	$	(7)	$	(36)
Commodity contracts not subject to rate recovery			156		72		(148)		(94)
Associated offsetting commodity contracts			(120)		(68)		120		68
Commodity contracts subject to rate recovery			28		8		(62)		(24)
Associated offsetting commodity contracts			(10)		(2)		10		2
Total		$	62	$	51	$	(87)	$	(84)
SDG&E:
Commodity contracts subject to rate recovery		$	22	$	8	$	(55)	$	(24)
Associated offsetting commodity contracts			(5)		(2)		5		2
Total		$	17	$	6	$	(50)	$	(22)
SoCalGas:
Commodity contracts subject to rate recovery		$	6	$	―	$	(7)	$	―
Associated offsetting commodity contracts			(5)		―		5		―
Total		$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

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

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain on derivatives recognized in earnings				Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	5	$	7
Interest rate instruments		Other Income, Net		4		13		6		16
Total(1)			$	5	$	15	$	11	$	23
SoCalGas:
Interest rate instrument		Interest Expense	$	―	$	―	$	―	$	1
Interest rate instrument		Other Income, Net		―		―		―		(3)
Total(1)			$	―	$	―	$	―	$	(2)
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

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

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

Undesignated Derivative Impact on the Condensed Consolidated Statements of Operations Table

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

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

Fair Value Measurements (Tables) [Abstract]

FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Sep. 30, 2012

Fair Value of Financial Instruments Table

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	16	$	―	$	―	$	46	$	46
Total long-term debt(2)			11,727		―		12,556		755		13,311
Preferred stock of subsidiaries			99		―		108		―		108
SDG&E:
Total long-term debt(3)		$	4,137	$	―	$	4,308	$	347	$	4,655
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,662	$	―	$	1,872	$	―	$	1,872
Preferred stock			22		―		24		―		24

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

Nuclear Decommissioning Trusts Table

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

Sales of Securities Table

SALES OF SECURITIES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Proceeds from sales	$	204	$	294	$	524	$	384
Gross realized gains		3		27		12		29
Gross realized losses		(1)		(8)		(6)		(10)

Fair Value of Cash Collateral Receivables Not Offset on the Condensed Consolidated Balance Sheets Table

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

Recurring Fair Value Measures Table

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Interest rate instruments			―		73		―		―		73
Commodity contracts subject to rate recovery			21		―		23		―		44
Commodity contracts not subject to rate recovery			19		19		―		―		38
Investments			1		―		―		―		1
Total		$	642	$	355	$	23	$	―	$	1,020
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	136	$	―	$	―	$	136
Commodity contracts subject to rate recovery			32		8		―		(32)		8
Commodity contracts not subject to rate recovery			9		30		―		(13)		26
Total		$	41	$	174	$	―	$	(45)	$	170

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Commodity contracts subject to rate recovery			19		―		23		―		42
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	622	$	263	$	23	$	―	$	908

Liabilities:
Interest rate instruments		$	―	$	85	$	―	$	―	$	85
Commodity contracts subject to rate recovery			32		7		―		(32)		7
Total		$	32	$	92	$	―	$	(32)	$	92

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826

Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

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

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Recurring Fair Value Measures Level 3 Rollforward Table

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

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

Non-Recurring Fair Value Measures Table

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated		Fair
		Fair		Value	% of Fair Value		Range of
		Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369	Market approach	Level 2	67%	Equity sale offer price	100%


			Probability weighted	Level 3	33%	Combined transportation rate assumption(1)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

SEGMENT INFORMATION (Tables)

3 Months Ended

Sep. 30, 2012

Segment Information (Tables) [Abstract]

Segment Information Table

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

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

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

Cumulative Effect of Change in Accounting Principle [Abstract]

GENERAL (DETAILS) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2008

Cumulative Effect of Change In Accounting Principle Of Reductions In Net Income And Earnings

$ 26

$ 30

$ 7

Retained Earnings Cumulative Effect Of Change In Accounting Principle Net Of Tax

$ 37

Change In Accounting Principle, As Originally Reported [Member]

Effect of Change in Accounting Principle [Line Items]

Change In Accounting Principle, Depreciation And Amortization

$ 730

Change In Accounting Principle, Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries

1,316

Change In Accounting Principle, Income Tax Expense

$ 68

269

Change In Accounting Principle, Net Income

326

1,092

Change In Accounting Principle, Earnings

$ 296

$ 1,065

Change In Accounting Principle, Basic Earnings Per Common Share

$ 1.23

$ 4.44

Change In Accounting Principle, Diluted Earnings Per Common Share

$ 1.22

$ 4.40

Change In Accounting Principle, Deferred Income Taxes And Invesment Tax Credits

$ 224

Change In Accounting Principle, Net Change In Other Working Capital Components (Income Taxes)

(108)

Change In Accounting Principle, Income Taxes Payable

Change In Accounting Principle, Deferred Credits And Other

773

Change In Accounting Principle, Deferred Income Taxes, Noncurrent Liability

1,554

Change In Accounting Principle, Property Plant And Equipment

31,303

Change In Accounting Principle, Less Accumulated Depreciation And Amortization

7,731

Change In Accounting Principle Property Plant And Equipment Net

23,572

Change In Accounting Principle, Retained Earnings

^[1]

8,225

Change In Accounting Principle, Adjustments [Member]

Effect of Change in Accounting Principle [Line Items]

Change In Accounting Principle, Depreciation And Amortization

(1)

Change In Accounting Principle, Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries

Change In Accounting Principle, Income Tax Expense

$ 7

Change In Accounting Principle, Net Income

(7)

(19)

Change In Accounting Principle, Earnings

$ (7)

$ (19)

Change In Accounting Principle, Basic Earnings Per Common Share

$ (0.02)

$ (0.08)

Change In Accounting Principle, Diluted Earnings Per Common Share

$ (0.02)

$ (0.08)

Change In Accounting Principle, Deferred Income Taxes And Invesment Tax Credits

$ (13)

Change In Accounting Principle, Net Change In Other Working Capital Components (Income Taxes)

Change In Accounting Principle, Income Taxes Payable

(11)

Change In Accounting Principle, Deferred Credits And Other

Change In Accounting Principle, Deferred Income Taxes, Noncurrent Liability

(34)

Change In Accounting Principle, Property Plant And Equipment

(111)

Change In Accounting Principle, Less Accumulated Depreciation And Amortization

(4)

Change In Accounting Principle Property Plant And Equipment Net

(107)

Change In Accounting Principle, Retained Earnings

^[1]

(63)

Change In Accounting Principle, Retrospectively Adjusted [Member]

Effect of Change in Accounting Principle [Line Items]

Change In Accounting Principle, Depreciation And Amortization

729

Change In Accounting Principle, Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries

1,317

Change In Accounting Principle, Income Tax Expense

$ 75

289

Change In Accounting Principle, Net Income

319

1,073

Change In Accounting Principle, Earnings

$ 289

$ 1,046

Change In Accounting Principle, Basic Earnings Per Common Share

$ 1.21

$ 4.36

Change In Accounting Principle, Diluted Earnings Per Common Share

$ 1.20

$ 4.32

Change In Accounting Principle, Deferred Income Taxes And Invesment Tax Credits

$ 211

Change In Accounting Principle, Net Change In Other Working Capital Components (Income Taxes)

$ (75)

Change In Accounting Principle, Income Taxes Payable

Change In Accounting Principle, Deferred Credits And Other

774

Change In Accounting Principle, Deferred Income Taxes, Noncurrent Liability

1,520

Change In Accounting Principle, Property Plant And Equipment

31,192

Change In Accounting Principle, Less Accumulated Depreciation And Amortization

7,727

Change In Accounting Principle Property Plant And Equipment Net

23,465

Change In Accounting Principle, Retained Earnings

^[1]

$ 8,162

[1]	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

RECENT INVESTMENT ACTIVITY 2 (DETAILS) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

May 20, 2012

Sep. 13, 2011

Apr. 06, 2011

^[1]

$ 277

Pro forma revenues

$ 2,576

7,775

Pro forma earnings

^[1]

289

794

^[2]

Willmut Gas [Member]

Revenue of acquiree since acquisition date

$ 17

Total liabilities

(10)

Goodwill

$ 10

$ 3

$ 5

Acquired percentage interest in joint venture

100.00%

South America Acquisition [Member]

Revenue of acquiree since acquisition date

356

345

1,100

706

Net Income of acquiree since acquisition date

155

108

Earnings of acquiree since acquisition date

$ 49

$ 52

$ 135

$ 92

Luz Del Sur [Member]

Ownership Percentage Before Acquisition

38.00%

Ownership percentage after Luz Del Sur tender offer

80.00%

Chilquinta Energia [Member]

Ownership Percentage Before Acquisition

50.00%

Acquired percentage interest in joint venture

100.00%

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Excludes the $277 million gain related to remeasurement of equity method investments.

