View Filing Data

$ 288

$ 349

^[1]

^[1]

Accounts receivable – other, net

1,307

1,390

^[1]

277

164

^[1]

^[1]

110

^[1]

307

258

^[1]

325

348

^[1]

^[1]

299

^[1]

Assets held for sale

127

201

^[1]

136

142

^[1]

3,341

3,110

^[1]

^[1]

598

201

^[1]

1,517

3,414

^[1]

1,033

1,026

^[1]

Investments

2,527

2,097

^[1]

2,397

2,364

^[1]

Dedicated assets in support of certain benefit plans

596

548

^[1]

455

430

^[1]

418

606

^[1]

170

234

^[1]

295

^[1]

Property, Plant and Equipment, Net [Abstract]

792

520

^[1]

Total other assets

10,610

11,745

^[1]

Less accumulated depreciation and amortization

48,108

43,624

^[1]

(11,605)

(10,693)

^[1]

36,503

32,931

^[1]

50,454

47,786

^[1]

1,540

1,779

^[1]

Accounts payable – trade

1,350

1,346

^[1]

Accounts payable – other

173

130

^[1]

Dividends and interest payable

^[1]

342

319

^[1]

Accrued compensation and benefits

439

409

^[1]

109

122

^[1]

1,427

913

^[1]

109

^[1]

Customer deposits

162

158

^[1]

^[1]

Liabilities held for sale

299

^[1]

^[1]

545

517

^[1]

6,635

5,927

^[1]

Deferred Credits and Other Liabilities [Abstract]

16,445

14,429

^[1]

Customer advances for construction

150

152

^[1]

Pension and other postretirement benefit plan obligations, net of plan assets

^[1]

1,148

1,208

^[1]

Deferred investment tax credits

2,767

3,745

^[1]

^[1]

3,922

2,876

^[1]

2,732

2,431

^[1]

316

405

^[1]

171

^[1]

Total deferred credits and other liabilities

1,136

1,173

^[1]

12,234

12,189

^[1]

Commitments and contingencies (Note 15)

^[1]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]

Preferred stock

^[1]

Common stock

3,149

2,982

^[1]

Retained earnings

10,147

10,717

^[1]

Accumulated other comprehensive income (loss)

(626)

(748)

^[1]

Total shareholders’ equity

12,670

12,951

^[1]

Preferred stock of subsidiary

^[1]

2,450

2,270

^[1]

Total equity

15,140

15,241

^[1]

50,454

47,786

^[1]

^[1]

^[1]

Accounts receivable – other, net

362

354

^[1]

^[1]

^[1]

122

^[1]

105

^[1]

316

340

^[1]

Prepaid expenses

^[1]

^[1]

116

^[1]

^[1]

1,100

1,072

^[1]

^[1]

451

2,012

^[1]

1,033

1,026

^[1]

182

^[1]

Property, Plant and Equipment, Net [Abstract]

328

176

^[1]

Total other assets

1,906

3,397

^[1]

Less accumulated depreciation and amortization

19,787

17,844

^[1]

(4,949)

(4,594)

^[1]

14,838

13,250

^[1]

17,844

17,719

^[1]

253

^[1]

Accounts payable – trade

501

460

^[1]

Accrued compensation and benefits

^[1]

Interest payable

^[1]

122

121

^[1]

^[1]

Accrued franchise fees

^[1]

220

191

^[1]

^[1]

^[1]

Customer deposits

^[1]

116

^[1]

^[1]

1,622

1,168

^[1]

Deferred Credits and Other Liabilities [Abstract]

5,335

4,658

^[1]

Customer advances for construction

^[1]

Pension and other postretirement benefit plan obligations, net of plan assets

182

232

^[1]

Deferred investment tax credits

1,530

2,829

^[1]

^[1]

2,225

1,725

^[1]

762

751

^[1]

153

189

^[1]

^[1]

Total deferred credits and other liabilities

334

349

^[1]

5,261

6,215

^[1]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]

Preferred stock

^[1]

Common stock

1,338

^[1]

Retained earnings

4,268

4,311

^[1]

Accumulated other comprehensive income (loss)

(8)

^[1]

Total shareholders’ equity

5,598

5,641

^[1]

^[1]

Total equity

5,626

5,678

^[1]

17,844

17,719

^[1]

^[1]

Accounts receivable – other, net

517

608

^[1]

^[1]

^[1]

^[1]

124

^[1]

^[1]

179

^[1]

^[1]

979

836

^[1]

983

1,331

^[1]

418

606

^[1]

109

^[1]

Property, Plant and Equipment, Net [Abstract]

364

290

^[1]

Total other assets

1,774

2,336

^[1]

Less accumulated depreciation and amortization

16,772

15,344

^[1]

(5,366)

(5,092)

^[1]

11,406

10,252

^[1]

14,159

13,424

^[1]

116

^[1]

Accounts payable – trade

502

481

^[1]

Accounts payable – other

^[1]

Accrued compensation and benefits

^[1]

151

150

^[1]

122

^[1]

501

^[1]

Customer deposits

^[1]

^[1]

179

^[1]

205

171

^[1]

2,046

1,241

^[1]

Deferred Credits and Other Liabilities [Abstract]

2,485

2,982

^[1]

Customer advances for construction

^[1]

Pension obligation, net of plan assets

789

762

^[1]

Deferred investment tax credits

995

1,709

^[1]

^[1]

1,697

1,151

^[1]

1,885

1,616

^[1]

^[1]

Total deferred credits and other liabilities

253

246

^[1]

5,721

5,691

^[1]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]

Preferred stock

^[1]

Common stock

866

^[1]

Retained earnings

3,040

2,644

^[1]

Accumulated other comprehensive income (loss)

(21)

(22)

^[1]

Total shareholders’ equity

3,907

3,510

^[1]

Total equity

3,907

3,510

Regulated and Unregulated Operating Revenue [Abstract]

$ 14,159

$ 13,424

^[1]

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

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

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Utilities

$ 9,776

$ 9,261

$ 9,254

Energy-related businesses

1,431

922

977

Total revenues

11,207

10,183

10,231

Utilities [Abstract]

Cost of electric fuel and purchased power

(2,281)

(2,188)

(2,136)

Cost of natural gas

(1,190)

(1,067)

(1,134)

Cost of natural gas, electric fuel and purchased power

(339)

(277)

(335)

Other cost of sales

(24)

(322)

(148)

(3,117)

(2,970)

(2,886)

Franchise fees and other taxes

(1,490)

(1,312)

^[1]

(1,250)

^[1]

(436)

(426)

(423)

(351)

^[1]

(72)

(153)

^[1]

(9)

^[1]

Gain on sale of assets

134

Operating expenses

153

^[1]

Equity earnings, before income tax

351

^[1]

104

617

254

132

126

Interest income

(659)

(553)

(561)

Income tax (expense) benefit

1,585

1,830

1,704

(1,276)

(389)

(341)

Equity earnings, net of income tax

(Earnings) losses attributable to noncontrolling interest

351

1,519

^[1]

1,448

^[1]

(94)

(148)

(98)

Earnings Per Share, Basic [Abstract]

(1)

Net income/Earnings

$ 256

$ 1,370

$ 1,349

Basic earnings per common share (in dollars per share)

$ 1.02

$ 5.48

$ 5.43

Weighted-average number of shares outstanding, basic

251,545

250,217

248,249

Earnings Per Share, Diluted [Abstract]

Diluted earnings per common share (in dollars per share)

$ 1.01

$ 5.46

$ 5.37

Weighted-average number of shares outstanding, diluted

252,300

251,155

250,923

Operating revenues

Electric

$ 3,935

$ 3,754

$ 3,719

541

499

500

Total operating revenues

4,476

4,253

4,219

Cost of electric fuel and purchased power

(351)

^[1]

Operating expenses

1,293

1,187

1,151

Cost of natural gas

164

127

153

1,020

1,048

1,017

Franchise fees and other taxes

670

646

^[1]

604

^[1]

265

255

262

351

^[1]

^[1]

(26)

^[1]

Total operating expenses

3,763

3,263

3,161

713

990

1,058

(203)

(195)

(204)

Income tax (expense) benefit

576

845

890

(155)

(280)

(284)

(Earnings) losses attributable to noncontrolling interest

421

565

^[1]

606

^[1]

(14)

(19)

407

570

587

Operating revenues

Total operating revenues

3,785

3,471

3,489

(22)

(9)

Operating expenses

Cost of natural gas

1,025

891

921

1,479

1,385

1,361

Franchise fees and other taxes

515

476

461

144

140

129

Total operating expenses

3,163

2,914

2,881

622

557

608

Interest income

(102)

(97)

(84)

Income tax (expense) benefit

557

493

558

(160)

(143)

(138)

Preferred dividend requirements

397

350

420

(1)

$ 396

$ 349

$ 419

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

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Other Comprehensive Income (Loss), Net of Tax [Abstract]

$ 351

$ 1,519

^[1]

$ 1,448

^[1]

142

(334)

(1)

Pretax amount [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

1,533

1,760

1,691

107

(260)

(6)

(80)

(13)

(3)

129

(343)

1,662

1,783

1,348

Total comprehensive income, after preferred dividends of subsidiaries

(1)

1,661

1,782

1,347

Income tax (expense) benefit [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

(1,276)

(389)

(341)

(8)

(7)

(1,283)

(374)

(307)

Total comprehensive income, after preferred dividends of subsidiaries

(1,283)

(374)

(307)

Net-of-tax amount [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

257

1,371

1,350

107

(260)

(47)

(9)

(2)

122

(309)

379

1,409

1,041

Total comprehensive income, after preferred dividends of subsidiaries

(1)

378

1,408

1,040

Noncontrolling interests (after-tax) [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

148

(3)

(30)

(25)

114

162

Total comprehensive income, after preferred dividends of subsidiaries

114

162

Total [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

351

1,519

1,448

115

(290)

(42)

(9)

(2)

142

(334)

493

1,571

1,114

Total comprehensive income, after preferred dividends of subsidiaries

(1)

492

1,570

1,113

Other Comprehensive Income (Loss), Net of Tax [Abstract]

421

565

^[1]

606

^[1]

San Diego Gas and Electric Company [Member] | Pretax amount [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

562

850

871

(1)

(1)

San Diego Gas and Electric Company [Member] | Income tax (expense) benefit [Member]

561

850

878

Other Comprehensive Income (Loss), Net of Tax [Abstract]

(155)

(280)

(284)

(3)

(3)

San Diego Gas and Electric Company [Member] | Net-of-tax amount [Member]

(154)

(280)

(287)

Other Comprehensive Income (Loss), Net of Tax [Abstract]

407

570

587

San Diego Gas and Electric Company [Member] | Noncontrolling interests (after-tax) [Member]

407

570

591

Other Comprehensive Income (Loss), Net of Tax [Abstract]

(5)

San Diego Gas and Electric Company [Member] | Total [Member]

Other Comprehensive Income (Loss), Net of Tax [Abstract]

421

565

606

432

575

616

Other Comprehensive Income (Loss), Net of Tax [Abstract]

397

350

420

Southern California Gas Company [Member] | Pretax amount [Member]

(3)

(1)

Other Comprehensive Income (Loss), Net of Tax [Abstract]

557

493

558

(6)

(2)

(5)

(1)

Southern California Gas Company [Member] | Income tax (expense) benefit [Member]

558

488

557

Other Comprehensive Income (Loss), Net of Tax [Abstract]

(160)

(143)

(138)

(1)

Southern California Gas Company [Member] | Net-of-tax amount [Member]

(160)

(141)

(138)

Other Comprehensive Income (Loss), Net of Tax [Abstract]

397

350

420

(4)

(1)

(3)

(1)

$ 398

$ 347

$ 419

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

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

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

$ 351

$ 1,519

^[1]

$ 1,448

^[1]

Deferred income taxes and investment tax credits

1,490

1,312

^[1]

1,250

^[1]

1,160

217

^[1]

239

^[1]

351

^[1]

153

^[1]

^[1]

(26)

^[1]

Gain on sale of assets

(3)

(134)

^[1]

(70)

^[1]

Equity earnings, net

(76)

(84)

^[1]

(189)

^[1]

(617)

^[1]

^[1]

(10)

^[1]

149

^[1]

188

(281)

^[1]

(325)

^[1]

Changes in other liabilities

(214)

^[1]

(169)

^[1]

153

^[1]

(24)

^[1]

Changes in working capital components:

Income taxes receivable, net

(42)

^[1]

(99)

^[1]

(70)

^[1]

(49)

(20)

^[1]

108

198

^[1]

586

^[1]

(12)

(41)

^[1]

(19)

^[1]

122

^[1]

(157)

^[1]

(221)

^[1]

274

^[1]

Net change in other working capital components

(51)

(58)

^[1]

(59)

^[1]

699

^[1]

3,625

2,311

^[1]

2,898

^[1]

Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired

(3,949)

(4,214)

^[1]

(3,156)

^[1]

(270)

(1,504)

^[1]

(198)

^[1]

Proceeds from sale of assets, net of cash sold

763

^[1]

373

^[1]

Distributions from investments

^[1]

Purchases of nuclear decommissioning and other trust assets

(1,314)

(1,034)

^[1]

(531)

^[1]

Proceeds from sales by nuclear decommissioning and other trusts

1,314

1,134

^[1]

577

^[1]

Advances to unconsolidated affiliates

(531)

(25)

^[1]

(31)

^[1]

Repayments of advances to unconsolidated affiliates

^[1]

(2)

^[1]

(4,700)

(4,835)

^[1]

(2,868)

^[1]

Preferred dividends paid by subsidiary

Common dividends paid

(755)

(686)

^[1]

(628)

^[1]

(1)

^[1]

(1)

^[1]

^[1]

Issuances of debt (maturities greater than 90 days)

(15)

(56)

^[1]

(74)

^[1]

4,509

2,951

^[1]

2,992

^[1]

Payments on debt (maturities greater than 90 days)

(2,800)

(2,057)

^[1]

(1,854)

^[1]

(Decrease) increase in short-term debt, net

(36)

692

^[1]

(622)

^[1]

Advances from unconsolidated affiliates

^[1]

Proceeds from sale of noncontrolling interests, net of $3 and $40 in offering costs, respectively

196

1,692

^[1]

Net distributions to noncontrolling interests

(130)

(63)

^[1]

(73)

^[1]

Net cash provided by (used in) financing activities

(43)

(21)

^[1]

(20)

^[1]

1,007

2,502

^[1]

(176)

^[1]

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(3)

^[1]

(14)

^[1]

Decrease in cash, cash equivalents and restricted cash

(61)

(25)

^[1]

(160)

^[1]

Cash, cash equivalents and restricted cash, January 1

^[1]

425

450

610

Cash, cash equivalents and restricted cash, December 31

364

425

^[1]

450

^[1]

^[2]

349

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

288

349

^[2]

Interest payments, net of amounts capitalized

619

532

^[1]

537

^[1]

Income tax payments (refunds), net

172

160

^[1]

Noncash acquisition of businesses:

Assets acquired, net of cash, cash equivalents and restricted cash

436

3,808

^[1]

Value of equity method investment immediately prior to acquisition

(28)

(1,144)

^[1]

Liabilities assumed

(261)

(1,322)

^[1]

(2)

^[1]

Accrued purchase price

^[1]

(5)

^[1]

Cash paid, net of cash, cash equivalents and restricted cash acquired

147

1,342

^[1]

Other Noncash Investing and Financing Items [Abstract]

Accrued capital expenditures

562

626

^[1]

566

^[1]

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

504

^[1]

Financing of build-to-suit property

^[1]

^[1]

Redemption of industrial development bonds

^[1]

Equitization of note receivable due from unconsolidated affiliate

^[1]

Common dividends issued in stock

^[1]

Dividends declared but not paid

214

196

^[1]

180

^[1]

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

421

565

^[1]

606

^[1]

Deferred income taxes and investment tax credits

670

646

^[1]

604

^[1]

(10)

258

^[1]

195

^[1]

351

^[1]

^[1]

(26)

^[1]

(2)

(3)

^[1]

(4)

^[1]

(22)

(35)

^[1]

(16)

^[1]

Changes in other liabilities

(108)

(20)

^[1]

(125)

^[1]

^[1]

Changes in working capital components:

Due to/from affiliates, net

(76)

(31)

^[1]

(10)

^[1]

(10)

(19)

^[1]

Income taxes receivable, net

136

(115)

^[1]

(25)

(5)

^[1]

(2)

^[1]

^[1]

474

^[1]

^[1]

(24)

^[1]

^[1]

(28)

^[1]

(28)

^[1]

(17)

^[1]

1,547

1,323

^[1]

1,661

^[1]

Purchases of nuclear decommissioning trust assets

(1,555)

(1,399)

^[1]

(1,133)

^[1]

(1,314)

(1,034)

^[1]

(526)

^[1]

Proceeds from sales by nuclear decommissioning trusts

1,314

1,134

^[1]

577

^[1]

Decrease (increase) in loans to affiliate, net

(31)

^[1]