INVESTMENTS IN UNCONSOLIDATED ENTITIES (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended			9 Months Ended
	Aug. 09, 2011	Apr. 15, 2011	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2011	Sep. 30, 2011
Investment In Joint Venture Disclosure [Abstract]
Distributions from RBS Sempra Commodities LLP	$ 98	$ 329
Investment in RBS Sempra Commodities LLP			$ 126
Pretax equity earnings (losses) from RBS Sempra Commodities LLP					$ (16)	$ (24)
Joint Venture Sales Of Businesses [Line Items]
Loss on impairment of RBS Sempra Commodities LLP					(16)	(16)
Loss on impairment of RBS Sempra Commodities LLP, after tax					$ (10)	$ (10)
Schedule of Equity Method Investments [Line Items]
Sempra Renewables' Equity Method Investments In Joint Ventures			296
Loss on impairment of investment in Rockies Express			100	$ 300
Loss on impairment of investment in Rockies Express, after tax			60	$ 179
Investment in Rockies Express			$ 369
Rockies Express [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage in equity method investee			25.00%
Ownership percentage of minority partner in equity method investee			25.00%
Ownership percentage of operating partner in equity method investee			50.00%
Flat Ridge 2 [Member]
Schedule of Equity Method Investments [Line Items]
Sempra Renewables' Equity Method Investments In Joint Ventures			$ 249

OTHER FINANCIAL DATA - U.S. Treasury Grants Receivable (Details) $ in Millions	Sep. 30, 2012 USD ($)
U S Treasury Grants Receivable Disclosure [Abstract]
U.S. Treasury grants receivable	$ 181

OTHER FINANCIAL DATA - VARIABLE INTEREST ENTITIES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Variable Interest Entities Disclosure [Abstract]
Secured debt of variable interest entity	$ 347		$ 347
Amounts Associated With Variable Interest Entities, Cost of Electric Fuel And Purchased Power	(26)	$ (29)	(66)	$ (55)
Amounts Associated With Variable Interest Entities, Operation And Maintenance	4	1	15	23
Amounts Associated With Variable Interest Entities, Depreciation And Amortization	7	7	19	20
Amounts Associated With Variable Interest Entities, Total Operating Expenses	(15)	(21)	(32)	(12)
Amounts Associated With Variable Interest Entities, Operating Income	15	21	32	12
Amounts Associated With Variable Interest Entities, Other Income (Expense), Net		4	(1)
Amounts Associated With Variable Interest Entities, Interest Expense	(3)	(4)	(8)	(6)
Amounts Associated With Variable Interest Entities, Net Income	12	21	23	6
Amounts Associated With Variable Interest Entities, (Earnings) Losses Attributable Noncontrolling Interests	$ (12)	$ (21)	$ (23)	$ (6)

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

9 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Goodwill by Segment, Sempra Energy Consolidated [Member]

Foreign currency translation

$ 1,036

^[1]

$ 63

Acquisition of subsidiary

Goodwill By Segment, Sempra South American Utilities [Member]

1,109

Foreign currency translation

949

^[1]

Goodwill By Segment, Sempra Mexico [Member]

1,012

Goodwill By Segment, Sempra Natural Gas [Member]

Acquisition of subsidiary

$ 62

$ 72

[1]	We record the offset of this fluctuation to other comprehensive income.

The increase (decrease) in the recorded value of goodwill for foreign currency translation adjustments and purchase accounting adjustments needed to revise the carrying amount of goodwill to fair value.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Earnings Per Share Numerator [Abstract]

OTHER FINANCIAL DATA - PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Southern California Gas Company [Member]
Remeasurement Due To Collective Bargaining Agreement [Line Items]
Discount Rate For Remeasurement			4.65%
Decrease In Recorded Liability From Remeasurement			$ 66
Pension Benefits
Net Periodic Benefit Cost
Service cost	$ 23	$ 20	68	$ 63
Interest cost	40	41	122	126
Expected return on assets	(38)	(36)	(116)	(109)
Amortization of prior service cost		1	2	3
Amortization of actuarial loss	12	8	35	26
Settlement	1	1	8	11
Regulatory adjustment	9	31	(9)	6
Total net periodic benefit cost	47	66	110	126
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			111
Expected contributions to pension and other postretirement benefit plans	123		123
Pension Benefits \| San Diego Gas and Electric Company and Subsidiary [Member]
Net Periodic Benefit Cost
Service cost	7	6	21	21
Interest cost	11	12	34	37
Expected return on assets	(11)	(10)	(35)	(35)
Amortization of prior service cost			1	1
Amortization of actuarial loss	4	2	11	7
Settlement	(1)		1	1
Regulatory adjustment	7	15	7	13
Total net periodic benefit cost	17	25	40	45
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			36
Expected contributions to pension and other postretirement benefit plans	45		45
Pension Benefits \| Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	13	10	40	34
Interest cost	24	24	74	74
Expected return on assets	(23)	(21)	(72)	(64)
Amortization of prior service cost		1	1	2
Amortization of actuarial loss	6	4	17	12
Settlement			1	1
Regulatory adjustment	2	16	(16)	(7)
Total net periodic benefit cost	22	34	45	52
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			45
Expected contributions to pension and other postretirement benefit plans	47		47
Other Postretirement Benefits
Net Periodic Benefit Cost
Service cost	4	8	19	23
Interest cost	11	16	39	49
Expected return on assets	(13)	(12)	(40)	(36)
Amortization of prior service cost			(2)
Amortization of actuarial loss	2	4	9	13
Regulatory adjustment	3	2	8	6
Total net periodic benefit cost	7	18	33	55
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			32
Expected contributions to pension and other postretirement benefit plans	41		41
Other Postretirement Benefits \| San Diego Gas and Electric Company and Subsidiary [Member]
Net Periodic Benefit Cost
Service cost	1	1	5	5
Interest cost	2	2	6	7
Expected return on assets	(1)	(1)	(5)	(5)
Amortization of prior service cost	1	1	3	3
Regulatory adjustment	1	1	2	2
Total net periodic benefit cost	4	4	11	12
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			10
Expected contributions to pension and other postretirement benefit plans	13		13
Other Postretirement Benefits \| Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	2	7	12	17
Interest cost	9	12	31	39
Expected return on assets	(10)	(10)	(33)	(30)
Amortization of prior service cost	(1)	(1)	(5)	(3)
Amortization of actuarial loss	1	4	8	13
Regulatory adjustment	2	1	6	4
Total net periodic benefit cost	3	$ 13	19	$ 40
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			19
Expected contributions to pension and other postretirement benefit plans	$ 23		$ 23

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Earnings Per Share Denominator [Abstract]

$ 268

$ 289

^[1]

$ 566

$ 1,046

^[1]

Weighted-average common shares outstanding for basic EPS

241,689,000

239,545,000

^[1]

241,133,000

239,693,000

^[1]

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

4,113,000

2,335,000

^[1]

3,880,000

2,262,000

^[1]

Weighted-average common shares outstanding for diluted EPS

245,802,000

241,880,000

^[1]

245,013,000

241,955,000

^[1]

Earnings Per Share [Abstract]

Basic earnings per common share

$ 1.11

$ 1.21

^[1]

$ 2.35

$ 4.36

^[1]