^[1]

(1,515)

(1,324)

^[1]

(1,077)

^[1]

Issuances of debt (maturities greater than 90 days)

Common dividends paid

(450)

(175)

^[1]

(300)

^[1]

398

498

^[1]

444

^[1]

Payments on debt (maturities greater than 90 days)

(186)

(204)

^[1]

(547)

^[1]

(Decrease) increase in short-term debt, net

253

(114)

^[1]

(131)

^[1]

Net distributions to noncontrolling interests

(34)

(21)

^[1]

(30)

^[1]

Debt issuance costs

(4)

(6)

^[1]

(4)

^[1]

Net cash provided by (used in) financing activities

(23)

(22)

^[1]

(568)

^[1]

Increase (decrease) in cash, cash equivalents and restricted cash

(23)

^[1]

Cash, cash equivalents and restricted cash, January 1

^[1]

Cash, cash equivalents and restricted cash, December 31

^[1]

^[2]

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

^[2]

Interest payments, net of amounts capitalized

195

187

^[1]

199

^[1]

Income tax payments (refunds), net

137

^[1]

Other Noncash Investing and Financing Items [Abstract]

Accrued capital expenditures

217

227

^[1]

191

^[1]

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

500

^[1]

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

397

350

420

Deferred income taxes and investment tax credits

515

476

461

137

103

127

(26)

(20)

188

(281)

(325)

Changes in other liabilities

(80)

(91)

(13)

(7)

Changes in working capital components:

Due to/from affiliates, net

(90)

(11)

Income taxes receivable, net

(5)

(2)

(66)

102

163

112

(13)

(143)

(221)

274

(25)

1,306

671

880

Decrease (increase) in loans to affiliate, net

(1,367)

(1,319)

(1,352)

^[1]

(50)

^[1]

(1,363)

(1,269)

(1,402)

Issuances of debt (maturities greater than 90 days)

Common dividends paid

(50)

Preferred dividends paid

(1)

499

599

Payments on debt (maturities greater than 90 days)

(3)

(Decrease) increase in short-term debt, net

(50)

Debt issuance costs

(5)

(3)

Net cash provided by (used in) financing activities

552

495

Increase (decrease) in cash and cash equivalents

(4)

(46)

(27)

^[2]

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

^[2]

Interest payments, net of amounts capitalized

Income tax payments (refunds), net

Other Noncash Investing and Financing Items [Abstract]

Accrued capital expenditures

$ 208

$ 207

$ 189

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)
$ in Millions

Total

Common Stock [Member]

Retained earnings [Member]

Accumulated other comprehensive income (loss) [Member]

Shareholders' equity [Member]

Non-controlling interests [Member]

San Diego Gas and Electric Company [Member]

Common Stock [Member]

San Diego Gas and Electric Company [Member]

Retained earnings [Member]

San Diego Gas and Electric Company [Member]

Accumulated other comprehensive income (loss) [Member]

San Diego Gas and Electric Company [Member]

Shareholders' equity [Member]

San Diego Gas and Electric Company [Member]

Non-controlling interests [Member]

Southern California Gas Company [Member]

Preferred stock [Member]

Southern California Gas Company [Member]

Common Stock [Member]

Southern California Gas Company [Member]

Retained earnings [Member]

Southern California Gas Company [Member]

Accumulated other comprehensive income (loss) [Member]

Beginning Balance at Dec. 31, 2014

$ 12,100

$ 2,484

$ 9,339

$ (497)

$ 11,326

$ 774

$ 4,992

$ 1,338

$ 3,606

$ (12)

$ 4,932

$ 60

$ 2,781

$ 22

$ 866

$ 1,911

$ (18)

Comprehensive income (loss)

1,448

^[1]

1,350

606

^[1]

587

420

(334)

(309)

(25)

(1)

Share-based compensation expense

Preferred stock dividends declared

(1)

Common stock dividends declared

(694)

(300)

(50)

(1)

107

Distributions to noncontrolling interests

(74)

(80)

(32)

Equity contributed by noncontrolling interests

Ending balance at Dec. 31, 2015

12,579

2,621

9,994

(806)

11,809

770

5,276

1,338

3,893

(8)

5,223

3,149

866

2,280

(19)

Cumulative-effect adjustment from change in accounting principle

107

Comprehensive income (loss)

1,519

^[1]

1,371

148

565

^[1]

570

(5)

350

(3)

Share-based compensation expense

Preferred stock dividends declared

(1)

Common stock dividends declared

(754)

(175)

(1)

104

Sale of noncontrolling interests, net of offering costs

(56)

1,701

261

281

1,420

Distributions to noncontrolling interests

(65)

(23)

Equity contributed by noncontrolling interests

Ending balance at Dec. 31, 2016

15,241

^[2]

2,982

10,717

(748)

12,951

2,290

5,678

^[2]

1,338

4,311

(8)

5,641

3,510

866

2,644

(22)

Comprehensive income (loss)

351

257

421

407

397

142

122

Share-based compensation expense

Preferred stock dividends declared

(1)

Common stock dividends declared

(826)

(450)

(1)

100

Sale of noncontrolling interests, net of offering costs

(15)

196

Distributions to noncontrolling interests

(132)

(35)

Equity contributed by noncontrolling interests

Ending balance at Dec. 31, 2017

$ 15,140

$ 3,149

$ 10,147

$ (626)

$ 12,670

$ 2,470

$ 5,626

$ 1,338

$ 4,268

$ (8)

$ 5,598

$ 28

$ 3,907

$ 22

$ 866

$ 3,040

$ (21)

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Significant Accounting Policies And Other Financial Data

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Energy’s principal operating units are


▪	Sempra Utilities, which includes our SDG&E, SoCalGas and Sempra South American Utilities reportable segments; and


▪	Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments.

We provide descriptions of each of our segments in Note 16.

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

Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. IEnova is a separate legal entity comprised of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. IEnova’s financial results are reported in Mexico under International Financial Reporting Standards, as required by the Mexican Stock Exchange, where its shares are traded under the symbol IENOVA.

Sempra Energy uses the equity method to account for investments in companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 3, 4 and 10.

SDG&E

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

SoCalGas

SoCalGas’ common stock is wholly owned by PE, which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

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

Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:


▪	the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;


▪	the Consolidated Financial Statements and related Notes of SDG&E and its VIE; and


▪	the Financial Statements and related Notes of SoCalGas.

Balance Sheet Reclassifications

We have made certain balance sheet reclassifications at December 31, 2016 to conform to the current year presentation. Line item captions for various types of regulatory assets and liabilities have been combined or separated into four new line items: current and noncurrent regulatory assets and current and noncurrent regulatory liabilities. The details of regulatory assets and liabilities are provided in Note 14. Additionally, greenhouse gas allowances have been separated from other current assets and sundry assets and greenhouse gas obligations have been separated from other current liabilities and deferred credits and other into four new line items: current and noncurrent greenhouse gas allowances and current and noncurrent greenhouse gas obligations. These reclassifications and related disclosures had no effect on our financial position as of December 31, 2016 and are intended to provide additional clarity into the financial position of Sempra Energy, SDG&E and SoCalGas. The following tables summarize the balance sheet line items affected by these reclassifications:



SEMPRA ENERGY CONSOLIDATED – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Regulatory assets	$	—	$	348
Greenhouse gas allowances	—		40
Regulatory balancing accounts – undercollected	259		—
Other	271		142
Other assets:
Greenhouse gas allowances	—		295
Sundry	815		520
Current liabilities:
Regulatory liabilities	—		122
Greenhouse gas obligations	—		40
Regulatory balancing accounts – overcollected	122		—
Other	557		517
Deferred credits and other liabilities:
Regulatory liabilities	—		2,876
Greenhouse gas obligations	—		171
Regulatory liabilities arising from removal obligations	2,697		—
Deferred credits and other	1,523		1,173



SDG&E – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Regulatory assets	$	81	$	340
Greenhouse gas allowances	—		16
Regulatory balancing accounts – net undercollected	259		—
Other	19		3
Other assets:
Regulatory assets	—		2,012
Greenhouse gas allowances	—		182
Deferred taxes recoverable in rates	1,014		—
Other regulatory assets	998		—
Sundry	358		176
Current liabilities:
Greenhouse gas obligations	—		16
Other	82		66
Deferred credits and other liabilities:
Regulatory liabilities	—		1,725
Greenhouse gas obligations	—		72
Regulatory liabilities arising from removal obligations	1,725		—
Deferred credits and other	421		349



SOCALGAS – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Greenhouse gas allowances	$	—	$	24
Other	63		39
Other assets:
Regulatory assets	—		1,331
Greenhouse gas allowances	—		109
Regulatory assets arising from pension obligations	742		—
Other regulatory assets	589		—
Sundry	399		290
Current liabilities:
Regulatory liabilities	—		122
Greenhouse gas obligations	—		24
Regulatory balancing accounts – net overcollected	122		—
Other	195		171
Deferred credits and other liabilities:
Regulatory liabilities	—		1,151
Greenhouse gas obligations	—		96
Regulatory liabilities arising from removal obligations	972		—
Deferred credits and other	521		246

Use of Estimates in the Preparation of the Financial Statements

We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 2017 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation. See Note 18 for a discussion of certain financing transactions that were completed in January 2018.

EFFECTS OF REGULATION

The California Utilities’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of:


▪	the nature of the event giving rise to the assessment;


▪	existing statutes and regulatory code;


▪	legal precedents;


▪	regulatory principles and analogous regulatory actions;


▪	testimony presented in regulatory hearings;


▪	regulatory orders;


▪	a commission-authorized mechanism established for the accumulation of costs;


▪	status of applications for rehearings or state court appeals;


▪	specific approval from a commission; and


▪	historical experience.

Sempra Mexico’s natural gas distribution utility, Ecogas, also applies U.S. GAAP for rate-regulated utilities to its operations, including the same evaluation of probability of recovery of regulatory assets described above.

We provide information concerning regulatory assets and liabilities in Notes 13 and 14.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Revenues are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP.

Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction by IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.”

Sempra LNG & Midstream owned Mobile Gas in southwest Alabama and Willmut Gas in Mississippi until they were sold in September 2016, as we discuss in Note 3. Mobile Gas and Willmut Gas also prepared their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

We discuss revenue recognition at our utilities in “Revenues” below.

FAIR VALUE MEASUREMENTS

We measure certain assets and liabilities at fair value on a recurring basis, primarily nuclear decommissioning and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances. These assets can include goodwill, intangible assets, equity method investments and other long-lived assets.

“Fair value” is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Pricing inputs are quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:


▪	quoted forward prices for commodities


▪	time value


▪	current market and contractual prices for the underlying instruments


▪	volatility factors


▪	other relevant economic measures

Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E.

CASH AND CASH EQUIVALENTS

Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.

RESTRICTED CASH

Restricted cash at Sempra Energy was $76 million at both December 31, 2017 and 2016, and includes:


▪	for SDG&E, $17 million and $12 million at December 31, 2017 and 2016, respectively, representing funds held by a trustee for Otay Mesa VIE to pay certain operating costs.


▪	for Sempra Mexico, $56 million and $61 million at December 31, 2017 and 2016, respectively, primarily denominated in Mexican pesos, representing funds to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects.


▪	for Sempra Renewables, $3 million at both December 31, 2017 and 2016, primarily representing funds held in accordance with debt agreements at our wholly owned solar project.


▪	for Sempra South American Utilities, negligible amounts at both December 31, 2017 and 2016.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported on the Consolidated Balance Sheets to the sum of such amounts reported on the Consolidated Statements of Cash Flows.



RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
	At December 31,
	2017		2016
Sempra Energy Consolidated:
Cash and cash equivalents	$	288	$	349
Restricted cash, current	62		66
Restricted cash, noncurrent	14		10
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$	364	$	425
SDG&E:
Cash and cash equivalents	$	12	$	8
Restricted cash, current	6		11
Restricted cash, noncurrent	11		1
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$	29	$	20

COLLECTION ALLOWANCES

We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below:



COLLECTION ALLOWANCES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated:
Allowances for collection of receivables at January 1	$	35	$	32	$	34



Provisions for uncollectible accounts	16			23			20
Write-offs of uncollectible accounts	(18		)	(20		)	(22		)
Allowances for collection of receivables at December 31	$	33		$	35		$	32
SDG&E:
Allowances for collection of receivables at January 1	$	8		$	9		$	7
Provisions for uncollectible accounts	8			6			7
Write-offs of uncollectible accounts	(7		)	(7		)	(5		)
Allowances for collection of receivables at December 31	$	9		$	8		$	9
SoCalGas:
Allowances for collection of receivables at January 1	$	21		$	17		$	17
Provisions for uncollectible accounts	4			14			11
Write-offs of uncollectible accounts	(9		)	(10		)	(11		)
Allowances for collection of receivables at December 31	$	16		$	21		$	17

We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to collection allowances are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.

We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.

INVENTORIES

The California Utilities value natural gas inventory using the LIFO method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. At December 31, 2016, SoCalGas recognized a permanent LIFO liquidation of $33 million. The California Utilities generally value materials and supplies at the lower of average cost or net realizable value.

Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra LNG & Midstream value LNG inventory using the first-in first-out method.

The components of inventories by segment are as follows:



INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	Natural gas				LNG				Materials and supplies				Total
	2017		2016		2017		2016		2017		2016		2017		2016
SDG&E	$	4	$	2	$	—	$	—	$	101	$	78	$	105	$	80
SoCalGas⁽¹⁾	75		11		—		—		49		47		124		58
Sempra South American Utilities	—		—		—		—		30		27		30		27
Sempra Mexico	—		—		7		6		2		1		9		7
Sempra Renewables	—		—		—		—		5		4		5		4
Sempra LNG & Midstream	30		79		4		3		—		—		34		82
Sempra Energy Consolidated	$	109	$	92	$	11	$	9	$	187	$	157	$	307	$	258


⁽¹⁾	At December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas storage facility leak, which we discuss in Note 15.

INCOME TAXES

Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC. At our other businesses, we reduce the book basis of the related asset by the amount of ITCs earned. At Sempra Renewables, PTCs are recognized in income tax expense as earned.

Under the regulatory accounting treatment required for flow-through temporary differences, as discussed in Note 6, the California Utilities and Sempra Mexico recognize


▪	regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and


▪	regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers.

When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more likely than not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more likely than not criterion at the largest amount of tax benefit that is greater than 50 percent likely of being realized upon its effective resolution.

Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.

On December 22, 2017, the TCJA was signed into law. As a result, all cumulative undistributed earnings from non-U.S. subsidiaries were deemed repatriated and subjected to a one-time U.S. federal deemed repatriation tax. To the extent we intend to repatriate cash into the U.S., incremental U.S. state and non-U.S. withholding taxes are accrued. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries to the extent the related cumulative undistributed earnings are indefinitely reinvested.

We provide additional information about income taxes in Note 6.

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

The California Utilities, Sempra Mexico and Sempra LNG & Midstream are required by California AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. At the California Utilities, many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Mexico and Sempra LNG & Midstream record the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

RENEWABLE ENERGY CERTIFICATES

RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS. The cost of RECs at SDG&E is recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations.

PROPERTY, PLANT AND EQUIPMENT

PP&E primarily represents the buildings, equipment and other facilities used by the Sempra Utilities to provide natural gas and electric utility services, and by the Sempra Infrastructure businesses in their operations, including construction work in progress at these operating units. PP&E also includes lease improvements and other equipment at Parent and Other, as well as property acquired under a build-to-suit lease, which we discuss further in Note 15.

Our plant costs include


▪	labor


▪	materials and contract services


▪	expenditures for replacement parts incurred during a major maintenance outage of a generating plant

In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP at Sempra Mexico and Sempra LNG & Midstream includes AFUDC. We discuss AFUDC below. The cost of other PP&E includes capitalized interest.

Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.

We discuss assets collateralized as security for certain indebtedness in Note 5.



PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
	PP&E at December 31,				Depreciation rates for years ended December 31,
	2017		2016		2017		2016			2015
SDG&E:
Natural gas operations	$	2,186	$	1,897	2.40	%	2.40	%		2.52	%
Electric distribution	6,975		6,497		3.92		3.86			3.79
Electric transmission⁽¹⁾	5,626		5,152		2.71		2.66			2.62
Electric generation⁽²⁾	2,435		1,932		4.05		4.00			3.89
Other electric⁽³⁾	1,114		1,059		5.54		5.66			5.73
Construction work in progress⁽¹⁾	1,451		1,307		NA		NA			NA
Total SDG&E	19,787		17,844
SoCalGas:
Natural gas operations⁽⁴⁾	15,759		14,428		3.63		3.64			3.83
Other non-utility	32		34		5.28		6.55			3.95
Construction work in progress	981		882		NA		NA			NA
Total SoCalGas	16,772		15,344

					Estimated				Weighted-average
Other operating units and parent⁽⁵⁾:					useful lives				useful life
Land and land rights	416		381		22 to 55 years⁽⁶⁾				33
Machinery and equipment:
Utility electric distribution operations	1,751		1,519		12 to 60 years				52
Generating plants	2,242		1,874		2 to 100 years				31
LNG terminals	1,133		1,129		43 years				43
Pipelines and storage	4,408		3,242		3 to 55 years				43
Other	269		235		1 to 50 years				13
Construction work in progress	691		1,488		NA				NA
Other⁽⁷⁾	639		568		1 to 80 years				33
	11,549		10,436
Total Sempra Energy Consolidated	$	48,108	$	43,624

⁽¹⁾

At December 31, 2017, includes $440 million in electric transmission assets and $29 million in construction work in progress related to SDG&E’s 92-percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations.


⁽²⁾	Includes capital lease assets of $757 million and $258 million at December 31, 2017 and 2016, respectively.


⁽³⁾	Includes capital lease assets of $22 million and $21 million at December 31, 2017 and 2016, respectively.


⁽⁴⁾	Includes capital lease assets of $34 million and $32 million at December 31, 2017 and 2016, respectively.


⁽⁵⁾	Includes $145 million and $128 million at December 31, 2017 and 2016, respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas.


⁽⁶⁾	Estimated useful lives are for land rights.


⁽⁷⁾	Includes capital lease assets of $136 million at both December 31, 2017 and 2016, related to a build-to-suit lease.

Depreciation expense is computed using the straight-line method over the asset’s estimated original composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest.

Depreciation expense on our Consolidated Statements of Operations is as follows:



DEPRECIATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,422	$	1,236	$	1,178
SDG&E	621		583		544
SoCalGas	514		474		459

Accumulated depreciation on our Consolidated Balance Sheets is as follows:



ACCUMULATED DEPRECIATION
(Dollars in millions)
	December 31,
	2017		2016
SDG&E:
Accumulated depreciation:
Electric⁽¹⁾	$	4,193	$	3,873
Natural gas	756		721
Total SDG&E	4,949		4,594
SoCalGas:
Accumulated depreciation of natural gas utility plant in service⁽²⁾	5,352		5,079
Accumulated depreciation – other non-utility	14		13
Total SoCalGas	5,366		5,092
Other operating units and parent and other:
Accumulated depreciation – other⁽³⁾	972		755
Accumulated depreciation of utility electric distribution operations	318		252
	1,290		1,007
Total Sempra Energy Consolidated	$	11,605	$	10,693


⁽¹⁾	Includes accumulated depreciation for capital lease assets of $47 million and $39 million at December 31, 2017 and 2016, respectively. Includes $241 million at December 31, 2017 related to SDG&E’s 92-percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.


⁽²⁾	Includes accumulated depreciation for capital lease assets of $33 million and $31 million at December 31, 2017 and 2016, respectively.


⁽³⁾	Includes $39 million and $33 million at December 31, 2017 and 2016, respectively, of accumulated depreciation for utility plant at Ecogas.

The California Utilities finance their construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.

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

We capitalize interest costs incurred to finance capital projects. We also capitalize interest on equity method investments that have not commenced planned principal operations.

Interest capitalized and AFUDC are as follows:



CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	256	$	236	$	201
SDG&E	85		62		51
SoCalGas	60		55		49

GOODWILL AND OTHER INTANGIBLE ASSETS

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 we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include


▪	consideration of market transactions


▪	future cash flows


▪	the appropriate risk-adjusted discount rate


▪	country risk


▪	entity risk

Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows:



GOODWILL
(Dollars in millions)
	Sempra South American Utilities		Sempra Mexico			Sempra LNG & Midstream			Total
Balance at December 31, 2015	$	722	$	25		$	72		$	819
Acquisition of businesses	—		1,590			—			1,590
Sale of business	—		—			(72		)	(72		)
Foreign currency translation⁽¹⁾	27		—			—			27
Balance at December 31, 2016	749		1,615			—			2,364
Acquisition of business – measurement period adjustment	—		(13		)	—			(13		)
Foreign currency translation⁽¹⁾	46		—			—			46
Balance at December 31, 2017	$	795	$	1,602		$	—		$	2,397


⁽¹⁾	We record the offset of this fluctuation to Other Comprehensive Income (Loss).

In 2016, Sempra Mexico recorded goodwill of $1,590 million in connection with the acquisitions of IEnova Pipelines and Ventika. In 2017, Sempra Mexico recorded a reduction to goodwill of $13 million for a measurement period adjustment in connection with the acquisition of Ventika. Also in 2016, Sempra LNG & Midstream reduced goodwill by $72 million in connection with the sale of EnergySouth. We discuss these acquisitions and the divestiture in Note 3.

Other Intangible Assets

Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:



OTHER INTANGIBLE ASSETS
(Dollars in millions)
	Amortization period (years)	December 31,
	Amortization period (years)	2017		2016
Development rights	50	$	322	$	322
Renewable energy transmission and consumption permit	19	154		154



Storage rights	46	138			138
O&M agreement	23	66			—
Other	10 years to indefinite	18			18
		698			632
Less accumulated amortization:
Development rights		(60		)	(53		)
Renewable energy transmission and consumption permit		(8		)	—
Storage rights		(28		)	(25		)
Other		(6		)	(6		)
		(102		)	(84		)
		$	596		$	548

Other Intangible Assets primarily includes


▪	storage and development rights related to the Bay Gas and Mississippi Hub natural gas storage facilities.


▪	a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities.


▪	a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 3.

Amortization expense for intangible assets in 2017, 2016 and 2015 was $18 million, $11 million and $10 million, respectively. We estimate the amortization expense for the next five years to be $21 million per year.

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated subsidiaries. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include


▪	significant decreases in the market price of an asset


▪	a significant adverse change in the extent or manner in which we use an asset or in its physical condition


▪	a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset


▪	a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset


▪	a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life

A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

VARIABLE INTEREST ENTITIES

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


▪	the purpose and design of the VIE;


▪	the nature of the VIE’s risks and the risks we absorb;


▪	the power to direct activities that most significantly impact the economic performance of the VIE; and


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

SDG&E

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs 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.

Tolling Agreements

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

Otay Mesa VIE

SDG&E has an agreement to purchase power generated at OMEC, a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase OMEC at the end of the contract term in April 2019, or upon earlier termination of the PPA, 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 for $280 million, which we refer to as the put option.

The facility owner, OMEC LLC, is a VIE, which we refer to as Otay Mesa VIE, of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy consolidate Otay Mesa VIE. Otay Mesa VIE’s equity of $28 million at December 31, 2017 and $37 million at December 31, 2016 is included on the Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $295 million at December 31, 2017, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is collateralized by OMEC’s assets. 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 9.

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



AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	December 31,
	2017		2016
Cash and cash equivalents	$	4	$	6
Restricted cash	6		11
Inventories	4		3
Other	1		2
Total current assets	15		22
Restricted cash	11		1
Property, plant and equipment, net	321		354
Total assets	$	347	$	377

Current portion of long-term debt	$	10	$	10
Fixed-price contracts and other derivatives	10		13
Other	5		5
Total current liabilities	25		28
Long-term debt	284		293
Fixed-price contracts and other derivatives	3		12
Deferred credits and other	7		7
Noncontrolling interest	28		37
Total liabilities and equity	$	347	$	377



	Years ended December 31,
	2017			2016			2015
Operating expenses
Cost of electric fuel and purchased power	$	(79	)	$	(79	)	$	(83	)
Operation and maintenance	17			29			19
Depreciation and amortization	28			35			26
Total operating expenses	(34		)	(15		)	(38		)
Operating income	34			15			38
Other income	2			—			—
Interest expense	(22		)	(20		)	(19		)
Income (loss) before income taxes/Net Income (loss)	14			(5		)	19
(Earnings) losses attributable to noncontrolling interest	(14		)	5			(19		)
Earnings attributable to common shares	$	—		$	—		$	—

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 of a VIE at December 31, 2017. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, and other components of cash flows 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. 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. 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 could be significant to the financial position and liquidity of SDG&E and Sempra Energy. We provide additional information about PPAs with power plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 15.

Sempra Renewables

In the fourth quarters of 2017 and 2016, certain of Sempra Renewables’ wind and solar power generation projects became held by limited liability companies whose members are Sempra Renewables and financial institutions. The financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. These entities are VIEs and Sempra Energy is the primary beneficiary, generally due to Sempra Energy’s power as the operator of the renewable energy projects to direct the activities that most significantly impact the economic performance of these VIEs. As the primary beneficiary of these tax equity limited liability companies, we consolidate them.

The Consolidated Financial Statements of Sempra Energy include the following amounts associated with these entities.



AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
	December 31,
	2017		2016
Cash and cash equivalents	$	23	$	88
Accounts receivable – trade, net	5		3
Inventories	1		—
Other	1		—
Total current assets	30		91
Sundry	2		—
Property, plant and equipment, net	1,412		926
Total assets	1,444		1,017

Accounts payable	42		68
Other	1		7
Total current liabilities	43		75
Asset retirement obligations	40		27
Deferred income taxes	10		—
Deferred credits and other	1		—
Total deferred credits and other liabilities	94		102

Other noncontrolling interests	631		468
Net assets less other noncontrolling interests	$	719	$	447



	Years ended December 31,
	2017			2016
REVENUES
Energy-related businesses	$	61		$	2
EXPENSES
Operation and maintenance	(9		)	(1		)
Depreciation and amortization	(32		)	—
Income before income taxes	20			1
Income tax expense	(4		)	—
Net income	16			1
Losses attributable to noncontrolling interests⁽¹⁾	23			4
Earnings	$	39		$	5

⁽¹⁾Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.

Sempra LNG & Midstream

Sempra Energy’s equity method investment in Cameron LNG JV is considered to be a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $997 million at both December 31, 2017 and 2016. Our maximum exposure to loss includes the carrying value of our investment and guarantees we have provided. We discuss our investment in the Cameron LNG JV, including related guarantees, in Note 4.

Other Variable Interest Entities

Sempra Energy’s other businesses 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 or project companies that are VIEs. As the primary beneficiary of these companies, we consolidate them; however, their financial statements are not material to the financial statements of Sempra Energy. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record asset retirement obligations for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost over the life of the related asset by depreciating the asset retirement cost (measured as the present value of the obligation at the time the asset is placed into service), and accreting the obligation until the liability is settled. Our rate-regulated entities, including the California Utilities, record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.

We have recorded asset retirement obligations related to various assets, including:

SDG&E and SoCalGas


▪	fuel and storage tanks


▪	natural gas transmission systems


▪	natural gas distribution systems


▪	hazardous waste storage facilities


▪	asbestos-containing construction materials

SDG&E


▪	decommissioning of nuclear power facilities


▪	electric distribution and transmission systems


▪	energy storage systems


▪	site restoration of a former power plant


▪	power generation plant (natural gas)

SoCalGas


▪	underground natural gas storage facilities and wells

Sempra South American Utilities


▪	electric distribution and transmission systems

Sempra Mexico


▪	power generation plant (natural gas) (classified as held for sale at December 31, 2017)


▪	natural gas distribution and transportation systems


▪	LNG terminal


▪	LPG terminal


▪	wind farm

Sempra Renewables


▪	certain power generation plants (solar and wind)

Sempra LNG & Midstream


▪	natural gas transportation systems


▪	underground natural gas storage facilities

The changes in asset retirement obligations are as follows:



CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra Energy Consolidated						SDG&E						SoCalGas
	2017			2016			2017			2016			2017			2016
Balance as of January 1⁽¹⁾	$	2,553		$	2,255		$	830		$	828		$	1,659		$	1,383
Accretion expense	109			101			39			38			66			61
Liabilities incurred and acquired	34			35			17			—			—			—
Deconsolidation and reclassification⁽²⁾	—			(16		)	—			—			—			—
Payments	(63		)	(47		)	(61		)	(46		)	(2		)	—
Revisions⁽³⁾	244			225			14			10			230			215
Balance at December 31⁽¹⁾	$	2,877		$	2,553		$	839		$	830		$	1,953		$	1,659


⁽¹⁾	Current portions of the obligations for Sempra Energy Consolidated and SoCalGas are included in Other Current Liabilities on the Consolidated Balance Sheets.


⁽²⁾	Deconsolidated $12 million due to the September 2016 sale of EnergySouth and reclassified $4 million to Liabilities Held for Sale, as we discuss in Note 3.


⁽³⁾	In 2017, revised estimates were primarily related to underground natural gas storage facilities and wells at SoCalGas. In 2016, revised estimates were related to changes in the cost of removal rates primarily for natural gas assets based on updated cost studies approved in the 2016 GRC FD.

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and:


▪	information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and


▪	the amount of the loss can be reasonably estimated.

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:


▪	foreign currency translation adjustments


▪	certain hedging activities


▪	changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans


▪	unrealized gains or losses on available-for-sale securities

The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to noncontrolling interests. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests, for the years ended December 31:



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT⁽¹⁾
(Dollars in millions)
	Foreign currency translation adjustments			Financial instruments				Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
Sempra Energy Consolidated:
Balance as of December 31, 2014	$	(322	)		$	(90	)	$	(85	)	$	(497	)

OCI before reclassifications	(260		)		(57		)	(10		)	(327		)
Amounts reclassified from AOCI	—				10			8			18
Net OCI	(260		)		(47		)	(2		)	(309		)
Balance as of December 31, 2015	(582		)		(137		)	(87		)	(806		)

OCI before reclassifications	42				(7		)	(15		)	20
Amounts reclassified from AOCI⁽²⁾	13				19			6			38
Net OCI	55				12			(9		)	58
Balance as of December 31, 2016	(527		)		(125		)	(96		)	(748		)

OCI before reclassifications	107				(4		)	—			103
Amounts reclassified from AOCI	—				7			12			19
Net OCI	107				3			12			122
Balance as of December 31, 2017	$	(420	)		$	(122	)	$	(84	)	$	(626	)
SDG&E:
Balance as of December 31, 2014								$	(12	)	$	(12	)

OCI before reclassifications								3			3
Amounts reclassified from AOCI								1			1
Net OCI								4			4
Balance as of December 31, 2015								(8		)	(8		)

OCI before reclassifications								(1		)	(1		)
Amounts reclassified from AOCI								1			1
Net OCI								—			—
Balance as of December 31, 2016								(8		)	(8		)

OCI before reclassifications								(1		)	(1		)
Amounts reclassified from AOCI								1			1
Net OCI								—			—
Balance as of December 31, 2017								$	(8	)	$	(8	)
SoCalGas:
Balance as of December 31, 2014					$	(14	)	$	(4	)	$	(18	)

OCI before reclassifications					—			(1		)	(1		)
Net OCI					—			(1		)	(1		)
Balance as of December 31, 2015					(14		)	(5		)	(19		)

OCI before reclassifications					—			(4		)	(4		)
Amounts reclassified from AOCI					1			—			1
Net OCI					1			(4		)	(3		)
Balance as of December 31, 2016					(13		)	(9		)	(22		)

Amounts reclassified from AOCI					—			1			1
Net OCI					—			1			1
Balance as of December 31, 2017					$	(13	)	$	(8	)	$	(21	)


⁽¹⁾	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.


⁽²⁾	Total AOCI includes $20 million associated with the October 2016 sale of noncontrolling interests, discussed below in “Sale of Noncontrolling Interests – Sempra Mexico – Follow-On Offerings,” which does not impact the Consolidated Statement of Comprehensive Income.



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)									Affected line item on Consolidated Statements of Operations
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments⁽¹⁾	$	(4	)	$	17		$	18		Interest Expense
Interest rate instruments	8			10			12			Equity Earnings, Before Income Tax
Interest rate and foreign exchange instruments	—			7			—			Remeasurement of Equity Method Investment
Interest rate and foreign exchange instruments	12			5			13			Equity Earnings, Net of Income Tax
Foreign exchange instruments	(2		)	—			—			Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	9			(6		)	(14		)	Revenues: Energy-Related Businesses
Total before income tax	23			33			29
	(6		)	(6		)	(4		)	Income Tax Expense
Net of income tax	17			27			25
	(10		)	(15		)	(15		)	Earnings Attributable to Noncontrolling Interests
	$	7		$	12		$	10
Pension and other postretirement benefits:
Amortization of actuarial loss⁽²⁾	$	18		$	10		$	14
Amortization of prior service cost⁽²⁾	1			1			—
Total before income tax	19			11			14
	(7		)	(5		)	(6		)	Income Tax Expense
Net of income tax	$	12		$	6		$	8

Total reclassifications for the period, net of tax	$	19		$	18		$	18
SDG&E:
Financial instruments:
Interest rate instruments⁽¹⁾	$	13		$	12		$	12		Interest Expense
	(13		)	(12		)	(12		)	(Earnings) Losses Attributable to Noncontrolling Interest
	$	—		$	—		$	—
Pension and other postretirement benefits:
Amortization of actuarial loss⁽²⁾	$	1		$	1		$	1

Total reclassifications for the period, net of tax	$	1		$	1		$	1
SoCalGas:
Financial instruments:
Interest rate instruments	$	—		$	1		$	1		Interest Expense
	—			—			(1		)	Income Tax Expense
Net of income tax	$	—		$	1		$	—
Pension and other postretirement benefits:
Amortization of prior service cost⁽²⁾	$	1		$	—		$	—

Total reclassifications for the period, net of tax	$	1		$	1		$	—


⁽¹⁾	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.