Diluted earnings per common share

$ 1.09

$ 1.20

^[1]

$ 2.31

$ 4.32

^[1]

Seventy Fifth Percentile Or Above [Member]

Total Shareholder Return Ranking [Line Items]

Common Shares Received For Each Restricted Stock Unit

^[2]

1.5

Fiftieth Percentile [Member]

Total Shareholder Return Ranking [Line Items]

Common Shares Received For Each Restricted Stock Unit

^[2]

Thirty Fifth Percentile Or Below [Member]

Total Shareholder Return Ranking [Line Items]

Common Shares Received For Each Restricted Stock Unit

^[2]

Restricted Stock Units [Member]

Schedule Of Performance Based Restricted Shares [Line Items]

Contractual vesting percentage maximum

150.00%

Restricted Stock Awards [Member]

Schedule Of Performance Based Restricted Shares [Line Items]

Contractual vesting percentage maximum

100.00%

San Diego Gas and Electric Company and Subsidiary [Member]

Earnings Per Share Numerator [Abstract]

$ 176

$ 115

$ 378

$ 277

Earnings Per Share Numerator [Abstract]

Out Of The Money Stock Options [Member]

$ 71

$ 81

$ 191

$ 209

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

Antidilutive securities excluded from computation of earnings per share

2,112,880

40,000

2,111,839

In The Money Stock Options

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

Antidilutive securities excluded from computation of earnings per share

900

Restricted Stock

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

Antidilutive securities excluded from computation of earnings per share

2,349,338

3,473,578

2,523,343

3,630,253

Restricted Stock Units

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

Antidilutive securities excluded from computation of earnings per share

3,387

1,109

1,881

Restricted Stock Awards [Member]

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

Antidilutive securities excluded from computation of earnings per share

14,319

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	(2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

OTHER FINANCIAL DATA - COMMON STOCK REPURCHASE PROGRAM (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010
Share Repurchases [Abstract]
Prepayment for shares to be repurchased under Collared Accelerated Share Acquisition Program			$ 500
Accelerated Share Repurchases, Initial Share Delivery			5,670,006
Accelerated Share Repurchases, Interim Share Delivery	1,496,435	2,407,994
Accelerated Share Repurchases, Total Share Delivery	9,574,435
Accelerated Share Repurchases Final Price Paid Per Share	$ 52.22

OTHER FINANCIAL DATA - PREFERRED STOCK (Details)	Jun. 30, 2011 USD ($)
Preferred Stock (Details) [Abstract]
Preferred stock redeemed	$ 81,000,000
Preferred stock redemption price per share, minimum	100
Preferred stock redemption price per share, maximum	101.50
Accrued preferred stock dividends at redemption date	$ 1,000,000

OTHER FINANCIAL DATA - SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Share-based compensation expense, net of income taxes	$ 5	$ 7	$ 18	$ 20
Restricted stock units granted			927,734
Restricted stock awards granted			18,487

Represents the expense recognized during the period arising from equity-based compensation arrangements (for example, shares of stock, unit, stock options or other equity instruments) with employees, directors and certain consultants qualifying for treatment as employees.

Comprehensive Income And Equity Disclosure [Line Items]

OTHER FINANCIAL DATA - CAPITALIZED FINANCING COSTS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	$ 5	$ 10	$ 32	$ 27
AFUDC related to equiity	13	26	80	67
Other capitalized financing costs	13	6	40	20
Total capitalized financing costs	31	42	152	114
San Diego Gas and Electric Company and Subsidiary [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	3	8	26	22
AFUDC related to equiity	6	21	61	54
Total capitalized financing costs	9	29	87	76
Southern California Gas Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	2	2	6	5
AFUDC related to equiity	7	5	19	13
Total capitalized financing costs	$ 9	$ 7	$ 25	$ 18

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

$ 10,178

^[1],[2]

$ 9,201

$ 290

$ 319

^[1]

615

1,073

^[1]

Reclassification to net income of foreign currency translation adjustments related to equity method investments

(139)

^[1]

125

(110)

^[1]

^[1],[3]

(54)

(7)

(39)

^[1]

(22)

(52)

^[1]

Purchase of noncontrolling interest in subsidiary

(10)

^[1]

(5)

^[1]

(43)

Share-based compensation expense

Common stock dividends declared

(435)

(346)

Repurchases of common stock

(2)

(1)

^[1]

(5)

(6)

^[1]

Issuance of common stock

(16)

(18)

Acquisition of South American entities

279

Redemption of preferred stock of subidiary

(80)

Common stock released from ESOP

(36)

(9)

Other Comprehensive Income (Loss), Tax [Abstract]

10,496

9,928

10,496

9,928

Financial instruments, income tax expense (benefit)

(1)

(11)

(5)

(11)

Net actuarial gain, income tax expense (benefit)

(1)

(7)

(4)

Ownership Interests Held By Others [Line Items]

San Diego Gas and Electric Company and Subsidiary [Member]

394

$ 383

Comprehensive Income And Equity Disclosure [Line Items]

3,841

^[2]

3,221

188

136

401

283

(4)

(25)

(13)

(34)

(2)

(4)

Capital contribution

200

(22)

4,203

3,673

4,203

3,673

Comprehensive Income And Equity Disclosure [Line Items]

2,193

191

209

(1)

Other Comprehensive Income (Loss), Tax [Abstract]

2,234

Financial instruments, income tax expense (benefit)

Total Shareholders' Equity

Comprehensive Income And Equity Disclosure [Line Items]

9,775

8,990

270

290

^[1]

571

1,052

^[1]

Reclassification to net income of foreign currency translation adjustments related to equity method investments

(132)

^[1]

114

(109)

^[1]

^[1],[3]

(54)

(3)

(14)

^[1]

(9)

(18)

^[1]

Purchase of noncontrolling interest in subsidiary

(10)

^[1]

(5)

^[1]

(4)

Share-based compensation expense

Common stock dividends declared

(435)

(346)

Repurchases of common stock

(2)

(1)

^[1]

(5)

(6)

^[1]

Issuance of common stock

(16)

(18)

Common stock released from ESOP

Other Comprehensive Income (Loss), Tax [Abstract]

10,082

9,574

10,082

9,574

Financial instruments, income tax expense (benefit)

^[4]

(1)

(11)

(5)

(11)

Net actuarial gain, income tax expense (benefit)

^[4]

(1)

^[4]

(7)

(4)

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

Comprehensive Income And Equity Disclosure [Line Items]

3,739

3,108

176

115

378

277

(4)

Capital contribution

200

Total Shareholders' Equity | Southern California Gas Company [Member]

4,113

3,582

4,113

3,582

Other Comprehensive Income (Loss), Tax [Abstract]

Financial instruments, income tax expense (benefit)

^[4]

Noncontrolling Interests

Comprehensive Income And Equity Disclosure [Line Items]

403

211

^[1]

(7)

^[1]

(1)

^[1]

Purchase of noncontrolling interest in subsidiary

(4)

(25)

^[1]

(13)

(34)

^[1]

(39)

Acquisition of South American entities

279

Redemption of preferred stock of subidiary

(80)

(36)

(9)

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

414

354

414

354

Comprehensive Income And Equity Disclosure [Line Items]

102

113

(4)

(25)

(13)

(34)

(22)

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

$ 90

$ 91

$ 90

$ 91

Ownership Interests Held By Others [Line Items]

^[5]

9.00%

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

^[5]

$ 19

Ownership Interests Held By Others [Line Items]

^[5]

49.00%

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

^[5]

$ 1

Ownership Interests Held By Others [Line Items]

^[5]

25.00%

Ownership Interests Held By Others, Tecsur [Member]

^[5]

$ 13

Ownership Interests Held By Others [Line Items]

10.00%

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

$ 4

Ownership Interests Held By Others [Line Items]

20.00%

Ownership Interests Held By Others, Chilquinta Energia [Member]

$ 230

216

Ownership Interests Held By Others [Line Items]

Percent of ownership held by others, minimum

15.00%

Percent of ownership held by others, maximum

43.00%

Ownership Interests Held By Others, Otay Mesa VIE [Member]

$ 37

Ownership Interests Held By Others [Line Items]

100.00%

Transactions With Affiliates Disclosure [Line Items]

$ 90

$ 102

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Derived from audited financial statements.
[3]	Related to the acquisition of Chilquinta Energía and Luz del Sur.
[4]	Shareholders’ equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.
[5]	Part of Sempra Natural Gas.