⁽²⁾	Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).

NONCONTROLLING INTERESTS

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

Sale of Noncontrolling Interests

Sempra Mexico – Follow-On Offerings

On October 13, 2016, IEnova priced a private follow-on offering of its common stock (which trades under the symbol IENOVA on the Mexican Stock Exchange) in the U.S. and outside of Mexico (the International Offering) and a concurrent public common stock offering in Mexico (the Mexican Offering) at 80.00 Mexican pesos per share. The initial purchasers in the International Offering and the underwriters in the Mexican Offering were granted a 30-day option to purchase additional common shares at the global offering price, less the underwriting discount, to cover overallotments. These options were exercised on October 17, 2016. Sempra Energy also participated in the Mexican Offering by purchasing 83,125,000 shares of common stock for approximately $351 million. After the offerings, including the issuance of shares pursuant to the exercise of the overallotment options, the aggregate shares of common stock sold in the offerings totaled 380,000,000.

The net proceeds of the offerings were approximately $1.57 billion in U.S. dollars or 29.86 billion Mexican pesos. IEnova used the net proceeds of the offerings to repay debt financing, including the $1.15 billion bridge loan from Sempra Global that was used to finance the IEnova Pipelines acquisition, $100 million in loans from its parent and $250 million of borrowings under its revolving credit facility. Additionally, $50 million of net proceeds was used to partially fund the Ventika acquisition. Remaining proceeds were used to fund capital expenditures and for general corporate purposes. We discuss these acquisitions in Note 3.

All U.S. dollar equivalents presented here are based on an exchange rate of 18.96 Mexican pesos to 1.00 U.S. dollar as of October 13, 2016, the pricing date for the offerings. Net proceeds are after reduction for underwriting discounts and commissions and offering expenses. Upon completion of the offerings on October 19, 2016 (including the issuance of shares pursuant to the exercise of the overallotment options), Sempra Energy’s beneficial ownership of IEnova decreased from approximately 81.1 percent to 66.4 percent, which did not result in a change in control. When there are changes in noncontrolling interests of a subsidiary that do not result in a change of control, any difference between carrying value and fair value related to the change in ownership is recorded as an adjustment to shareholders’ equity. As a result of the offerings, we recorded an increase in Sempra Energy’s shareholders’ equity of $281 million, net of $351 million for our participation in the Mexican Offering, and a $948 million increase in Other Noncontrolling Interests for the sale of IEnova shares to third parties.

The International Offering was exempt from registration under the U.S. Securities Act of 1933, as amended (the Securities Act), and shares in the International Offering were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside of the U.S., in accordance with Regulation S under the Securities Act. The shares were not registered under the Securities Act or any state securities laws, and may not be offered or sold in the U.S. absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable securities laws.

Sempra Renewables – Tax Equity Arrangements

In the fourth quarter of 2017, Sempra Renewables entered into membership interest purchase agreements with financial institutions to form two separate tax equity limited liability companies: one that includes a Sempra Renewables’ portfolio of four solar power generation projects located in Fresno County, California and one for a wind power generation project located in Huron County, Michigan. For the solar power generation projects, Sempra Renewables received $104 million, net of offering costs, in tax equity funding for three of the four phases in the fourth quarter of 2017. Additional funding for the fourth phase of the tax equity arrangement is subject to conditions precedent that we expect to occur in the first half of 2018. Under the purchase agreement for the wind power generation project, Sempra Renewables received cash proceeds of $92 million, net of offering costs, and the formation of the tax equity arrangement occurred in December 2017.

In December 2016, Sempra Renewables closed a transaction with a financial institution to form a portfolio tax equity limited liability company that includes three Sempra Renewables solar power generation projects. Also in December 2016, Sempra Renewables closed another transaction with two financial institutions to form a tax equity limited liability company involving a Sempra Renewables wind power generation project. Sempra Renewables received cash proceeds of $474 million, net of offering costs, for the sale of noncontrolling interests relating to these transactions.

Sempra Renewables consolidates these entities and after the funding dates, reports noncontrolling interests representing the financial institutions’ respective membership interests in the tax equity arrangements.

The financial institutions are noncontrolling, tax equity investors that are allocated earnings, tax attributes and cash flows in accordance with the respective limited liability company agreements. Sempra Renewables has determined that these tax equity arrangements represent substantive profit-sharing arrangements. Sempra Renewables has further determined that the appropriate method for attributing income and loss to the noncontrolling interests each period is a balance sheet approach referred to as the HLBV method. Under the HLBV method, the amounts of income and loss attributable to the noncontrolling interests in Sempra Energy’s Consolidated Statements of Operations reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members.

Preferred Stock

The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest at December 31, 2017 and 2016. Sempra Energy records charges against income related to noncontrolling interests for preferred stock dividends declared by SoCalGas. We provide additional information regarding SoCalGas’ preferred stock in Note 11.

Other Noncontrolling Interests

At December 31, 2017 and 2016, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Consolidated Balance Sheets:



OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
	Percent ownership held by others				Equity held by noncontrolling interests
	December 31,				December 31,
	2017		2016		2017		2016
SDG&E:
Otay Mesa VIE	100	%	100	%	$	28	$	37
Sempra South American Utilities:
Chilquinta Energía subsidiaries⁽¹⁾	22.9 - 43.4		23.1 - 43.4		24		22
Luz del Sur	16.4		16.4		189		173
Tecsur	9.8		9.8		4		4
Sempra Mexico:
IEnova⁽²⁾	33.6		33.6		1,532		1,524
Sempra Renewables:
Tax equity arrangements – wind⁽³⁾	NA		NA		181		92
Tax equity arrangements – solar⁽³⁾	NA		NA		450		376
Sempra LNG & Midstream:
Bay Gas	9.1		9.1		28		27
Liberty Gas Storage, LLC	23.3		23.3		14		14
Southern Gas Transmission Company⁽⁴⁾	—		49.0		—		1
Total Sempra Energy					$	2,450	$	2,270


⁽¹⁾	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.


⁽²⁾	IEnova has a subsidiary with a 10-percent noncontrolling interest held by others. The equity held by noncontrolling interests is negligible at December 31, 2017 and 2016.


⁽³⁾	Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.


⁽⁴⁾	We sold our assets in Southern Gas Transmission Company in August 2017.

REVENUES

California Utilities

Our California Utilities generate revenues primarily from deliveries to their customers of electricity by SDG&E and natural gas by both SoCalGas and SDG&E and from related services. We record these revenues following the accrual method and recognize them upon delivery and performance. As described below, recorded revenues include those authorized by the CPUC to support our operations (“decoupled revenue”), as well as commodity costs that are passed through to core gas customers and electric customers:

▪

Decoupled revenue – The regulatory framework permits the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. Any difference between actual demand and the annual demand approved in the proceedings is recovered or refunded in authorized revenue in a subsequent period. This design, commonly known as “decoupling,” is intended to minimize any impact on earnings due to variability in volumetric demand for electricity and natural gas.

▪

Commodity costs – The regulatory framework authorizes the California Utilities to recover the actual cost of natural gas procured and delivered to their core customers in rates substantially as incurred. Actual electricity procurement costs are recovered as power is delivered, or to the extent actual amounts vary from forecasts, generally recovered or refunded within a subsequent period. The California Utilities may also record revenue from CPUC-approved incentive awards, some of which require approval by the CPUC prior to being recognized. SDG&E bids and self-schedules its generation into the CAISO energy market on a day-ahead and real-time basis and self-schedules power to serve the demand of its customers. Generally, SDG&E is a net purchaser of power. The CAISO settles SDG&E costs and revenues on an hourly and real-time net basis.

Sempra South American Utilities

Our electric distribution utilities in South America, Chilquinta Energía and Luz del Sur, serve primarily regulated customers, and their revenues are based on tariffs that are set by the CNE in Chile and the OSINERGMIN in Peru.

The tariffs charged are based on an efficient model distribution company defined by Chilean law in the case of Chilquinta Energía, and OSINERGMIN in the case of Luz del Sur. The tariffs include O&M, an internal rate of return on the new replacement value of depreciable assets, charges for the use of transmission systems, and a component for the value added by the distributor. Tariffs are designed to provide for a pass-through to customers of transmission and energy charges, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base.

Sempra Infrastructure

Our natural gas utilities outside of California apply U.S. GAAP for revenue recognition consistent with the California Utilities, namely Ecogas, our natural gas utility in Mexico, and Mobile Gas and Willmut Gas, our natural gas utilities in Alabama and Mississippi, respectively, that were sold in September 2016.

The table below shows the total utilities revenues in Sempra Energy’s Consolidated Statements of Operations for each of the last three years. The revenues include amounts for services rendered but unbilled (approximately one-half month’s deliveries) at the end of each year.



TOTAL UTILITIES REVENUES AT SEMPRA ENERGY CONSOLIDATED⁽¹⁾
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Electric revenues	$	5,415	$	5,211	$	5,158
Natural gas revenues	4,361		4,050		4,096
Total	$	9,776	$	9,261	$	9,254


⁽¹⁾	Excludes intercompany revenues.

We provide additional information about our utility revenue recognition in “Effects of Regulation” above.

Energy-Related Businesses

Sempra South American Utilities

Sempra South American Utilities generates revenues from energy-services companies that provide electric construction services and recognizes these revenues when services are provided in accordance with contractual agreements. The energy-services company in Chile also generates revenue from selling electricity to non-regulated customers.

Sempra Mexico

Sempra Mexico recognizes revenues from:


▪	pipeline transportation and storage of natural gas, LPG and ethane as capacity is provided. Certain of the revenues recognized from pipelines are under contracts that are accounted for as operating leases;


▪	sale of natural gas as deliveries are made;


▪	an LNG regasification terminal that generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements as capacity is provided;


▪	wind power generation facilities that generate revenues from selling electricity as the power is delivered at the interconnection point; and


▪	TdM, a natural gas-fired power plant that generates revenues from selling electricity and/or capacity to the CAISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point. At December 31, 2017, TdM is classified as held for sale, as we discuss in Note 3.

Sempra Mexico reports revenue net of VAT in Mexico. Sempra Mexico’s revenues also include net realized gains and losses on settlements of energy derivatives and net unrealized gains and losses from the change in fair values of energy derivatives.

Sempra Renewables

For consolidated entities, Sempra Renewables generates revenues from the sale of solar and wind power and related green attributes pursuant to PPAs, and recognizes these revenues when the power is delivered. It also generates revenues for managing certain of its solar and wind project joint ventures. Approximately half of the revenues generated from assets under PPAs are accounted for as operating leases.

Sempra LNG & Midstream

Sempra LNG & Midstream records revenues from contractual counterparty obligations for non-delivery of LNG cargoes, as well as revenues from the sale of LNG and natural gas as deliveries are made to counterparties. Sempra LNG & Midstream also recognizes revenues from natural gas storage and transportation operations for services provided in accordance with contractual agreements. Sempra LNG & Midstream revenues also include net realized gains and losses on settlements of energy derivatives and net unrealized gains and losses from the change in fair values of energy derivatives. Prior to April 2015, Sempra LNG & Midstream generated revenues from selling electricity and/or capacity from its Mesquite Power plant (see Note 3) to the CAISO and to governmental, public utility and wholesale power marketing entities. Sempra LNG & Midstream recognized these revenues as the electricity was delivered and capacity was provided.

OTHER COST OF SALES

Other Cost of Sales primarily includes


▪	pipeline capacity costs, including the permanent release of pipeline capacity in 2016 and the associated recoveries in 2017, at Sempra LNG & Midstream;


▪	pipeline transportation and natural gas marketing costs at Sempra LNG & Midstream;


▪	electric construction services costs at Sempra South American Utilities’ energy-services companies; and


▪	energy management service fees and costs associated with construction performed for and invoiced to third parties at Sempra Mexico.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.

FOREIGN CURRENCY TRANSLATION

Our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI.

Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in “Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash” on the Sempra Energy Consolidated Statements of Cash Flows.

Currency transaction losses in a currency other than the entity’s functional currency were $35 million, $1 million and $7 million for the years ended December 31, 2017, 2016 and 2015, respectively, and are included in Other Income, Net, on the Sempra Energy Consolidated Statements of Operations.

TRANSACTIONS WITH AFFILIATES

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:



AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$	37		$	26

Sempra South American Utilities⁽¹⁾:
Eletrans – 4% Note⁽²⁾	$	103		$	96
Other related party receivables	1			1
Sempra Mexico⁽¹⁾:
IMG – Note due March 15, 2022⁽³⁾	487			—
DEN – Notes due November 14, 2018⁽⁴⁾	—			90
Energía Sierra Juárez – Note⁽⁵⁾	7			14
Total due from unconsolidated affiliates – noncurrent	$	598		$	201

Total due to various unconsolidated affiliates – current	$	(7	)	$	(11	)

Sempra Mexico⁽¹⁾:
Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021⁽⁶⁾	$	(35	)	$	—
SDG&E:
Sempra Energy⁽⁷⁾	$	—		$	3
Various affiliates	—			1
Total due from unconsolidated affiliates – current	$	—		$	4

Sempra Energy	$	(30	)	$	—
SoCalGas	(4		)	(8		)
Various affiliates	(6		)	(7		)
Total due to unconsolidated affiliates – current	$	(40	)	$	(15	)

Income taxes due from Sempra Energy⁽⁸⁾	$	27		$	159
SoCalGas:
Total due from unconsolidated affiliates – current – SDG&E	$	4		$	8

Total due to unconsolidated affiliates – current – Sempra Energy	$	(35	)	$	(28	)

Income taxes due from Sempra Energy⁽⁸⁾	$	10		$	5


⁽¹⁾	Amounts include principal balances plus accumulated interest outstanding.


⁽²⁾	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, comprising joint ventures of Chilquinta Energía.


⁽³⁾	Mexican peso-denominated revolving line of credit for up to $14.0 billion Mexican pesos or approximately $718 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (9.87 percent at December 31, 2017), to finance construction of the natural gas marine pipeline.


⁽⁴⁾	Four U.S. dollar-denominated loans, at a variable interest rate based on the 30-day LIBOR plus 450 bps (5.27 percent at December 31, 2016), to finance the Los Ramones Norte pipeline project. In November 2017, IEnova acquired the remaining 50-percent interest in DEN and DEN became a wholly owned, consolidated subsidiary of IEnova.


⁽⁵⁾	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps (7.94 percent at December 31, 2017) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.


⁽⁶⁾	U.S. dollar-denominated loan, at a variable interest rate based on 6-month LIBOR plus 290 bps (4.74 percent at December 31, 2017).


⁽⁷⁾	At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent.


⁽⁸⁾	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.

Revenues and cost of sales from unconsolidated affiliates are as follows:



REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Revenues:
Sempra Energy Consolidated	$	43	$	25	$	26
SDG&E	8		7		10
SoCalGas	74		76		75
Cost of Sales:
Sempra Energy Consolidated	$	47	$	72	$	107
SDG&E	71		64		49

California Utilities

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra Energy at interest rates based on the federal funds rate plus a margin of 13 to 20 bps, depending on the loan balance.

SoCalGas provides natural gas transportation and storage services for SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.

SDG&E and SoCalGas charge one another, as well as other Sempra Energy affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M.

The natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, revenues and costs related to SDG&E are presented net in SoCalGas’ Statements of Operations.

SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the Energía Sierra Juárez wind power generation facility. Energía Sierra Juárez is a 50-percent owned and unconsolidated joint venture of Sempra Mexico that commenced operations in June 2015.

Sempra Mexico

Sempra Mexico, through its wholly owned subsidiaries, DEN and IEnova Pipelines, provides operating and maintenance services to TAG, and also provides personnel under an administrative services arrangement.

Sempra Renewables

Sempra Renewables, through its wholly owned subsidiary, Sempra Renewables Services, Inc. (formerly known as Sempra Global Services, Inc.), provides project administration and operating and maintenance services to certain of its renewable energy unconsolidated joint ventures.

Sempra LNG & Midstream

Sempra LNG & Midstream provides project administration and operating and maintenance services to Cameron LNG JV, and also provides personnel under an administrative services arrangement.

Sempra LNG & Midstream has an agreement with Rockies Express for capacity on REX. In the second quarter of 2016, Sempra LNG & Midstream permanently released certain pipeline capacity with Rockies Express and others, as we discuss in Note 15.

Guarantees

Sempra Energy has provided guarantees to certain of its joint ventures as we discuss in Note 4.

RESTRICTED NET ASSETS

Sempra Energy Consolidated

As we discuss below, the California Utilities have restrictions on the amount of funds that can be transferred to Sempra Energy by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain other Sempra Energy subsidiaries are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 5) and in other agreements that limit the amount of funds that can be transferred to Sempra Energy. At December 31, 2017, Sempra Energy was in compliance with all covenants related to its debt agreements.