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

San Diego Gas and Electric Company and Subsidiary [Member]

$ 0

Transactions With Affiliates Disclosure [Line Items]

Due to affiliate, current

$ 67

Revenues from unconsolidated affiliates

$ 3

$ 6

Transactions With Affiliates Disclosure [Line Items]

Revenues from unconsolidated affiliates

280

$ 17

Affiliate Of Investee [Member] | Parent Company Member

Transactions With Affiliates Disclosure [Line Items]

Interest rate on due from affiliate, noncurrent

7.41%

Loan to unconsolidated affiliate, principal

$ 18

Loan to unconsolidated affiliate, accrued interest

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

Transactions With Affiliates Disclosure [Line Items]

Income taxes due from (to) Sempra Energy

^[1]

149

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

Transactions With Affiliates Disclosure [Line Items]

Income taxes due from (to) Sempra Energy

280

^[1]

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

Transactions With Affiliates Disclosure [Line Items]

Due to affiliate, current

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

Transactions With Affiliates Disclosure [Line Items]

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

Transactions With Affiliates Disclosure [Line Items]

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

$ 1

Transactions With Affiliates Disclosure [Line Items]

$ 17

Transactions With Joint Venture [Line Items]

Revenues from transactions with RBS Sempra Commodities

Cost of natural gas from transactions with RBS Sempra Commodities

Transactions With Joint Venture [Line Items]

Revenues from transactions with RBS Sempra Commodities

$ 0

Cost of natural gas from transactions with RBS Sempra Commodities

$ 3

[1]	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies’ having always filed a separate return.

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Component of Other Income, Nonoperating [Line Items]

San Diego Gas and Electric Company and Subsidiary [Member]

$ 44

$ 12

^[1]

$ 137

$ 86

^[1]

Component of Other Income, Nonoperating [Line Items]

Component of Other Income, Nonoperating [Line Items]

Allowance for Cost of Equity Funds Used During Construction [Member]

Component of Other Income, Nonoperating [Line Items]

Allowance for Cost of Equity Funds Used During Construction [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

Component of Other Income, Nonoperating [Line Items]

Allowance for Cost of Equity Funds Used During Construction [Member] | Southern California Gas Company [Member]

Component of Other Income, Nonoperating [Line Items]

Regulatory Interest, Net [Member]

Component of Other Income, Nonoperating [Line Items]

Regulatory Interest, Net [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

^[2]

Component of Other Income, Nonoperating [Line Items]

Gains (losses) on interest rate and foreign exchange instruments [Member]

^[2]

Component of Other Income, Nonoperating [Line Items]

Gain (Loss) on Investments [Member]

(26)

(14)

Component of Other Income, Nonoperating [Line Items]

Other Income, Sundry [Member]

^[3]

(6)

Component of Other Income, Nonoperating [Line Items]

Other Income, Sundry [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

Component of Other Income, Nonoperating [Line Items]

Other Income, Sundry [Member] | Southern California Gas Company [Member]

(1)

(3)

Component of Other Income, Nonoperating [Line Items]

Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]

$ (1)

$ (2)

$ (5)

$ (4)

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Interest on regulatory balancing accounts.
[3]	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Income tax expense (benefit)

$ 49

$ 75

^[1]

$ 48

$ 289

^[1]

Effective income tax rate

15.00%

19.00%

8.00%

22.00%

Income tax benefit associated with life insurance contracts

^[1]

$ 277

$ 54

Income tax benefit for repair allowance

$ 38

Income tax benefit for repair allowance related to 2011

San Diego Gas and Electric Company and Subsidiary [Member]

Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]

Income tax expense (benefit)

$ 38

$ 63

$ 151

$ 154

Effective income tax rate

17.00%

32.00%

27.00%

35.00%

Income tax benefit for repair allowance

$ 38

Income tax benefit for repair allowance related to 2011

Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]

Income tax expense (benefit)

$ 37

$ 41

$ 105

$ 106

Effective income tax rate

34.00%

35.00%

34.00%

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

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

Sep. 30, 2012

Dec. 31, 2011

$ 239

$ 195

159

151

398

346

^[1],[2]

S D G E Segment [Member]

So Cal Gas Segment [Member]

142

128

Sempra South American Utilities Segment [Member]

166

151

Schedule Of Commodity Derivative Volumes [Line Items]

$ 94

$ 60

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Derived from audited financial statements.

DEBT AND CREDIT FACILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2012	Dec. 31, 2011
Line Of Credit Facility, Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 4,100
Committed lines of credit, remaining borrowing capacity	$ 3,500
Weighted average interest rate on total short-term debt outstanding	0.82%	0.93%
Line Of Credit Facility, Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 1,067
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, capacity for issuance of letters of credit	$ 700
Other instruments supported by committed lines of credit	47
Line Of Credit Facility, Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 2,189
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Outstanding commercial paper supported by committed lines of credit	$ 545
Commercial paper noncurrent		$ 400
Line Of Credit Facility, S D G E [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	$ 656
Outstanding commercial paper supported by committed lines of credit	$ 2
Weighted average interest rate on total short-term debt outstanding	0.20%
Line Of Credit Facility, So Cal Gas [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	$ 658
Line Of Credit Facility, California Utilities Combined [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	877
Committed lines of credit, capacity for issuance of letters of credit	$ 200

DEBT AND CREDIT FACILITIES 2 (Details) $ in Millions	Sep. 30, 2012 USD ($)
Other Long Term Debt, Fixed Rate Due 2017 [Member] \| Sempra Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 600
Debt Instrument, Interest Rate, Stated Percentage	2.30%
Other Long Term Debt, Fixed Rate Due 2017 [Member] \| Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 21
Debt Instrument, Interest Rate, Stated Percentage	5.97%
Other Long Term Debt, Fixed Rate Due 2042 [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 250
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Other Long Term Debt, Fixed Rate Due 2042 [Member] \| Southern California Gas Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 350
Debt Instrument, Interest Rate, Stated Percentage	3.75%
Other Long Term Debt, Floating Rate Due 2028 [Member] \| Copper Mountain Solar I [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 117
Debt Instrument, Interest Rate, Stated Percentage	4.54%
Debt Instrument, Interest Rate At Period End	2.86%
Debt Instrument, Floating To Fixed Interest Rate Swap	$ 88
Other Long Term Debt, Fixed Rate Due 2022 [Member] \| Sempra Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 500
Debt Instrument, Interest Rate, Stated Percentage	2.875%
Other Long Term Debt, Fixed Rate Due 2018 [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 161
Debt Instrument, Interest Rate, Stated Percentage	1.65%
Other Long Term Debt, Fixed Rate Due 2039 [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 75
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Other Long Term Debt, Fixed Rate Due February 2019 [Member] \| Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 9
Debt Instrument, Interest Rate, Stated Percentage	6.34%
Other Long Term Debt, Fixed Rate Due July 2019 [Member] \| Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 25
Debt Instrument, Interest Rate, Stated Percentage	5.44%

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

Sep. 30, 2012

Dec. 31, 2011

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]

Schedule Of Commodity Derivative Volumes [Line Items]

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

^[1]

Schedule Of Commodity Derivative Volumes [Line Items]

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

^[1]

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

^[2]

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

DERIVATIVE FINANCIAL INSTRUMENTS 2 (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]

Notional amount of interest rate derivatives, minimum

^[1]

$ 6

$ 15

Notional amount of interest rate derivatives, maximum

^[1]

$ 369

$ 305

Maturities of interest rate derivatives, minimum

^[1]

2013

Maturities of interest rate derivatives, maximum

^[1]

2028

2019

San Diego Gas and Electric Company and Subsidiary [Member]

Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]

Notional amount of interest rate derivatives, minimum

^[1]