At December 31, 2017, the amount of restricted net assets of consolidated entities of Sempra Energy, including the California Utilities discussed below, that may not be distributed to Sempra Energy in the form of a loan or dividend is $8.6 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $7.4 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra Energy, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends and fund operating needs.

As we discuss in Note 4, $89 million of Sempra Energy’s consolidated retained earnings balance represents undistributed earnings of equity method investments at December 31, 2017.

Sempra Utilities

The CPUC’s regulation of the California Utilities’ capital structures limits the amounts available for dividends and loans to Sempra Energy. At December 31, 2017, Sempra Energy could have received combined loans and dividends of approximately $469 million, funded by long-term debt issuance, from SDG&E and approximately $736 million from SoCalGas.

The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra Energy from either utility:


▪	The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2017 is 52 percent at both SDG&E and SoCalGas.


▪	The FERC requires SDG&E to maintain a common equity ratio of 30 percent or above.


▪	The California Utilities have a combined revolving credit line that requires each utility to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreement) of no more than 65 percent, as we discuss in Note 5.

Based on these restrictions, at December 31, 2017, SDG&E’s restricted net assets were $5.1 billion and SoCalGas’ restricted net assets were $3.2 billion, which could not be transferred to Sempra Energy.

At Sempra South American Utilities, Peru requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $35 million at Luz del Sur at December 31, 2017.

Sempra Infrastructure

Significant restrictions of Sempra Infrastructure subsidiaries include


▪	Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $198 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2017.


▪	Wholly owned IEnova Pipelines has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under this restriction, net assets totaling $19 million are restricted at December 31, 2017.

▪

Wholly owned Ventika has long-term debt agreements that require it to maintain reserve accounts to pay the projects’ debt. The debt agreements may limit the project companies’ ability to incur liens, incur additional indebtedness, make investments, pay cash dividends and undertake certain additional actions. Under these restrictions, net assets totaling $34 million are restricted at December 31, 2017.

▪

Energía Sierra Juárez, a 50-percent owned and unconsolidated joint venture of Sempra Mexico, has long-term debt agreements that require the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit borrowings, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The long-term debt agreements also limit the joint venture’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Under these restrictions, net assets totaling $9 million are restricted at December 31, 2017.


▪	TAG, a 50-percent owned and unconsolidated joint venture of Sempra Mexico, has a long-term debt agreement that requires it to maintain a reserve account to pay projects’ debt. Under these restrictions, net assets totaling $82 million are restricted at December 31, 2017.

▪

Wholly owned Copper Mountain Solar 1 has a long-term debt agreement that requires the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreement. This long-term debt agreement also limits the solar project’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions, while also requiring maintenance of certain debt ratios. Under these restrictions, net assets totaling $8 million are restricted at December 31, 2017.

▪

Tax equity limited liability companies at Sempra Renewables are required to maintain completion reserve depository accounts to be used to pay for trailing construction costs that become due subsequent to the tax equity transaction closing. At December 31, 2017, as a result of these requirements, there were total restricted net assets at these tax equity limited liability companies of approximately $19 million.

▪

50- and 25-percent owned and unconsolidated joint ventures at Sempra Renewables have debt agreements that require each joint venture to maintain reserve accounts in order to pay the projects’ debt service and O&M requirements. We discuss Sempra Energy guarantees associated with these requirements in Note 4. At December 31, 2017, as a result of these requirements, there were total restricted net assets at these joint ventures of approximately $265 million.

▪

Sempra LNG & Midstream has an equity method investment in Cameron LNG JV, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the joint venture to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the joint venture. We discuss Sempra Energy guarantees associated with Cameron LNG JV’s debt agreements in Note 4. Under these restrictions, net assets of Cameron LNG JV of approximately $7.0 billion are restricted at December 31, 2017.

OTHER INCOME, NET

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



OTHER INCOME, NET
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	168		$	116		$	107
Investment gains⁽¹⁾	56			23			3
Gains (losses) on interest rate and foreign exchange instruments, net	47			(32		)	(4		)
Foreign currency transaction losses⁽²⁾	(35		)	(1		)	(7		)
Sale of other investments	3			5			11
Electrical infrastructure relocation income	3			10			7
Interest on regulatory balancing accounts, net	3			4			3
Sundry, net	9			7			6
Total	$	254		$	132		$	126
SDG&E:
Allowance for equity funds used during construction	$	63		$	46		$	37
Interest on regulatory balancing accounts, net	3			3			3
Sundry, net	—			1			(4		)
Total	$	66		$	50		$	36
SoCalGas:
Allowance for equity funds used during construction	$	44		$	40		$	36
Interest on regulatory balancing accounts, net	—			1			—
Sundry, net	(8		)	(9		)	(6		)
Total	$	36		$	32		$	30


⁽¹⁾	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Consolidated Statements of Operations.


⁽²⁾	Includes $35 million loss from translation of Mexican peso-denominated loan to IMG JV to U.S. dollars.

NEW ACCOUNTING STANDARDS

12 Months Ended

Dec. 31, 2017

Accounting Changes and Error Corrections [Abstract]

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.

ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606.

ASU 2015-14 defers the effective date of ASC 606 by one year for all entities and permits early adoption on a limited basis. For public entities, ASC 606 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which will result in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification has no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers will be included in our Notes to Consolidated Financial Statements beginning in the first quarter of 2018.

ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively. There is an outstanding FASB exposure draft which clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected.

For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2016-01 on January 1, 2018 and it will not materially affect our financial condition, results of operations or cash flows.

ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP.

For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance described above. We continue to monitor outstanding issues currently being addressed by the FASB, including guidance under a FASB exposure draft that would allow entities an optional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented. Conclusions that the FASB reaches on outstanding issues may impact our application of these ASUs.

ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses.

For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues:


▪	Issue 1 – debt prepayment or debt extinguishment costs


▪	Issue 3 – contingent consideration payments made after a business combination


▪	Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies)

ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents. ASU 2016-15 and ASU 2016-18 must be adopted retrospectively. We early adopted ASU 2016-15 and ASU 2016-18 in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Statements of Cash Flows.

Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities – other	$	63		$	(1	)	$	62		$	66		$	—		$	66
Changes in other assets	56			(7		)	49			(162		)	(7		)	(169		)
Net cash provided by operating activities	2,319			(8		)	2,311			2,905			(7		)	2,898

Cash flows from investing activities:
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired	(1,582		)	1,582			—			(200		)	200			—
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired	—			(1,504		)	(1,504		)	—			(198		)	(198		)
Increases in restricted cash	(139		)	139			—			(100		)	100			—
Decreases in restricted cash	175			(175		)	—			93			(93		)	—
Other	—			9			9			1			8			9
Net cash used in investing activities	(4,886		)	51			(4,835		)	(2,885		)	17			(2,868		)

Cash flows from financing activities:
Other	(10		)	(11		)	(21		)	(17		)	(3		)	(20		)
Net cash provided by (used in) financing activities	2,513			(11		)	2,502			(173		)	(3		)	(176		)

Effect of exchange rate changes on cash and cash equivalents	—			—			—			(14		)	14			—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—			(3		)	(3		)	—			(14		)	(14		)

Decrease in cash and cash equivalents	(54		)	54			—			(167		)	167			—
Decrease in cash, cash equivalents, and restricted cash	—			(25		)	(25		)	—			(160		)	(160		)

Cash and cash equivalents, January 1	403			(403		)	—			570			(570		)	—
Cash, cash equivalents and restricted cash, January 1	—			450			450			—			610			610
Cash and cash equivalents, December 31	349			(349		)	—			403			(403		)	—
Cash, cash equivalents and restricted cash, December 31	—			425			425			—			450			450
SDG&E Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Changes in other assets	$	(16	)	$	(4	)	$	(20	)	$	(122	)	$	(3	)	$	(125	)
Net cash provided by operating activities	1,327			(4		)	1,323			1,664			(3		)	1,661

Cash flows from investing activities:
Increases in restricted cash	(49		)	49			—			(39		)	39			—
Decreases in restricted cash	60			(60		)	—			35			(35		)	—
Other	—			6			6			—			5			5
Net cash used in investing activities	(1,319		)	(5		)	(1,324		)	(1,086		)	9			(1,077		)

Cash flows from financing activities:
Other⁽¹⁾	(4		)	(2		)	(6		)	(2		)	(2		)	(4		)
Net cash used in financing activities	(20		)	(2		)	(22		)	(566		)	(2		)	(568		)

(Decrease) increase in cash and cash equivalents	(12		)	12			—			12			(12		)	—
(Decrease) increase in cash, cash equivalents, and restricted cash	—			(23		)	(23		)	—			16			16

Cash and cash equivalents, January 1	20			(20		)	—			8			(8		)	—
Cash, cash equivalents and restricted cash, January 1	—			43			43			—			27			27
Cash and cash equivalents, December 31	8			(8		)	—			20			(20		)	—
Cash, cash equivalents and restricted cash, December 31	—			20			20			—			43			43

⁽¹⁾ Previously labeled “Debt issuance costs.”

ASU 2017-01, “Clarifying the Definition of a Business”: ASU 2017-01 narrows the definition of a business and provides a framework to assist entities in determining whether a transaction involves an asset or a business. Specifically, the ASU provides a “screen” for determining when an integrated set of assets and activities (collectively referred to as a “set”) is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted. We early adopted ASU 2017-01 on July 1, 2017.

ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard.

ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. Entities may apply a full retrospective or modified retrospective approach. Under a modified retrospective approach, entities are required to apply the guidance to any transactions that are not completed as of the adoption date. We adopted the standard in conjunction with our adoption of ASC 606 on January 1, 2018 using the modified retrospective transition method. As we discuss in Note 1, Sempra Renewables expects the formation of a tax equity arrangement to be completed in the first half of 2018. While the arrangement would be in the scope of this ASU, we do not expect it to have a material impact on our financial condition, results of operations or cash flows.

ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017				2016
	As reported		Recast		As reported		Recast
Sempra Energy Consolidated Statements of Operations:
Operation and maintenance	$	3,117	$	3,096	$	2,970	$	2,976
Other income, net	254		233		132		138
SDG&E Consolidated Statements of Operations:
Operation and maintenance	$	1,020	$	1,024	$	1,048	$	1,062
Operating income	713		709		990		976
Other income, net	66		70		50		64
SoCalGas Statements of Operations:



Operation and maintenance	$	1,479	$	1,474	$	1,385	$	1,391
Operating income	622		627		557		551
Other income, net	36		31		32		38

ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. For public entities, ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. If an entity early adopts ASU 2017-12 in an interim period, any transition adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. Entities will adopt ASU 2017-12 by applying a modified retrospective approach to the accounting for existing hedging relationships and will prospectively apply the new presentation and disclosure requirements. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018, and it will not materially affect our financial condition, results of operations or cash flows.

ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard.

ACQUISTION AND DIVESTITURE ACTIVITY

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquistion and divestiture activity

ACQUISITION AND DIVESTITURE ACTIVITY

We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

ACQUISITIONS

SEMPRA MEXICO

2017 Acquisition

Ductos y Energéticos del Norte, S. de R.L. de C.V.

On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50-percent interest in DEN, a joint venture that holds a 50-percent interest in the Los Ramones Norte pipeline through TAG, for a purchase price of $165 million (exclusive of $18 million of cash and cash equivalents acquired), plus the assumption of $96 million of short-term debt. This acquisition increased IEnova’s ownership interest in DEN through IEnova Pipelines from 50 percent to 100 percent, and increased IEnova’s indirect ownership interest in TAG from 25 percent to 50 percent. IEnova Pipelines previously accounted for its 50-percent interest in DEN as an equity method investment. At closing, DEN became a wholly owned, consolidated subsidiary of IEnova Pipelines. DEN will continue to account for its interest in TAG as an equity method investment. This acquisition also included a $66 million intangible asset that represents a favorable O&M agreement, which has an amortization period of 23 years.

2016 Acquisitions

The following table summarizes the total fair value of the 2016 business combinations at Sempra Mexico, described below, and the final purchase price allocations of the assets acquired and liabilities assumed at the dates of acquisition:



PURCHASE PRICE ALLOCATIONS
(Dollars in millions)
	IEnova Pipelines			Ventika
	At September 26, 2016⁽¹⁾			At December 14, 2016⁽²⁾
Fair value of business combination:
Cash consideration (fair value of total consideration)	$	1,144		$	310
Fair value of equity interest in IEnova Pipelines immediately prior to acquisition	1,144			—
Total fair value of business combination	$	2,288		$	310

Recognized amounts of identifiable assets acquired and liabilities assumed:
Cash and cash equivalents	$	66		$	—
Restricted cash	—			68
Accounts receivable	39			14
Other current assets	6			1
Other intangible assets	—			154
Deferred income taxes	—			36
Regulatory assets	33			—
Property, plant and equipment	1,248			673
Other noncurrent assets	1			3
Short-term debt	—			(125		)
Accounts payable	(11		)	(1		)
Due to unconsolidated affiliates	(3		)	—
Current portion of long-term debt	(49		)	(7		)
Fixed-price contracts and other derivatives, current	(6		)	(4		)
Other current liabilities	(20		)	(8		)
Long-term debt	(315		)	(478		)
Asset retirement obligations	(5		)	(2		)
Deferred income taxes	(127		)	(120		)
Fixed-price contracts and other derivatives, noncurrent	(19		)	(10		)
Other noncurrent liabilities	(11		)	—
Total identifiable net assets	827			194
Goodwill	1,461			116
Total fair value of business combination	$	2,288		$	310

⁽¹⁾

During the fourth quarter of 2016, we received additional information regarding IEnova Pipelines’ deferred income taxes as of the acquisition date, primarily related to basis differences in IEnova Pipelines’ PP&E. As a result, we recorded measurement period adjustments that resulted in a net increase to goodwill of $86 million, an increase in deferred income tax liabilities of $119 million and $33 million of regulatory assets related to deferred income taxes on AFUDC.


⁽²⁾	During the fourth quarter of 2017, we received additional information regarding Ventika’s deferred income taxes as of the acquisition date, primarily related to net operating loss carryforwards. As a result, we recorded a measurement period adjustment that resulted in a decrease to goodwill and an increase in deferred income tax assets of $13 million.

IEnova Pipelines, S. de R.L. de C.V. (formerly known as Gasoductos de Chihuahua, S. de R.L. de C.V., or GdC)

Background and Financing. On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in IEnova Pipelines, which develops and operates energy infrastructure in Mexico, for a purchase price of $1.144 billion (exclusive of $66 million of cash and cash equivalents acquired), plus the assumption of $364 million of long-term debt, increasing IEnova’s ownership interest in IEnova Pipelines to 100 percent. IEnova Pipelines became a consolidated subsidiary of IEnova on this date. Prior to the acquisition date, IEnova owned 50 percent of IEnova Pipelines and accounted for its interest as an equity method investment.

The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excluded the Los Ramones Norte pipeline, in which IEnova continued to hold an indirect 25-percent ownership interest through IEnova Pipelines’ interest in DEN until November 2017, as we discuss above.

IEnova paid $1.078 billion in cash ($1.144 billion purchase price less $66 million of cash and cash equivalents acquired), which was funded using interim financing provided by Sempra Global through a $1.15 billion bridge loan to IEnova. Sempra Global funded the majority of the transaction using commercial paper borrowings. As we discuss in Note 1, in October 2016, IEnova completed a private follow-on offering of its common stock in the U.S. and outside of Mexico and a concurrent public common stock offering in Mexico. IEnova used a portion of the net proceeds from the offerings to fully repay the Sempra Global bridge loan.

Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on their respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. None of the goodwill is expected to be deductible in Mexico or the U.S. for income tax purposes.

Gain on Remeasurement of Equity Method Investment. In the year ended December 31, 2016, we recorded a pretax gain of $617 million ($432 million after-tax) for the excess of the acquisition-date fair value of Sempra Mexico’s previously held equity interest in IEnova Pipelines over the carrying value of that interest, included as Remeasurement of Equity Method Investment on the Sempra Energy Consolidated Statement of Operations. We used a market approach to measure the acquisition-date fair value of IEnova’s equity interest in IEnova Pipelines immediately prior to the business acquisition. We discuss non-recurring fair value measures and the associated accounting impact of the IEnova Pipelines acquisition in Note 10.

Valuation of IEnova Pipelines’ Assets and Liabilities. Based on the nature of the Mexico regulatory environment and the oversight surrounding the establishment and maintenance of rates that IEnova Pipelines charges for services on its assets, IEnova Pipelines applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Therefore, when determining the fair value of the acquired assets and liabilities assumed, we considered the effect of regulation on a market participant’s view of the highest and best use of the assets, in particular for the fair value of IEnova Pipelines’ PP&E. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s PP&E, and the impact of regulation is considered a fundamental input to measuring the fair value of PP&E in a business combination involving a regulated business.