$ 285

Notional amount of interest rate derivatives, maximum

^[1]

$ 347

$ 355

Maturities of interest rate derivatives

^[1]

2019

[1]	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

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

Sep. 30, 2012

Dec. 31, 2011

Fixed Price Contracts And Other Derivatives, Current Assets [Member]

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

Interest rate instruments designated as hedging instruments

^[1],[2]

$ 6

$ 5

Total derivatives designated as hedging instruments

^[1]

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

Interest rate interest rate instruments not designated as hedging instruments

^[1]

^[1]

Commodity contracts not subject to rate recovery not designated as hedging instruments

^[1]

119

156

Associated offsetting commodity contracts not subject to rate recovery

^[1]

(111)

(120)

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

(5)

(10)

Total derivatives not designated as hedging instruments

^[1]

Fixed Price Contracts And Other Derivatives, Current Assets [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

(4)

(5)

Total derivatives not designated as hedging instruments

^[1]

Fixed Price Contracts And Other Derivatives, Current Assets [Member] | Southern California Gas Company [Member]

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[1]

Associated offsetting commodity contracts subject to rate recovery

^[1]

(1)

(5)

Total derivatives not designated as hedging instruments

^[1]

Fixed Price Contracts And Other Derivatives, Noncurrent Assets [Member]

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

Interest rate instruments designated as hedging instruments

^[2]

Total derivatives designated as hedging instruments

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

Interest rate interest rate instruments not designated as hedging instruments

Commodity contracts not subject to rate recovery not designated as hedging instruments

Associated offsetting commodity contracts not subject to rate recovery

(15)

(68)

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

Associated offsetting commodity contracts subject to rate recovery

(1)

(2)

Total derivatives not designated as hedging instruments

Fixed Price Contracts And Other Derivatives, Noncurrent Assets [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

Associated offsetting commodity contracts subject to rate recovery

(1)

(2)

Total derivatives not designated as hedging instruments

Fixed Price Contracts And Other Derivatives, Current Liabilities [Member]

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

Interest rate instruments designated as hedging instruments

^[2],[3]

(20)

(17)

Derivative commodity contracts not subject to rate recovery designated as hedging instruments

^[3]

(3)

Total derivatives designated as hedging instruments

^[3]

(23)

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

Interest rate interest rate instruments not designated as hedging instruments

^[3]

(8)

^[3]

(7)

Commodity contracts not subject to rate recovery not designated as hedging instruments

^[3]

(131)

(148)

Associated offsetting commodity contracts not subject to rate recovery

^[3]

111

120

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[3]

(39)

(62)

Associated offsetting commodity contracts subject to rate recovery

^[3]

Total derivatives not designated as hedging instruments

^[3]

(62)

(87)

Fixed Price Contracts And Other Derivatives, Current Liabilities [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

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

Interest rate instruments designated as hedging instruments

^[2],[3]

(17)

(16)

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[3]

(37)

(55)

Associated offsetting commodity contracts subject to rate recovery

^[3]

Total derivatives not designated as hedging instruments

^[3]

(33)

(50)

Fixed Price Contracts And Other Derivatives, Current Liabilities [Member] | Southern California Gas Company [Member]

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

^[3]

(2)

(7)

Associated offsetting commodity contracts subject to rate recovery

^[3]

Total derivatives not designated as hedging instruments

^[3]

(1)

(2)

Fixed Price Contracts And Other Derivatives, Noncurrent Liabilities [Member]

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

Interest rate instruments designated as hedging instruments

^[2]

(69)

(65)

Total derivatives designated as hedging instruments

(69)

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

Interest rate interest rate instruments not designated as hedging instruments

(38)

(36)

Commodity contracts not subject to rate recovery not designated as hedging instruments

(31)

(94)

Associated offsetting commodity contracts not subject to rate recovery

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

(7)

(24)

Associated offsetting commodity contracts subject to rate recovery

Total derivatives not designated as hedging instruments

(60)

(84)

Fixed Price Contracts And Other Derivatives, Noncurrent Liabilities [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

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

Interest rate instruments designated as hedging instruments

^[2]

(68)

(65)

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

Derivative commodity contracts subject to rate recovery not designated as hedging instruments

(7)

(24)

Associated offsetting commodity contracts subject to rate recovery

Total derivatives not designated as hedging instruments

$ (6)

$ (22)

[1]	Included in Current Assets: Other for SoCalGas.
[2]	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
[3]	Included in Current Liabilities: Other for SoCalGas.

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Cash Flow Hedges

Derivative Instruments, Gain (Loss) [Line Items]

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

$ (15)

$ (48)

$ (36)

$ (66)

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

(7)

(9)

(3)

Cash Flow Hedges | Interest Expense | Interest Rate Instruments

Derivative Instruments, Gain (Loss) [Line Items]

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

^[1]

(6)

(21)

(32)

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

^[1]

(3)

(5)

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

Derivative Instruments, Gain (Loss) [Line Items]

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

^[1]

(6)

(21)

(16)

(32)

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

^[1]

(2)

(3)

Cash Flow Hedges | Interest Expense | Interest Rate Instruments | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

(1)

(2)

(3)

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

Derivative Instruments, Gain (Loss) [Line Items]

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

(6)

(27)

(12)

(34)

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

(4)

(2)

(4)

(3)

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

Derivative Instruments, Gain (Loss) [Line Items]

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

(3)

Fair Value Hedges

Derivative Instruments, Gain (Loss) [Line Items]

Fair Value Hedges | Southern California Gas Company [Member]

^[2]

Derivative Instruments, Gain (Loss) [Line Items]

Fair Value Hedges | Interest Expense | Interest Rate Instruments

^[2]

(2)

Derivative Instruments, Gain (Loss) [Line Items]

Fair Value Hedges | Interest Expense | Interest Rate Instruments | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

Derivative Instruments, Gain (Loss) [Line Items]

Fair Value Hedges | Other Income, Net | Interest Rate Instruments | Southern California Gas Company [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Derivative Instruments, Gain (Loss) [Line Items]

(3)

Undesignated Derivatives

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

(40)

(2)

Derivative Instruments, Gain (Loss) [Line Items]

Undesignated Derivatives | Southern California Gas Company [Member]

(16)

(6)

Derivative Instruments, Gain (Loss) [Line Items]

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

(3)

(1)

Derivative Instruments, Gain (Loss) [Line Items]

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

(26)

(14)

Derivative Instruments, Gain (Loss) [Line Items]

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

(5)

(3)

Derivative Instruments, Gain (Loss) [Line Items]

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

Derivative Instruments, Gain (Loss) [Line Items]

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

(15)

(6)

Derivative Instruments, Gain (Loss) [Line Items]

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

(15)

(6)

Derivative Instruments, Gain (Loss) [Line Items]

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

Derivative Instruments, Gain (Loss) [Line Items]

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

(1)

Derivative Instruments, Gain (Loss) [Line Items]

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

$ 1

(1)

Derivative Instruments, Gain (Loss) [Line Items]

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

(2)

(1)

Derivative Instruments, Gain (Loss) [Line Items]

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

$ (2)

$ (1)

[1]	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.
[2]	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

DERIVATIVE FINANCIAL INSTRUMENTS 5 (Details) $ in Millions	3 Months Ended
DERIVATIVE FINANCIAL INSTRUMENTS 5 (Details) $ in Millions	Sep. 30, 2012 USD ($)
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ (18)
Maximum length of time hedged in cash flow hedge	17
Joint Venture Maximum Length Of Time Hedged In Cash Flow Hedge	18
Cash flow hedge ineffectiveness	$ 1
San Diego Gas and Electric Company and Subsidiary [Member]
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ (8)
Maximum length of time hedged in cash flow hedge	7
Southern California Gas Company [Member]
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ (1)

DERIVATIVE FINANCIAL INSTRUMENTS 6 (Details) $ in Millions	Sep. 30, 2012 USD ($)
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	$ 11
Additional Collateral Aggregate Fair Value	11
San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	6
Additional Collateral Aggregate Fair Value	$ 6

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

$ 585

$ 562

311

248

(4)