Under this premise, the fair value of the PP&E of a regulated business is generally assumed to be equivalent to carrying value for financial reporting purposes. Management concluded that the carrying value of IEnova Pipelines’ PP&E is representative of fair value.

We applied an income approach, specifically the discounted cash flow method, to measure the fair value of debt and derivatives. We valued debt by discounting future debt payments by a market yield, and we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data.

For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature.

Impact on Operating Results. We incurred acquisition costs of $4 million and $1 million in the years ended December 31, 2016 and 2015, respectively. These costs are included in Operation and Maintenance on the Sempra Energy Consolidated Statements of Operations.

For the year ended December 31, 2016, the Sempra Energy Consolidated Statement of Operations includes $82 million of revenues and $33 million of earnings (after noncontrolling interests) from IEnova Pipelines since the September 26, 2016 date of acquisition.

Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V.

Background and Financing. On December 14, 2016, IEnova acquired 100 percent of the equity interests in the Ventika wind power generation facilities for cash consideration of $310 million and the assumption of $610 million of existing debt. Ventika is a 252-MW wind farm located in Nuevo Leon, Mexico, that began commercial operations in April 2016. All of Ventika’s generation capacity is contracted under 20-year, U.S. dollar-denominated PPAs with five private off-takers. The acquisition was funded using $50 million of net proceeds from the IEnova equity offerings that we discuss in Note 1, $250 million of borrowings against Sempra Mexico’s revolving credit facility, and $10 million of available cash at IEnova. The acquisition also included $68 million of restricted cash that represents funds set aside for servicing debt, operations, and other costs pursuant to the long-term debt agreements.

Valuation of Ventika’s Assets and Liabilities. The fair values of the tangible and intangible assets acquired and liabilities assumed were recognized based on their preliminary values at the acquisition date. Significant inputs used to measure the fair values of the acquired PP&E, intangible asset, debt, and derivatives are as follows:


▪	PP&E – We applied an income approach using market-based discounted cash flows. We used the pricing included in the existing PPAs, which was determined to reflect current market rates in the Mexican renewable energy market.

▪

Intangible asset – Ventika is the holder of a renewable energy transmission and consumption permit that allows it to transmit its generated power to various locations within Mexico at beneficial rates and reduces the administrative burden to manage transmitting power to off-takers. With recent renewable energy market reforms in Mexico, these transmission and consumption permits are no longer available, resulting in higher tariffs for generators. We applied an income approach based on a cash flow differential approach that measures the fair value of the transmission rights by comparing the operating expenses under the transmission and consumption permit as compared to under the new, higher tariffs. This acquired intangible asset has an amortization period of 19 years, reflecting the remaining life of the transmission and consumption transmission permit at the time of acquisition.


▪	Debt – Using an income approach, we valued debt by discounting future debt payments by a market yield commensurate with the remaining term of the loans.


▪	Derivatives – Using an income approach, we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data.

Additionally, we recognized deferred income taxes on Ventika’s existing NOLs, and for the difference between the fair values and tax bases of the net assets acquired using the Mexican statutory rate.

For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature.

Impact on Operating Results. We incurred acquisition costs of $1 million in the year ended December 31, 2016, which are included in Operation and Maintenance on the Sempra Energy Consolidated Statement of Operations.

For the year ended December 31, 2016, the Sempra Energy Consolidated Statement of Operations includes $4 million of revenues and $3 million of earnings (after noncontrolling interests) from Ventika since the December 14, 2016 date of acquisition.

Unaudited Pro Forma Information

The following table presents unaudited pro forma information for the years ended December 31, 2016 and 2015, combining the historical results of operations of Sempra Energy, IEnova Pipelines and Ventika as though the acquisitions occurred on January 1, 2015. The pro forma information is not necessarily indicative of results that would have been achieved had the businesses been combined during the periods presented or the results that we will experience going forward.



UNAUDITED PRO FORMA INFORMATION – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Years ended December 31,
	2016		2015
Revenues	$	10,463	$	10,473
Net income	1,145		1,938
Earnings	1,058		1,641

The unaudited pro forma information above assumes


▪	the related IEnova equity offerings, discussed above and in Note 1, occurred on January 1, 2015, which results in a change in Sempra Energy’s noncontrolling interest in IEnova from 18.9 percent to 33.6 percent for all periods presented;


▪	the proceeds from the IEnova equity offerings were used to fund the acquisitions, instead of the bridge loan that was provided by Sempra Global to IEnova for the IEnova Pipelines acquisition, therefore interest expense on the commercial paper borrowings supporting the bridge loan is excluded for all periods presented;


▪	interest expense on the borrowings against Sempra Mexico’s revolving credit facility began when Ventika’s commercial operations commenced in April 2016;


▪	equity earnings, net of income tax, from IEnova Pipelines that were previously included in Sempra Energy’s results have been excluded for both periods presented;


▪	the gain related to the remeasurement of our previously held equity interest in IEnova Pipelines has been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude the gain; and


▪	acquisition-related transaction costs have been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude them.

Most of Sempra Mexico’s operations, including IEnova Pipelines and Ventika, use the U.S. dollar as their functional currency.

SEMPRA RENEWABLES

On July 10, 2017, Sempra Renewables paid $124 million in cash for an asset acquisition of a portfolio of four solar projects located in Fresno County, California, that were under construction. We placed three of the four projects into service in the fourth quarter of 2017 and expect to place the fourth project into service in the first half of 2018. When fully constructed, the portfolio will be capable of producing up to 200 MW of solar power. The solar projects are fully contracted under four long-term PPAs, with an average contract term of 18 years.

In July 2016, Sempra Renewables acquired a 100-percent interest in a 100-MW wind farm in Huron County, Michigan, with a 15-year PPA, for a total purchase price of $22 million. Sempra Renewables paid $18 million in cash on the acquisition date and paid the remaining $4 million in cash on achievement of certain construction milestones in the fourth quarter of 2016. We placed this wind farm into service in November 2017.

In March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest in a 78-MW wind development project in Stearns County, Minnesota. The wind farm has a 20-year PPA with a load serving entity and began commercial operation in December 2016.

PENDING ACQUISITION

SEMPRA ENERGY

Energy Future Holdings Corp.

On August 21, 2017, Sempra Energy entered into an Agreement and Plan of Merger, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018 (together referred to as the Merger Agreement), with Energy Future Holdings Corp., the indirect owner of 80.03 percent of Oncor Electric Delivery Company LLC. Oncor is a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. Following closing, this acquisition will expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region. Under the Merger Agreement, we will pay the Merger Consideration of $9.45 billion in cash.

Pursuant to the Merger Agreement and subject to the satisfaction of certain closing conditions described below, EFH will be merged with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy (the Merger), as follows:



The foregoing is a simplified ownership structure that does not show all the subsidiaries of, or other equity interests owned by, these entities.

TTI, an investment vehicle indirectly owned by third parties unaffiliated with EFH or Sempra Energy, owns 19.75 percent of Oncor’s outstanding membership interests, and certain current and former directors and officers of Oncor indirectly beneficially own 0.22 percent of Oncor’s outstanding membership interests through their ownership of Class B membership interests in OMI. On October 3, 2017, Sempra Energy provided written confirmation to Oncor Holdings and Oncor that, contemporaneously with the closing of the Merger, equivalent value (approximately $25.9 million) will be provided in exchange for the Class B membership interests in OMI for cash or, if mutually agreed by the parties, alternative benefit and/or incentive plans. The consummation of the Merger is not conditioned on the acquisition of the interest in OMI, and there has been no formal agreement by us or the owners of these interests to accept the terms of our written confirmation.

Merger Consideration and Financing

Under the Merger Agreement, Sempra Energy will pay Merger Consideration of $9.45 billion in cash. We intend to initially finance the Merger Consideration of $9.45 billion, as well as associated transaction costs, with the net proceeds from debt and equity issuances, including proceeds from the common stock, mandatory convertible preferred stock and debt offerings completed in January 2018, which we discuss in Note 18, and initial additional financing consisting of up to $2.7 billion aggregate principal amount of commercial paper, although we may reduce the amount of commercial paper by borrowings under our revolving credit facilities and cash from operations. We expect to ultimately fund approximately 65 percent of the Merger Consideration, along with the associated transaction costs, with the net proceeds from sales of Sempra Energy common stock and other equity securities and approximately 35 percent with the net proceeds from issuances of Sempra Energy debt securities. However, we may use cash from operations and proceeds from asset sales in place of some of the equity financing. Some of the equity issuances will likely occur following the Merger, including common stock to be sold pursuant to the forward sale agreements entered into in connection with the common stock offering discussed in Note 18, to repay outstanding indebtedness, including indebtedness we incur to initially finance the Merger Consideration and associated transaction costs. The total amount of equity we ultimately issue may be reduced by cash from operations and proceeds from asset sales.

In addition, we have agreed that, within 60 days of the Merger, we will contribute our proportionate share of the aggregate investment in Oncor in an amount necessary for Oncor to achieve a capital structure consisting of 57.5 percent long-term debt and 42.5 percent equity, as calculated for regulatory purposes.

We have incurred transaction costs of $43 million as of December 31, 2017. These costs are included in Sundry on the Sempra Energy Consolidated Balance Sheet, and will be charged against related gross proceeds of equity offerings, debt offerings and/or included in the basis of EFH’s equity method investment in Oncor Holdings upon consummation of the Merger. If the Merger does not occur, the transaction costs that would be included in the basis of EFH’s equity method investment in Oncor Holdings will be expensed.

Ring-Fencing

In April 2014, EFH and the substantial majority of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court. The bankruptcy does not include Oncor Holdings or Oncor. Certain existing “ring-fencing” measures, governance mechanisms and restrictions will remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. In accordance with the ring-fencing measures and commitments made by Sempra Energy as part of the Joint Application to the PUCT for regulatory approval of the Merger, and the Stipulation with key stakeholders entered into in connection with that proceeding, Sempra Energy and Oncor will be subject to certain restrictions following the Merger. Sempra Energy will not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions will limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. These limitations include limited representation on the Oncor Holdings and Oncor boards of directors. Following consummation of the Merger, if the Stipulation is approved by the PUCT, the board of directors of Oncor is expected to consist of thirteen members and be constituted as follows:

▪

seven members will be independent directors in all material respects under the rules of the New York Stock Exchange in relation to Sempra Energy and its subsidiaries and affiliated entities and any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings (and those directors must have no material relationship with Sempra Energy or its affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings at the time of the Merger or within the previous ten years) (“independent directors”);


▪	two members will be designated by Sempra Energy;


▪	two members will be appointed by TTI. If Sempra Energy acquires TTI’s interest in Oncor, the two board positions on the Oncor board of directors that TTI is entitled to appoint shall be eliminated, and the size of the Oncor board of directors will be reduced by two; and

▪

two members will be current or former officers of Oncor (the Oncor Officer Directors). In order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, such officer cannot have worked for Sempra Energy or any of its affiliates (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten years prior to such officer being employed by Oncor. Oncor Holdings, at the direction of EFIH (a subsidiary of EFH, which will be a wholly owned indirect subsidiary of, and controlled by, Sempra Energy following the Merger), will have the right to nominate and/or seek the removal of the Oncor Officer Directors, with such nomination or removal subject to approval by a majority of the Oncor board of directors.

Oncor Holdings will also continue to have a majority of independent directors following the consummation of the Merger. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced). Upon consummation of the acquisition, we will consolidate EFH, and EFH will continue to account for its ownership interest in Oncor Holdings as an equity method investment.

Settlement Agreement Regarding Joint Application

In December 2017 and January 2018, Sempra Energy and Oncor entered into a comprehensive Stipulation with 10 intervening parties, including the Staff of the PUCT, reflecting the parties’ settlement of all issues in the PUCT proceeding regarding the Joint Application. Pursuant to the Stipulation, the parties have agreed that Sempra Energy’s acquisition of EFH is in the public interest and will bring substantial benefits.

The Stipulation includes regulatory commitments by Sempra Energy, most of which are similar to the regulatory commitments made by Sempra Energy as part of the Joint Application and are consistent with the “ring-fencing” measures currently in place. Sempra Energy and Oncor are entitled to seek modifications of the PUCT order to be entered in the proceedings regarding the Joint Application, which modifications would be subject to PUCT approval.

On January 5, 2018, Oncor, Sempra Energy and the Staff of the PUCT jointly filed with the PUCT, requesting that the PUCT approve the Merger consistent with the Stipulation. As of January 31, 2018, all 10 intervening parties including the Staff of the PUCT, had agreed to the Stipulation.

Closing Conditions

The Merger is subject to customary closing conditions, including the approval of the Bankruptcy Court, the PUCT, the Vermont Department of Financial Regulation, and the FERC, among others, as well as receipt of a private letter ruling from the IRS and the issuance of certain tax opinions regarding the Merger.

On September 6, 2017, the Bankruptcy Court approved EFH’s and EFIH’s entry into the Merger Agreement. Under the terms of the Merger Agreement, a $190 million termination fee would be owed to Sempra Energy if EFH or EFIH terminates the Merger Agreement in certain circumstances and consummates an alternative proposal with a third party.

On October 5, 2017, Sempra Energy and Oncor filed a joint application with the PUCT and an application with the FERC seeking approval of the Merger. On October 12, 2017, the ALJ in the PUCT proceeding issued an order deeming the joint application sufficient. On October 16, 2017, the PUCT set a procedural schedule to complete a review of Sempra Energy’s and Oncor’s change-in-control request within 180 days of the filing of the joint application on October 5, 2017.

On November 2, 2017, EFH received a supplemental private letter ruling from the IRS that provides that the Merger will not affect the tax-free treatment of the 2016 Vistra (formerly TCEH Corp.) spinoff from EFH. This ruling satisfies the closing condition described above.

On November 29, 2017, Sempra Energy received the necessary approval from the Vermont Department of Financial Regulation.

On December 11, 2017, the FERC issued an order authorizing the Merger, subject to customary conditions.

On February 26, 2018, the Bankruptcy Court held a hearing to consider confirmation of EFH’s plan of reorganization and final approval of the Merger. At the conclusion of the hearing, the Bankruptcy Court ruled that it will confirm the plan of reorganization and approve the Merger and that it will promptly enter an order reflecting such ruling.

We currently expect the Merger will close in the first half of 2018, although there can be no assurance that the Merger will be completed on that timetable, or at all.

ASSETS HELD FOR SALE

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next 12 months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs.

SEMPRA MEXICO

Termoeléctrica de Mexicali

In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified it as held for sale.

In connection with the sales process, in late September 2016 and early July 2017, Sempra Mexico received market information indicating that the fair value of TdM was less than its carrying value. After performing analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing noncash impairment charges of $131 million ($111 million after-tax) in the third quarter of 2016 and $71 million in the second quarter of 2017, recorded in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. We discuss non-recurring fair value measures and the associated accounting impact on TdM in Note 10.

In connection with TdM’s classification as held for sale, we recognized an $8 million income tax benefit in 2017 and an $8 million income tax expense in 2016, for a deferred Mexican income tax liability related to the excess of carrying value over the tax basis. As the Mexican income tax on this outside basis difference is based on current carrying value, foreign exchange rates and inflation, such amount could change in future periods until the date of sale. We continue to actively pursue the sale of TdM, which we expect to be completed in 2018.

At December 31, 2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows:



ASSETS HELD FOR SALE AT DECEMBER 31, 2017
(Dollars in millions)
	TdM
Inventories	$	10
Other current assets	59
Property, plant and equipment, net	56
Other noncurrent assets	2
Total assets held for sale	$	127

Accounts payable	$	5
Other current liabilities	38
Asset retirement obligations	5
Other noncurrent liabilities	1
Total liabilities held for sale	$	49

DIVESTITURES

SEMPRA RENEWABLES

Rosamond Solar

In December 2015, Sempra Renewables sold its 100-percent interest in Rosamond Solar, a development project located in Antelope Valley, California for $26 million in cash. Upon completion of the sale that was comprised of $18 million of net PP&E, Sempra Renewables recognized a pretax gain of $8 million ($5 million after-tax), which is included in Gain on Sale of Assets on our Consolidated Statement of Operations.

SEMPRA LNG & MIDSTREAM

EnergySouth Inc.

In September 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas, to Spire Inc. (formerly The Laclede Group, Inc.) for cash proceeds of $318 million, net of $2 million cash sold, with the buyer assuming debt of $67 million. We recognized a pretax gain on the sale of $130 million ($78 million after-tax) in the year ended December 31, 2016, in Gain on Sale of Assets on Sempra Energy’s Consolidated Statement of Operations. On September 12, 2016, Sempra LNG & Midstream deconsolidated EnergySouth.