(6)

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

892

804

Proceeds from sales

204

$ 294

524

$ 384

Gross realized gains

Gross realized losses

(1)

$ (8)

(6)

$ (10)

Total Debt Securities

308

305

(1)

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

335

325

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

134

^[1]

134

^[1]

157

^[1]

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

146

^[1]

146

^[1]

170

Municipal Bonds

^[2]

^[2]

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

^[2]

Other Debt Securities

114

^[3]

114

^[3]

^[3]

(1)

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

123

^[3]

123

^[3]

Equity Securities

249

246

284

227

(4)

(5)

Cash And Cash Equivalents

529

468

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

$ 28

$ 11

[1]	Maturity dates are 2013-2042
[2]	Maturity dates are 2012-2057
[3]	Maturity dates are 2013-2111

FAIR VALUE MEASUREMENTS 2 (Details) - USD ($) $ in Millions	Sep. 30, 2012	Dec. 31, 2011
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	$ 46	$ 20
San Diego Gas and Electric Company and Subsidiary [Member]
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	20	10
Southern California Gas Company [Member]
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	$ 4	$ 2

FAIR VALUE MEASUREMENTS 3 (Details) - USD ($)
$ in Millions

Sep. 30, 2012

Dec. 31, 2011

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

$ 529

$ 468

146

170

Nuclear decomissioning trusts - Municipal debt securities

Nuclear decommissioning trusts - Other debt securities

123

Nuclear decommissioning trusts - Total debt securities

335

325

Interest rate instruments, assets

^[1]

864

793

Commodity contracts subject to rate recovery, assets

Commodity contracts not subject to rate recovery, assets

Investments

Total fair value of assets measured on a recurring basis

1,020

946

Commodity contracts subject to rate recovery, liabilities

136

125

Commodity contracts not subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

170

187

San Diego Gas and Electric Company and Subsidiary [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

529

468

146

170

Nuclear decomissioning trusts - Municipal debt securities

Nuclear decommissioning trusts - Other debt securities

123

Nuclear decommissioning trusts - Total debt securities

335

325

Commodity contracts subject to rate recovery, assets

^[1]

864

793

Commodity contracts not subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

908

826

Commodity contracts subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, assets

Commodity contracts not subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

Commodity contracts subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

Level 1

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

529

468

Nuclear decommissioning trusts - Total debt securities

Commodity contracts subject to rate recovery, assets

^[1]

601

560

Commodity contracts not subject to rate recovery, assets

Investments

Total fair value of assets measured on a recurring basis

642

590

Commodity contracts subject to rate recovery, liabilities

Commodity contracts not subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

529

468

Nuclear decommissioning trusts - Total debt securities

Commodity contracts subject to rate recovery, assets

^[1]

601

560

Commodity contracts not subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

622

570

Commodity contracts subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

Level 1 | Southern California Gas Company [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, assets

Commodity contracts not subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

Level 2

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Nuclear decomissioning trusts - Municipal debt securities

Nuclear decommissioning trusts - Other debt securities

123

Nuclear decommissioning trusts - Total debt securities

263

233

Interest rate instruments, assets

^[1]

263

233

Commodity contracts subject to rate recovery, assets

Commodity contracts not subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

355

335

Commodity contracts subject to rate recovery, liabilities

136

124

Commodity contracts not subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

174

189

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Nuclear decomissioning trusts - Municipal debt securities

Nuclear decommissioning trusts - Other debt securities

123

Nuclear decommissioning trusts - Total debt securities

263

233

Total fair value of assets measured on a recurring basis

^[1]

263

233

263

233

Commodity contracts subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

Level 2 | Southern California Gas Company [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

Commodity contracts subject to rate recovery, liabilities

Total fair value of liabilities measured on a recurring basis

Level 3

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, assets

Total fair value of assets measured on a recurring basis

Collateral Netted [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts not subject to rate recovery, assets

(2)

Total fair value of assets measured on a recurring basis

(2)

Commodity contracts subject to rate recovery, liabilities

(32)

(61)

Commodity contracts not subject to rate recovery, liabilities

(13)

(4)

Total fair value of liabilities measured on a recurring basis

(45)

(65)

Collateral Netted [Member] | San Diego Gas and Electric Company and Subsidiary [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commodity contracts subject to rate recovery, liabilities

(32)

(61)

Total fair value of liabilities measured on a recurring basis

$ (32)

$ (61)

[1]	Excludes cash balances and cash equivalents.

FAIR VALUE MEASUREMENTS 4 (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
FAIR VALUE MEASUREMENTS 4 (Details) - USD ($) $ in Millions	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 13	$ 3	$ 23	$ 2
Realized and unrealized gains (losses)	16	5	23	17
Allocated transmission instruments	17		18	2
Settlements	(23)	(5)	(41)	(18)
Balance at end of period	23	$ 3	23	$ 3
CRR Auction Rate Per MWh, Minimum	(3)		(3)
CRR Auction Rate Per MWh, Maximum	$ 5		$ 5

FAIR VALUE MEASUREMENTS 5 (Details) - USD ($)
$ in Millions

Sep. 30, 2012

Dec. 31, 2011

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

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

$ 1

$ 5

Level 1

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

Carrying Amount

Fair value of financial instruments, Total long-term debt

^[1]

^[2]

11,727

9,826

Preferred Stock Of Subsidiaries Fair Value Disclosure

Debt Instrument Unamortized Discount

Capital Lease Obligations

192

204

Commercial Paper Noncurrent

400

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

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

Fair value of financial instruments, Total long-term debt

^[3]

4,137

3,895

Contingently Redeemable Preferred Stock Fair Value Disclosure

Debt Instrument Unamortized Discount

Capital Lease Obligations

187

193

Carrying Amount | Southern California Gas Company [Member]

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

Fair value of financial instruments, Total long-term debt

^[4]

1,662

1,313

Preferred Stock 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]

13,311

11,047

Preferred Stock Of Subsidiaries Fair Value Disclosure

108

106

Fair Value | Level 2

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

Fair value of financial instruments, Total long-term debt

^[2]

12,556

10,447

Preferred Stock Of Subsidiaries Fair Value Disclosure

108

106

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]

755

600

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

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

Fair value of financial instruments, Total long-term debt

^[3]

4,655

4,288

Contingently Redeemable Preferred Stock Fair Value Disclosure

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

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

Fair value of financial instruments, Total long-term debt

^[3]

4,308

3,933

Contingently Redeemable Preferred Stock Fair Value Disclosure

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

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

Fair value of financial instruments, Total long-term debt

^[3]

347

355

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]

1,872

1,506

Preferred Stock 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]

1,872

1,506

Preferred Stock Fair Value Disclosure

$ 24

$ 23

[1]	We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
[2]	Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
[3]	Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.
[4]	Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

FAIR VALUE MEASUREMENTS 6 (Details)
$ in Millions

3 Months Ended

Sep. 30, 2012

USD ($)

Fair Value Inputs Assets Quantitative Information [Line Items]

Investment in RBS Sempra Commodities LLP

$ 126

Investment in Rockies Express

$ 369

Fair value measurement percentage, of level two hierarchy, for Rockies Express

67.00%

Fair value measurement percentage, of level three hierarchy, for Rockies Express

33.00%

Fair value measurement percentage, of level three hierarchy, for RBS Sempra Commodities

100.00%

Equity Method Investments [Member] | Market Approach Valuation Technique [Member] | Level 2 | Sixty Seven Percent [Member] | Stated [Member]

Fair Value Inputs Assets Quantitative Information [Line Items]

Fair value inputs, equity sale offer price

100.00%

Equity Method Investments [Member] | Probability Weighted Discounted Cash Flow Valuation Technique [Member] | Level 3 | Thirty Three Percent [Member] | Maximum [Member]

Fair Value Inputs Assets Quantitative Information [Line Items]

Fair value inputs, combined transportation rate assumption

78.00%

^[1]

Fair value inputs, operating and maintenance escalation rate

1.00%

Fair value inputs, forecasted interest rate on debt to be refinanced

10.00%

Fair value inputs, discount rate

10.00%

Equity Method Investments [Member] | Probability Weighted Discounted Cash Flow Valuation Technique [Member] | Level 3 | Thirty Three Percent [Member] | Minimum [Member]

Fair Value Inputs Assets Quantitative Information [Line Items]

Fair value inputs, combined transportation rate assumption

6.00%

^[1]

Fair value inputs, forecasted interest rate on debt to be refinanced

5.00%

Fair value inputs, discount rate

8.00%

Equity Method Investments [Member] | Discounted Cash Flow Valuation Technique [Member] | Level 3 | One Hundred Percent [Member] | Maximum [Member]

Fair Value Inputs Assets Quantitative Information [Line Items]

Fair value inputs, future cash distributions

110.00%

Equity Method Investments [Member] | Discounted Cash Flow Valuation Technique [Member] | Level 3 | One Hundred Percent [Member] | Minimum [Member]

Fair Value Inputs Assets Quantitative Information [Line Items]

Fair value inputs, future cash distributions

90.00%

[1]	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

CALIFORNIA UTILITIES' REGULATORY MATTERS (Details) $ in Thousands	3 Months Ended
	Sep. 30, 2012 USD ($)
San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Regulatory Amounts [Line Items]
General Rate Case, Annual Revenue Requirement Increase	$ 235,000
General Rate Case, Percentage Annual Revenue Requirement Increase	14.60%
Regulatory Recovery, Deductible Per Event	$ 5,000
Incremental insurance costs incurred related to catastrophe for 2009-2010 policy period	29,000
Incremental insurance costs incurred related to catastrophe for 2010-2011 policy period	63,000
General Rate Case, Revenue Requirement Request	1,849,000
Incremental Insurance Premiums Cost Recovery In GRC	67,000
Incremental Insurance Premiums Included In 2011 Earnings	$ 28,000
Authorized Return On Equity	11.10%
Authorized Return On Rate Base	8.40%
Authorized Capital Structure, Common Equity	49.00%
Requested Return On Equity	11.00%
Requested Return On Rate Base	8.15%
Requested Capital Structure, Common Equity	52.00%
Nuclear Plant, Ownership Percentage	20.00%
Nuclear Plant, Proportional Investment	$ 180,000
Nuclear Plant, Replacement Power Costs	54,000
Nuclear Plant, Rate Base Investment	220,000
Nuclear Plant, Net Book Investment	485,000
Nuclear Plant, MHI Limited Liability	137,000
Nuclear Plant, Revenue Recognized Associated with SONGS	153,000
Nuclear Plant, Invoice to MHI	45,000
Minimum Unrecoverable Per Wildfire	10,000
Southern California Gas Company [Member]
Schedule Of Regulatory Amounts [Line Items]
General Rate Case, Annual Revenue Requirement Increase	$ 268,000
General Rate Case, Percentage Annual Revenue Requirement Increase	14.50%
Unrecorded Gas Cost Incentive Mechanism Award	$ 5,400
General Rate Case, Revenue Requirement Request	2,112,000
Recognized Gas Cost Incentive Mechanism Award 2010-2011	$ 6,200
Authorized Return On Equity	10.82%
Authorized Return On Rate Base	8.68%
Authorized Capital Structure, Common Equity	48.00%
Requested Return On Equity	10.90%
Requested Return On Rate Base	8.44%
Requested Capital Structure, Common Equity	52.00%
East County Substation [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	$ 435,000
South Orange County Reliability Enhancement [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	473,000
Aliso Canyon Natural Gas Storage Compressor Replacement [Member] \| Southern California Gas Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	$ 200,000

COMMITMENTS AND CONTINGENCIES - LEGAL PROCEEDINGS (Details)
$ in Thousands, £ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2012

USD ($)

Sep. 30, 2012

GBP (£)

Sep. 30, 2011

USD ($)

Sep. 30, 2012

USD ($)

Sep. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

^[2]

Regulatory Assets Arising From Wildfire Litigation Costs

$ 427,000

326,000

$ 594,000

^[1]

San Diego Gas and Electric Company and Subsidiary [Member]

Regulatory Assets Arising From Wildfire Litigation Costs

411,000

326,000

$ 594,000

Loss from Catastrophes [Member] | S D G E Segment [Member]

5,000

Loss From Loss Contingencies [Line Items]

Loss Contingency, Loss in Period

(1,000)

$ 5,000

4,000

$ 7,000

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

Payments for Legal Settlements

411,000

14,750

Claims Payments By Insurers To All Claimants

$ 1,600,000

Percentage of Total Claims to be Paid by Company

57.50%

Total Individual And Business Claims

$ 1,400,000

Liability Insurance Coverage, Maximum

1,100,000

Litigation Settlement, Gross

824,000

Payments For Legal Settlements In Excess Of Recovered Amounts

187,000

Loss Contingency Accrual Carrying Value, Current

284,000

Loss Contingency Accrual Carrying Value, Noncurrent

127,000

Potential Impact On Earnings

175,000

Portion of Regulatory Assets Arising From Wildfire Litigation Related To CPUC Operations

292,000

Liberty Gas Storage Litigation [Member]

Loss Contingency Monetary Damages Sought

56,700

Estimated Gain Loss On Contract Termination

$ 215,000

HMRC VAT Claim [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

VAT Tax Claim Amount | £

£ 86

[1]	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
[2]	Derived from audited financial statements.

COMMITMENTS AND CONTINGENCIES - NUCLEAR INSURANCE (Details) - San Diego Gas and Electric Company and Subsidiary [Member] $ in Thousands	Sep. 30, 2012 USD ($)
Schedule Of Nuclear Insurance [Line Items]
Nuclear Liability Insurance Coverage, Maximum	$ 375,000
Secondary Financial Protection, Maximum	12,200,000
Secondary Financial Protection, Company Contribution, Maximum	47,000
Secondary Financial Protection, Company Contribution, Annual Maximum	7,000
Nuclear Property Insurance Coverage, Maximum	2,750,000
Nuclear Property Damage Insurance Coverage, Maximum	490,000
Nuclear Property Damage Insurance Coverage, Weekly Maximum	3,500
Nuclear Property Damage Insurance Coverage, Weekly Minimum	2,800
Nuclear Property Damage Insurance, Premium Assessment	9,700
Nuclear Property Insurance Terrorism Coverage, Maximum	$ 3,240,000

COMMITMENTS AND CONTINGENCIES - CONTRACTUAL COMMITMENTS (Details) $ in Millions	3 Months Ended
	Sep. 30, 2012 USD ($)
Luz Del Sur [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	$ (291)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	15
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	2
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	(1)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	8
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	105
Chilquinta Energia [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	(205)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	28
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	32
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	34
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	34
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	335
San Diego Gas and Electric Company and Subsidiary [Member]
Payments Under Contractual Commitments [Line Items]
Contractual Commitments, Payments Due, Current	62
Contractual Commitments, Payments Due In Two Years	159
Contractual Commitments, Payments Due In Three Years	20
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	(47)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	18
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	61
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	66
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	67
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	1,400
Increase (Decrease) In Purchase Commitment Amount	1,600
Southern California Gas Company [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Natural Gas Contracts Commitments	232
Decrease In Natural Gas Contracts Commitments, Fulfillment	359
Increase In Natural Gas Contracts Commitments, New Contracts	591
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(231)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	307
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	67
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Four Years	34
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Five Years	4
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due Thereafter	51
Sempra South American Utilities [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchase Commitment Amount	96
Sempra Mexico [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Natural Gas Contracts Commitments	(128)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(81)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	(22)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	(25)
Sempra Natural Gas [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due, Current	(384)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Two Years	(9)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Three Years	(18)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Four Years	(27)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Five Years	(33)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due Thereafter	(523)
Increase (Decrease) In Natural Gas Contracts Commitments	73
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(7)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	14
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	10
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Four Years	11
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Five Years	11
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due Thereafter	34
Sempra Renewables [Member]
Operating Leases [Line Items]
Operating Leases, Future Minimum Payments, Due in Two Years	2
Operating Leases, Future Minimum Payments, Due in Three Years	2
Operating Leases, Future Minimum Payments, Due in Four Years	2
Operating Leases, Future Minimum Payments, Due in Five Years	2
Operating Leases, Future Minimum Payments, Due Thereafter	$ 57
Sunrise Powerlink Construction [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Contractual Commitment Annual Escalation Percentage	2.00%
Contractual Commitment Number of Years	58
Contractual Commitment Future Annual Payment Amount	$ 3
Contractual Commitment Present Value Future Payments, Regulatory Asset	116
Contractual Commitment Future Payments, Liability	113
Natural Gas Infrastructure Construction [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	11
Natural Gas Infrastructure Construction [Member] \| Southern California Gas Company [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	60
Electric Distribution And Generation Plant [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	34
ECO Substation [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 196
Citizens Sunrise Transmission [Member] \| San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Contractual Commitment Number of Years	30
Proceeds From Long Term Transmission Agreement	$ 85