The following table summarizes the deconsolidation:



DECONSOLIDATION OF SUBSIDIARY
(Dollars in millions)
	EnergySouth
Proceeds from sale, net of transaction costs	$	304
Cash	(2		)
Other current assets	(17		)
Property, plant and equipment, net	(199		)
Goodwill	(72		)
Other noncurrent assets	(65		)
Current liabilities	25
Long-term debt	67
Other noncurrent liabilities	89
Gain on sale	$	130

Investment in Rockies Express

In March 2016, Sempra LNG & Midstream entered into an agreement to sell its 25-percent interest in Rockies Express to a subsidiary of Tallgrass Development, LP for cash consideration of $440 million, subject to adjustment at closing. The transaction closed in May 2016 for total cash proceeds of $443 million.

At the date of the agreement, the carrying value of Sempra LNG & Midstream’s investment in Rockies Express was $484 million. Following the execution of the agreement, Sempra LNG & Midstream measured the fair value of its equity method investment at $440 million, and recognized a $44 million ($27 million after-tax) impairment in Equity Earnings, Before Income Tax, on the Sempra Energy Consolidated Statement of Operations. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 10.

We discuss Sempra LNG & Midstream’s 2016 permanent release of pipeline capacity that it held with Rockies Express and others in Note 15.

Mesquite Power Plant

In April 2015, Sempra LNG & Midstream sold the remaining 625-MW block of the Mesquite Power plant that was classified as held for sale at December 31, 2014, together with a related power sales contract, for net cash proceeds of $347 million. We recognized a pretax gain on the sale of $61 million ($36 million after-tax), included in Gain on Sale of Assets on our Consolidated Statement of Operations.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

12 Months Ended

Dec. 31, 2017

INVESTMENTS IN UNCONSOLIDATED ENTITIES

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. We adjust each investment for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss. We evaluate the carrying value of unconsolidated entities for impairment under the U.S. GAAP provisions for equity method investments.

We provide the carrying value of our investments and earnings (losses) on these investments below:



EQUITY METHOD AND OTHER INVESTMENT BALANCES
(Dollars in millions)
	December 31,
	2017		2016
Sempra South American Utilities:
Eletrans⁽¹⁾	$	16	$	(8	)
Sempra Mexico:
DEN	—		42
Energía Sierra Juárez⁽²⁾	39		38
IMG⁽³⁾	221		100
TAG⁽⁴⁾	364		—
Sempra Renewables:
Wind:
Auwahi Wind	42		41
Broken Bow 2 Wind	32		35
Cedar Creek 2 Wind	72		75
Flat Ridge 2 Wind	255		271
Fowler Ridge 2 Wind	44		43
Mehoopany Wind	89		92
Solar:
California solar partnership	107		113
Copper Mountain Solar 2	35		33
Copper Mountain Solar 3	44		42
Mesquite Solar 1	81		86
Other	12		13
Sempra LNG & Midstream:
Cameron LNG JV⁽⁵⁾	997		997
Parent and other:
RBS Sempra Commodities	67		67
Total equity method investments	2,517		2,080
Other	10		17
Total	$	2,527	$	2,097


⁽¹⁾	Reflects losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the CLF relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018.


⁽²⁾	The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014.


⁽³⁾	The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees, which we discuss below.


⁽⁴⁾	The carrying value of our equity method investment is $130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.


⁽⁵⁾	The carrying value of our equity method investment is $237 million and $190 million higher than the underlying equity in the net assets of the investee at December 31, 2017 and 2016, respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations.



EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Earnings (losses) recorded before income tax:
Sempra Renewables:
Wind:
Auwahi Wind	$	5		$	4		$	4
Broken Bow 2 Wind	(2		)	(2		)	(2		)
Cedar Creek 2 Wind	(2		)	(2		)	(6		)
Flat Ridge 2 Wind	(13		)	(7		)	(12		)
Fowler Ridge 2 Wind	4			4			4
Mehoopany Wind	(1		)	—			(1		)
Solar:
California solar partnership	7			7			6
Copper Mountain Solar 2	5			6			7
Copper Mountain Solar 3	8			8			8
Mesquite Solar 1	18			17			16
Other	—			(1		)	—
Sempra LNG & Midstream:
Cameron LNG JV	5			(2		)	5
Rockies Express Pipeline	—			(26		)	79
Parent and other:
RBS Sempra Commodities	—			—			(4		)
	$	34		$	6		$	104
Earnings (losses) recorded net of income tax⁽¹⁾:
Sempra South American Utilities:
Eletrans	$	4		$	3		$	(4	)
Sempra Mexico:
DEN	(13		)	5			—
Energía Sierra Juárez	—			6			6
IEnova Pipelines	—			64			83
IMG	45			—			—
TAG	6			—			—
	$	42		$	78		$	85


⁽¹⁾	As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our ETR.

Our share of the undistributed earnings of equity method investments was $89 million and $44 million at December 31, 2017 and 2016, respectively. These balances do not include remaining distributions of $67 million associated with our investment in RBS Sempra Commodities and expected to be received from the partnership as it is dissolved, as we discuss below.

SEMPRA SOUTH AMERICAN UTILITIES

In February 2017, Sempra South American Utilities recorded the equitization of its $19 million note receivable due from Eletrans,

resulting in an increase in its investment in this unconsolidated joint venture. During the year ended December 31, 2017, Sempra South American Utilities invested cash of $1 million in Eletrans.

SEMPRA MEXICO

IEnova Pipelines, DEN and TAG

On September 26, 2016, IEnova completed the acquisition of the remaining 50-percent interest in IEnova Pipelines and IEnova Pipelines became a consolidated subsidiary. Prior to the acquisition date, IEnova owned 50 percent of IEnova Pipelines and accounted for its interest as an equity method investment. As of the acquisition date, IEnova accounted for IEnova Pipelines’ 50-percent interest in DEN as an equity method investment.

On November 15, 2017, IEnova acquired the remaining 50-percent interest in DEN, and DEN became a consolidated subsidiary. Since the acquisition date, IEnova accounts for DEN’s 50-percent interest in TAG as an equity method investment. We discuss these acquisitions in Note 3.

IMG

In June 2016, IMG, a joint venture between IEnova and a subsidiary of TransCanada, was awarded the right to build, own and operate the Sur de Texas-Tuxpan natural gas marine pipeline by the CFE. IEnova has a 40-percent interest in the project and accounts for its interest as an equity method investment, and TransCanada owns the remaining 60-percent interest. The marine pipeline is fully contracted under a 25-year natural gas transportation service contract with the CFE. We expect the project to be completed in the second half of 2018. During the years ended December 31, 2017 and 2016, Sempra Mexico invested cash of $72 million and $100 million respectively, in the IMG joint venture.

SEMPRA RENEWABLES

Sempra Renewables has 50-percent interests in wind and solar energy generation facilities in operation in the U.S. The generating capacities of the facilities are contracted under long-term PPAs. These facilities are accounted for under the equity method. During the years ended December 31, 2016 and 2015, Sempra Renewables invested cash of $18 million and $21 million, respectively, in its unconsolidated joint ventures.

SEMPRA LNG & MIDSTREAM

Rockies Express

As we discuss in Note 3, in May 2016, Sempra LNG & Midstream sold its 25-percent interest in Rockies Express, a partnership that operates a natural gas pipeline, REX, that links the Rocky Mountain region to the upper Midwest and the eastern U.S. In 2015, Sempra LNG & Midstream invested $113 million of cash in Rockies Express to repay project debt that matured in early 2015.

Cameron LNG JV

The Cameron LNG JV is a joint venture partnership that was formed in October 2014 among Sempra Energy and three project partners. The Cameron LNG existing regasification terminal that was contributed to the joint venture included two marine berths and three LNG storage tanks, and facilities capable of processing 1.5 Bcf of natural gas per day. The current liquefaction project, which is utilizing Cameron LNG JV’s existing facilities, is comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.9 Mtpa of LNG, with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. As of October 2014, Sempra LNG & Midstream began accounting for its investment in Cameron LNG JV under the equity method.

During the years ended December 31, 2017, 2016 and 2015, Sempra LNG & Midstream capitalized $47 million, $47 million and $49 million, respectively, of interest related to this equity method investment that has not commenced planned principal operations. During the years ended December 31, 2017 and 2015, Sempra LNG & Midstream invested $1 million and $10 million, respectively, of cash in Cameron LNG JV.

Cameron LNG JV Financing

General. In August 2014, Cameron LNG JV entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $7.4 billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI).

The Cameron LNG JV Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans will be used for financing the cost of development and construction of the three-train Cameron LNG project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG JV financing.

Interest. The weighted-average all-in cost of the loans outstanding under all the Loan Facility Agreements (and based on certain assumptions as to timing of drawdown) is 1.59 percent per annum over LIBOR prior to financial completion of the project and 1.78 percent per annum over LIBOR following financial completion of the project. The Loan Facility Agreements require Cameron LNG JV to hedge 50 percent of outstanding borrowings to fix the interest rate, beginning in 2016. The hedges are to remain in place until the debt principal has been amortized by 50 percent. In November 2014, Cameron LNG JV entered into floating-to-fixed interest rate swaps for approximately $3.7 billion notional amount, resulting in an effective fixed rate of 3.19 percent for the LIBOR component of the interest rate on the loans. In June 2015, Cameron LNG JV entered into additional floating-to-fixed interest rate swaps effective starting in 2020, for approximately $1.5 billion notional amount, resulting in an effective fixed rate of 3.32 percent for the LIBOR component of the interest rate on the loans.

Guarantees. In August 2014, Sempra Energy entered into agreements for the benefit of all of Cameron LNG JV’s creditors under the Loan Facility Agreements and related finance documents. Pursuant to these agreements, Sempra Energy has severally guaranteed 50.2 percent of Cameron LNG JV’s obligations under the Loan Facility Agreements and related finance documents, or a maximum amount of $3.9 billion. Guarantees for the remaining 49.8 percent of Cameron LNG JV’s senior secured financing have been provided by the other project partners. The Sempra Energy guarantee of 50.2 percent of Cameron LNG JV’s financing became effective upon effectiveness of the joint venture. Sempra Energy’s agreements and guarantees will terminate upon financial completion of the three-train Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. We expect the project to achieve financial completion and the guarantees to be terminated approximately nine months after all three trains achieve commercial operation. Sempra Energy recorded a liability of $82 million in October 2014, with an associated carrying value of $26 million at December 31, 2017, for the fair value of its obligations associated with the Loan Facility Agreements and related finance documents, which constitute guarantees. This liability is being reduced on a straight-line basis over the duration of the guarantees by recognizing equity earnings from Cameron LNG JV, included in Equity Earnings, Before Income Tax.

In August 2014, Sempra Energy and the other project partners entered into a transfer restrictions agreement with Société Générale, as intercreditor agent for the lenders under the Loan Facility Agreements. Pursuant to the transfer restriction agreement, Sempra Energy agreed to certain restrictions on its ability to dispose of Sempra Energy’s indirect fully diluted economic and beneficial ownership interests in Cameron LNG JV. These restrictions vary over time. Prior to financial completion of the three-train Cameron LNG project, Sempra Energy must retain 37.65 percent of such interest in Cameron LNG JV. Starting six months after financial completion of the three-train Cameron LNG project, Sempra Energy must retain at least 10 percent of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra Energy controlled (but not necessarily wholly owned) subsidiary must directly own 50.2 percent of the membership interests of the Cameron LNG JV.

Events of Default. Cameron LNG JV’s Loan Facility Agreements and related finance documents contain events of default customary for such financings, including events of default for: failure to pay principal and interest on the due date; insolvency of Cameron LNG JV; abandonment of the project; expropriation; unenforceability or termination of the finance documents; and a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to an additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under Cameron LNG JV’s financing and a potential demand on Sempra Energy’s guarantees.

Security. To support Cameron LNG JV’s obligations under the Loan Facility Agreements and related finance documents, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra Energy and the other project partners.

The security trustee under Cameron LNG JV’s financing can demand that a payment be made by Sempra Energy under its guarantees of Sempra Energy’s 50.2-percent share of senior debt obligations due and payable either on the date such amounts were due from Cameron LNG JV (taking into account cure periods) in the event of a failure by Cameron LNG JV to pay such senior debt obligations when they become due or within 10 business days in the event of an acceleration of senior debt obligations under the terms of the finance documents. If an event of default occurs under the Sempra Energy completion agreement, the security trustee can demand that Sempra Energy purchase its 50.2-percent share of all then outstanding senior debt obligations within five business days (other than in the case of a bankruptcy default, which is automatic).

RBS SEMPRA COMMODITIES

RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report miscellaneous costs since the sale of the business in Parent and Other.

In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. The investment balance of $67 million at December 31, 2017 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 in “Legal Proceedings – Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.

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

SUMMARIZED FINANCIAL INFORMATION

We present summarized financial information below, aggregated for all of our equity method investments for the periods in which we were invested in the entity. The amounts below represent the aggregate financial position and results of operations of 100 percent of each of Sempra Energy’s equity method investments.



SUMMARIZED FINANCIAL INFORMATION
(Dollars in millions)
	Years ended December 31,
	2017⁽¹⁾			2016⁽²⁾			2015
Gross revenues	$	846		$	1,079		$	1,533
Operating expense	(590		)	(726		)	(845		)
Income from operations	256			353			688
Interest expense	(217		)	(127		)	(312		)
Net income/Earnings⁽³⁾	116			252			440



	At December 31,
	2017⁽¹⁾		2016⁽²⁾
Current assets	$	974	$	704
Noncurrent assets	14,087		9,970
Current liabilities	797		629
Noncurrent liabilities	9,809		6,627


⁽¹⁾	On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50-percent interest in DEN, increasing its ownership percentage to 100 percent. At December 31, 2017, DEN is no longer an equity method investment.


⁽²⁾	On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in IEnova Pipelines, increasing its ownership percentage to 100 percent, and on May 9, 2016, Sempra LNG & Midstream sold its 25-percent interest in Rockies Express. At December 31, 2016, IEnova Pipelines and Rockies Express are no longer equity method investments.


⁽³⁾	Except for our investments in South America and Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

GUARANTEES

Project financing at our solar and wind joint ventures generally requires the joint venture partners, for each partner’s interest, to return cash to the projects in the event that the projects do not meet certain cash flow criteria or in the event that the projects’ debt service, O&M, and firm transmission and PTC reserve accounts are not maintained at specific thresholds. In some cases, the joint venture partners have provided guarantees to the lenders in lieu of the projects funding the reserve account requirements. We recorded liabilities for the fair value of certain of our obligations associated with these guarantees and the liabilities are being amortized over their expected lives. The outstanding loans at our solar and wind joint ventures are not guaranteed by the partners, but are secured by project assets.

IEnova has an indirect 40-percent ownership interest and TransCanada has an indirect 60-percent ownership interest in IMG. IEnova and TransCanada have each provided guarantees to third parties associated with construction of IMG’s Sur de Texas-Tuxpan natural gas marine pipeline. The aggregate amount of the obligations guaranteed by IEnova shall not exceed $288 million and will terminate upon completion of all guaranteed obligations. IEnova expects the construction giving rise to these guarantees to be completed by the end of 2018.

At December 31, 2017, we provided guarantees aggregating a maximum of $183 million with an associated aggregated carrying value of $6 million for guarantees related to project financing. In addition, at December 31, 2017, we provided guarantees to joint ventures aggregating a maximum of $370 million with an associated aggregated carrying value of $3 million, primarily related to PPAs and EPC contracts.

DEBT AND CREDIT FACILITIES

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt and Credit Facilities

DEBT AND CREDIT FACILITIES

LINES OF CREDIT

At December 31, 2017, Sempra Energy Consolidated had an aggregate of $4.3 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the principal terms of which we describe below. Available unused credit on these lines at December 31, 2017 was approximately $3.0 billion. Our foreign operations have additional general purpose credit facilities aggregating $1.8 billion at December 31, 2017. Available unused credit on these lines totaled $1.4 billion at December 31, 2017.



PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
		At December 31, 2017
		Total facility			Commercial paper outstanding⁽¹⁾			Available unused credit
Sempra Energy⁽²⁾		$	1,000		$	—		$	1,000
Sempra Global⁽³⁾		2,335			(931		)	1,404
California Utilities⁽⁴⁾:
	SDG&E	750			(253		)	497
	SoCalGas	750			(116		)	634
	Less: subject to a combined limit of $1 billion for both utilities	(500		)	—			(500		)
		1,000			(369		)	631
Total		$	4,335		$	(1,300	)	$	3,035


⁽¹⁾	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.


⁽²⁾	The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017.


⁽³⁾	Sempra Energy guarantees Sempra Global’s obligations under the credit facility.


⁽⁴⁾	The facility also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017.

Related to the committed lines of credit in the table above:


▪	Each is a 5-year syndicated revolving credit agreement expiring in October 2020.


▪	Citibank N.A. serves as administrative agent for the Sempra Energy and Sempra Global facilities and JPMorgan Chase Bank, N.A. serves as administrative agent for the California Utilities combined facility.


▪	Each facility has a syndicate of 21 lenders. No single lender has greater than a 7-percent share in any facility.


▪	Sempra Energy, SDG&E and SoCalGas must maintain a ratio of indebtedness to total capitalization (as defined in each agreement) of no more than 65 percent at the end of each quarter. Each entity is in compliance with this and all other financial covenants under its respective credit facility at December 31, 2017.