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

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

Segment reporting information, Percentage of Total Consolidated Revenues

$ 2,507

$ 2,576

^[1]

$ 6,979

$ 7,432

^[1]

100.00%

$ 126

$ 118

^[1]

$ 352

$ 344

^[1]

Segment reporting information, Depreciation and Amortization

^[1]

$ 280

$ 251

^[1]

$ 803

$ 729

^[1]

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

100.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 49

$ 75

^[1]

$ 48

$ 289

^[1]

Segment reporting information, Equity Earnings (Losses) Recorded Before Tax

(94)

(12)

^[1]

(375)

(4)

^[1]

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

^[1]

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 268

$ 289

^[1]

$ 566

$ 1,046

^[1]

100.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 2,241

$ 2,031

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

100.00%

Segment reporting information, Percentage of Consolidated Assets

$ 35,390

$ 33,249

^[1],[2]

100.00%

Segment Reporting Information Investments In Equity Method Investees

$ 1,503

$ 1,629

S D G E Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 1,092

$ 868

$ 2,706

$ 2,405

44.00%

34.00%

39.00%

32.00%

Segment reporting information, Depreciation and Amortization

$ 49

$ 37

$ 124

$ 104

$ 128

$ 108

$ 359

$ 316

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

46.00%

43.00%

45.00%

43.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 38

$ 63

$ 151

$ 154

Segment reporting information, Percentage of Consolidated Earnings (Losses)

^[3]

$ 174

$ 113

$ 374

$ 273

65.00%

39.00%

66.00%

26.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 998

$ 1,162

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

44.00%

57.00%

Segment reporting information, Percentage of Consolidated Assets

$ 14,589

$ 13,555

41.00%

Segment Reporting Information, Intersegment Revenue

$ 3

$ 2

$ 6

$ 5

Segment Reporting Information, Intersegment Receivables

$ 67

So Cal Gas Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 728

$ 844

$ 2,328

$ 2,776

29.00%

33.00%

37.00%

$ 17

$ 51

$ 52

Segment reporting information, Depreciation and Amortization

$ 91

$ 83

$ 268

$ 246

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

33.00%

34.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 37

$ 41

$ 105

$ 106

Segment reporting information, Percentage of Consolidated Earnings (Losses)

^[3]

$ 71

$ 81

$ 190

$ 208

26.00%

28.00%

34.00%

20.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 462

$ 499

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

21.00%

25.00%

Segment reporting information, Percentage of Consolidated Assets

$ 8,784

$ 8,475

25.00%

Segment Reporting Information, Intersegment Revenue

$ 17

$ 13

$ 48

$ 38

Segment Reporting Information, Intersegment Receivables

280

$ 40

All Other Segments [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

185

174

Segment reporting information, Depreciation and Amortization

(2)

$ 3

$ 4

$ 9

$ 11

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

1.00%

2.00%

1.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (17)

$ (58)

$ (91)

$ (100)

Segment reporting information, Equity Earnings (Losses) Recorded Before Tax

(1)

(16)

(2)

(27)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ (16)

$ (44)

$ (37)

$ (102)

(6.00%)

(15.00%)

(7.00%)

(10.00%)

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 3

$ 1

Segment reporting information, Percentage of Consolidated Assets

$ 520

$ 538

1.00%

2.00%

Segment Reporting Information Investments In Equity Method Investees

$ 135

$ 137

Adjustments and Eliminations [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Intercompany Eliminations Segment [Member]

$ (1)

(1)

Segment Reporting Information, Profit (Loss) [Abstract]

(44)

(33)

(125)

(95)

Intersegment Revenues Segment [Member]

(19)

(10)

(51)

(31)

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

^[4]

$ (171)

$ (125)

$ (359)

$ (372)

(7.00%)

(5.00%)

Intersegment Receivables Segment [Member]

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Percentage of Consolidated Assets

^[5]

$ (3,108)

$ (2,162)

(9.00%)

(7.00%)

Sempra South American Utilities Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 356

$ 345

$ 1,061

$ 706

14.00%

13.00%

15.00%

10.00%

$ 6

$ 9

$ 22

$ 23

Segment reporting information, Depreciation and Amortization

$ 15

$ 14

$ 42

$ 27

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

5.00%

6.00%

5.00%

4.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 27

$ 18

$ 57

$ 30

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

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 40

$ 50

$ 118

$ 386

15.00%

17.00%

21.00%

37.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 117

$ 63

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

5.00%

3.00%

Segment reporting information, Percentage of Consolidated Assets

$ 3,241

$ 2,981

9.00%

Segment Reporting Information, Intersegment Receivables

$ 54

$ 52

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 181

$ 183

$ 434

$ 561

7.00%

6.00%

8.00%

$ 4

$ 10

$ 15

Segment reporting information, Depreciation and Amortization

$ 15

$ 46

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

5.00%

6.00%

Segment reporting information, Income Tax Expense (Benefit)

$ 21

$ (7)

$ 44

$ 24

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

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 54

$ 47

$ 134

$ 121

20.00%

16.00%

24.00%

12.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 13

$ 11

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

1.00%

Segment reporting information, Percentage of Consolidated Assets

$ 3,042

$ 2,914

9.00%

Segment Reporting Information Investments In Equity Method Investees

$ 333

$ 302

Segment Reporting Information, Intersegment Revenue

$ 48

161

$ 157

Segment Reporting Information, Intersegment Receivables

643

543

Sempra Renewables Segment [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 27

$ 49

1.00%

$ 6

$ 13

Segment reporting information, Depreciation and Amortization

$ 4

$ 1

$ 10

$ 4

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

1.00%

0.00%

1.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (12)

$ (9)

$ (47)

$ (22)

Segment reporting information, Equity Earnings (Losses) Recorded Before Tax

(6)

(7)

(6)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ 13

$ 1

$ 47

$ 9

5.00%

1.00%

8.00%

1.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 564

$ 124

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

25.00%

6.00%

Segment reporting information, Percentage of Consolidated Assets

$ 2,412

$ 1,210

7.00%

4.00%

Segment Reporting Information Investments In Equity Method Investees

$ 666

$ 390

Segment Reporting Information, Intersegment Receivables

521

263

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Percentage of Total Consolidated Revenues

$ 294

$ 455

$ 761

$ 1,340

12.00%

18.00%

11.00%

18.00%

$ 26

$ 22

$ 72

$ 62

Segment reporting information, Depreciation and Amortization

$ 24

$ 26

$ 69

$ 79

Segment reporting information, Percentage of Consolidated Depreciation and Amortization

9.00%

10.00%

9.00%

11.00%

Segment reporting information, Income Tax Expense (Benefit)

$ (45)

$ 27

$ (171)

$ 97

Segment reporting information, Equity Earnings (Losses) Recorded Before Tax

(87)

(366)

Segment reporting information, Percentage of Consolidated Earnings (Losses)

$ (68)

$ 41

$ (260)

$ 151

(25.00%)

14.00%

(46.00%)

14.00%

Segment Reporting Information, Additional Information [Abstract]

Segment reporting information, Expenditures for Property, Plant & Equipment

$ 84

$ 171

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

4.00%

8.00%