▪	Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings in the case of the Sempra Energy and Sempra Global lines of credit, and with the borrowing utility’s credit rating in the case of the California Utilities line of credit.


▪	The California Utilities’ obligations under their agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility.

On January 17, 2018, pursuant to the terms of the Sempra Energy and Sempra Global credit facilities, the amounts available under the lines of credit were increased by $250 million, from $1.0 billion to $1.25 billion, for Sempra Energy and by $850 million, from $2.335 billion to $3.185 billion, for Sempra Global. This additional borrowing capacity is available to us for working capital, capital expenditures and other general corporate purposes, and is intended to provide us with additional liquidity and to support commercial paper that we may utilize from time to time to fund our strategic and growth initiatives.



CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar equivalent in millions)
			At December 31, 2017
		Denominated in	Total facility		Amount outstanding				Available unused credit
Sempra South American Utilities⁽¹⁾:
	Peru⁽²⁾	Peruvian sol	$	465	$	(169	)	⁽³⁾	$	296
	Chile	Chilean peso	115		—				115
Sempra Mexico:
	IEnova⁽⁴⁾	U.S. dollar	1,170		(137		)		1,033
Total			$	1,750	$	(306	)		$	1,444

⁽¹⁾ The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021.

⁽²⁾ The Peruvian facilities require a debt to equity ratio of no more than 170 percent, with which we were in compliance at December 31, 2017.

⁽³⁾ Includes bank guarantees of $18 million.

⁽⁴⁾ Five-year revolver expiring in August 2020 with a syndicate of eight lenders.

Outside of these domestic and foreign committed credit facilities, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2017, we had approximately $629 million in standby letters of credit outstanding under these agreements.

WEIGHTED-AVERAGE INTEREST RATES

The weighted-average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.92 percent and 1.51 percent at December 31, 2017 and 2016, respectively. The weighted-average interest rate on total short-term debt at SDG&E was 1.65 percent at December 31, 2017. The weighted-average interest rates on total short-term debt at SoCalGas were 1.64 percent and 0.75 percent at December 31, 2017 and 2016, respectively.

BRIDGE FACILITY RELATED TO THE PENDING ACQUISITION OF ENERGY FUTURE HOLDINGS CORP.

At December 31, 2017, Sempra Energy had a commitment letter from a syndicate of banks, subject to customary conditions, for a $4.0 billion, 364-day senior unsecured bridge facility to backstop a portion of our obligations to pay the Merger Consideration for the acquisition of EFH, which we discuss in Note 3. The $4.0 billion commitment is reduced by the amount of funds received through Sempra Energy’s sales of equity securities and debt securities, subject in each case to certain exceptions, and increases in our borrowing capacity under our existing revolving credit facilities. At December 31, 2017, we had no amounts outstanding under this bridge facility. Following the completion of the common stock offering and the mandatory convertible preferred stock offering, which closed on January 9, 2018, the facility was terminated. We discuss the offerings in Note 18.

LONG-TERM DEBT

The following tables show the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016
SDG&E
First mortgage bonds (collateralized by plant assets):
Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017	$	—		$	140
1.65% July 1, 2018⁽¹⁾	161			161
3% August 15, 2021	350			350
1.914% payable 2015 through February 2022	161			197
3.6% September 1, 2023	450			450
2.5% May 15, 2026	500			500
6% June 1, 2026	250			250
5.875% January and February 2034⁽¹⁾	176			176
5.35% May 15, 2035	250			250
6.125% September 15, 2037	250			250
4% May 1, 2039⁽¹⁾	75			75
6% June 1, 2039	300			300
5.35% May 15, 2040	250			250
4.5% August 15, 2040	500			500
3.95% November 15, 2041	250			250
4.3% April 1, 2042	250			250
3.75% June 1, 2047	400			—
	4,573			4,349
Other long-term debt:
OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007),
payable 2013 through April 2019 (collateralized by OMEC plant assets)	295			305
Capital lease obligations:
Purchased-power contracts	731			239
Other	1			1
	1,027			545
	5,600			4,894
Current portion of long-term debt	(220		)	(191		)
Unamortized discount on long-term debt	(11		)	(11		)
Unamortized debt issuance costs	(34		)	(34		)
Total SDG&E	5,335			4,658

SoCalGas
First mortgage bonds (collateralized by plant assets):
5.45% April 15, 2018	250			250
1.55% June 15, 2018	250			250
3.15% September 15, 2024	500			500
3.2% June 15, 2025	350			350
2.6% June 15, 2026	500			500
5.75% November 15, 2035	250			250
5.125% November 15, 2040	300			300
3.75% September 15, 2042	350			350
4.45% March 15, 2044	250			250
	3,000			3,000
Other long-term debt (uncollateralized):
1.875% Notes payable 2016 through May 2026⁽¹⁾	4			4
5.67% Notes January 18, 2028	5			5
Capital lease obligations	1			—
	10			9
	3,010			3,009
Current portion of long-term debt	(501		)	—
Unamortized discount on long-term debt	(7		)	(7		)
Unamortized debt issuance costs	(17		)	(20		)
Total SoCalGas	2,485			2,982



LONG-TERM DEBT (CONTINUED)
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy
Other long-term debt (uncollateralized):
2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease⁽²⁾	138			137
Sempra South American Utilities
Other long-term debt (uncollateralized):
Chilquinta Energía – 4.25% Series B Bonds October 30, 2030	205			185
Luz del Sur
Bank loans 5.18% to 6.7% payable 2016 through December 2018	53			75
Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029	415			346
Other bonds at 3.77% to 4.61% payable 2020 through May 2022	6			7
Capital lease obligations	6			6
Sempra Mexico
Other long-term debt (uncollateralized unless otherwise noted):
Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency
swaps effective 2013)	66			63
6.3% Notes February 2, 2023 (4.12% after cross-currency swap)	198			189
Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014),
payable 2016 through December 2026, collateralized by plant assets	314			352
3.75% Notes January 14, 2028	300			—
Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates
(weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable
rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets	468			481
4.875% Notes January 14, 2048	540			—
Sempra Renewables
Other long-term debt (collateralized by project assets):
Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028
except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012⁽¹⁾	77			84
Sempra LNG & Midstream
Other long-term debt (uncollateralized unless otherwise noted):
Notes at 2.87% to 3.51% October 1, 2026⁽¹⁾	20			20
8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee	—			6
	9,405			7,548
Current portion of long-term debt	(706		)	(722		)
Unamortized discount on long-term debt	(13		)	(10		)
Unamortized premium on long-term debt	4			4
Unamortized debt issuance costs	(65		)	(31		)
Total other Sempra Energy	8,625			6,789
Total Sempra Energy Consolidated	$	16,445		$	14,429


⁽¹⁾	Callable long-term debt not subject to make-whole provisions.


⁽²⁾	We discuss this lease in Note 15.



MATURITIES OF LONG-TERM DEBT⁽¹⁾
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra Energy		Total Sempra Energy Consolidated
2018	$	207	$	500	$	705	$	1,412
2019	321		—		1,098		1,419
2020	36		—		997		1,033
2021	385		—		961		1,346
2022	18		—		629		647
Thereafter	3,901		2,509		4,872		11,282
Total	$	4,868	$	3,009	$	9,262	$	17,139


⁽¹⁾	Excludes capital lease obligations, build-to-suit lease, market value adjustments for interest rate swaps, discounts, premiums and debt issuance costs.

Various long-term obligations totaling $8.4 billion at Sempra Energy Consolidated at December 31, 2017 are unsecured. This includes unsecured long-term obligations totaling $9 million at SoCalGas. There were no unsecured long-term obligations at SDG&E.

CALLABLE LONG-TERM DEBT

At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2017 is callable subject to premiums:



CALLABLE LONG-TERM DEBT
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra Energy		Total Sempra Energy Consolidated
Not subject to make-whole provisions	$	412	$	4	$	97	$	513
Subject to make-whole provisions	4,161		3,005		7,058		14,224

In addition, the OMEC LLC project financing loan discussed in Note 1, with $295 million of outstanding borrowings at December 31, 2017, may be prepaid at OMEC LLC’s option.

FIRST MORTGAGE BONDS

The California Utilities issue first mortgage bonds secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $4.7 billion at SDG&E and $1.1 billion at SoCalGas at December 31, 2017.

In June 2017, SDG&E publicly offered and sold $400 million of 3.75-percent, first mortgage bonds maturing in June 2047. SDG&E used the proceeds from the offering to repay outstanding commercial paper.

OTHER LONG-TERM DEBT

Sempra Energy

In January 2018, Sempra Energy publicly offered and sold an aggregate principal amount of $5.0 billion of fixed and floating rate notes, which we discuss in Note 18.

In October 2017, Sempra Energy publicly offered and sold $850 million of floating rate notes, maturing in March 2021. The floating rate notes bear interest at a rate equal to the three-month LIBOR plus 45 bps. The interest rate is reset quarterly. Sempra Energy used a substantial portion of the net proceeds from the offering to repay outstanding commercial paper, with remaining proceeds used for general corporate purposes.

In June 2017, Sempra Energy publicly offered and sold $750 million of 3.25-percent, fixed rate notes maturing in June 2027. Sempra Energy used the proceeds from the offering to repay outstanding commercial paper.

SDG&E

In 2015, SDG&E entered into a CPUC-approved 25-year PPA with a peaker plant facility. Construction of the peaker plant facility was completed and delivery of contracted power commenced in June 2017, at which time we recorded a $500 million capital lease obligation on SDG&E’s and Sempra Energy’s Consolidated Balance Sheets.

Sempra South American Utilities

Luz del Sur has outstanding corporate bonds and bank loans that are denominated in the local currency. In February 2017, Luz del Sur publicly offered and sold $50 million of corporate bonds at 6.375 percent, maturing in February 2023. In December 2017, Luz del Sur publicly offered and sold $50 million of corporate bonds at 5.9375 percent, maturing in December 2027.

Sempra Mexico

In December 2017, Sempra Mexico offered and sold in a private placement $300 million of 3.75-percent, fixed rate notes maturing in January 2028 and $540 million of 4.875-percent, fixed rate notes maturing in January 2048. Sempra Mexico used a substantial portion of the net proceeds from the offering to repay outstanding short-term debt, with remaining proceeds used for general corporate purposes.

INTEREST RATE SWAPS

We discuss our fair value and cash flow hedging interest rate swaps in Note 9.

INCOME TAXES

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Reconciliation of net U.S. statutory federal income tax rates to the ETRs is as follows:



RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES

	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Effects of the TCJA	55		—		—
Utility depreciation	6		4		5
Foreign exchange and inflation effects⁽¹⁾	3		(2	)	(2	)
State income taxes, net of federal income tax benefit	1		1		1
Utility repairs expenditures	(6	)	(4	)	(5	)
Tax credits	(4	)	(3	)	(4	)
Self-developed software expenditures	(4	)	(3	)	(3	)
Non-U.S. earnings taxed at lower statutory income tax rates⁽²⁾	(3	)	(3	)	(2	)
Allowance for equity funds used during construction	(3	)	(2	)	(2	)
Resolution of prior years’ income tax items	(2	)	—		(3	)
Share-based compensation	—		(2	)	—
Other, net	3		—		—
Effective income tax rate	81	%	21	%	20	%
SDG&E:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	7		5		4
Effects of the TCJA	5		—		—
State income taxes, net of federal income tax benefit	3		5		5



Repairs expenditures	(8	)	(4	)	(4	)
Self-developed software expenditures	(6	)	(3	)	(3	)
Allowance for equity funds used during construction	(4	)	(2	)	(2	)
Resolution of prior years’ income tax items	(4	)	(1	)	(2	)
Share-based compensation	—		(1	)	—
Other, net	(1	)	(1	)	(1	)
Effective income tax rate	27	%	33	%	32	%
SoCalGas:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	9		9		8
State income taxes, net of federal income tax benefit	3		2		4
Repairs expenditures	(8	)	(9	)	(10	)
Self-developed software expenditures	(5	)	(6	)	(6	)
Allowance for equity funds used during construction	(3	)	(2	)	(2	)
Resolution of prior years’ income tax items	(2	)	2		(3	)
Share-based compensation	—		(1	)	—
Other, net	—		(1	)	(1	)
Effective income tax rate	29	%	29	%	25	%

⁽¹⁾

Primarily due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of significant appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.


⁽²⁾	Related to operations in Mexico, Chile and Peru.

On December 22, 2017, the TCJA was signed into law. This legislation significantly changes the IRC. Under U.S. GAAP, certain effects of the TCJA are required to be recognized upon enactment, and, as a result, Sempra Energy, SDG&E, and SoCalGas recorded the related effects in 2017.

The TCJA reduces the U.S. statutory corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018, which will be applied to future U.S. earnings. U.S. GAAP requires that deferred income tax assets and liabilities, including NOLs, be remeasured at the income tax rate expected to apply when those temporary differences reverse and that the effects of any change to such income tax rate be recognized in the period when the change was enacted. This remeasurement resulted in significant reductions in deferred income tax balances at Sempra Energy Consolidated, SDG&E and SoCalGas.

The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes that previously have been collected from ratepayers at the higher rate. These excess deferred income taxes have been recorded as regulatory liabilities as of December 31, 2017 and will be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and FERC.

Our 2017 financial statements were materially impacted by the effects of the TCJA, primarily related to two provisions:

▪

Lower U.S. statutory corporate income tax rate: The change in the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent resulted in income tax expense of $182 million for the year ended December 31, 2017 for Sempra Energy Consolidated because of the remeasurement of deferred income tax balances. SDG&E’s and SoCalGas’ impacts were primarily offset with adjustments to regulatory liabilities, however, they also recorded $28 million and $2 million of income tax expense, respectively, for the year ended December 31, 2017 associated with the TCJA.

▪

Deemed repatriation: The TCJA imposes a one-time tax for deemed repatriation of foreign undistributed earnings as determined under U.S. federal tax law. Under this provision, a U.S. shareholder must include in taxable income its pro-rata share of foreign undistributed earnings, which are taxed at 15.5 percent on cash or cash equivalents and 8 percent on cumulative other earnings. Sempra Energy Consolidated recorded deemed repatriation tax expense of $328 million. Based on our preliminary analysis, we currently anticipate using our existing NOLs to offset the deemed repatriation tax liability. In addition, we plan to repatriate these foreign undistributed earnings (estimated to be approximately $4 billion) that have now been taxed at the U.S. federal level. As a result, for the year ended December 31, 2017, we accrued $360 million of U.S. state and non-U.S. withholding tax expense on this expected future repatriation. This liability could change as a result of various factors, such as interpretation and clarification of the TCJA provisions, changes in foreign tax laws, foreign currency movements, the source of cash to be repatriated or adjustments to our provisional estimates, as we discuss below.

We have not recorded deferred income tax with respect to remaining basis differences of approximately $1 billion between financial statement and income tax investment amounts in our non-U.S subsidiaries as of December 31, 2017 because we consider them to be indefinitely reinvested. It is not practicable to determine the hypothetical amount of tax that might be payable if the underlying basis differences were realized. If these basis differences were realized, we would need to adjust our income tax provision in the period we determine that they are no longer indefinitely reinvested.



EFFECTS OF THE TAX CUTS AND JOBS ACT OF 2017
(Dollars in millions)
	Sempra Energy Consolidated			SDG&E			SoCalGas
Consolidated Balance Sheets:
Decrease in net deferred income tax liabilities due
to remeasurement	$	(2,220	)	$	(1,400	)	$	(972	)
Increase in net regulatory liabilities from remeasurement of
deferred income tax assets and liabilities	$	2,402		$	1,428		$	974

Consolidated Statements of Operations:
Income tax expense related to remeasurement of deferred
income tax assets and liabilities	$	182		$	28		$	2
Income tax expense related to deemed repatriation	328			—			—
U.S. state and non-U.S. withholding tax expense related to
expected future repatriation of foreign earnings	360			—			—
Total increase in income tax expense	$	870		$	28		$	2

We recorded the effects of the TCJA in 2017 using our best estimates and the information available to us through the date the financial statements were issued. However, our analysis is ongoing and as such, the income tax effects that we have recorded are provisional.

As permitted by and in accordance with the guidance issued by the SEC, we may adjust our provisional estimates in future reporting periods throughout 2018 as we complete our analysis and as more information becomes available, and these adjustments may affect earnings. Events and information that may result in adjustments to our provisional estimates include interpretations or rulings by the U.S. Department of the Treasury or states, the filing of our 2017 income tax return and the finalization of our calculation of foreign undistributed earnings.

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


▪	repairs expenditures related to a certain portion of utility plant fixed assets


▪	the equity portion of AFUDC


▪	a portion of the cost of removal of utility plant assets


▪	utility self-developed software expenditures


▪	depreciation on a certain portion of utility plant assets


▪	state income taxes

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

The 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings. We expect that certain amounts recorded in the tracking accounts may give rise to regulatory assets or liabilities. We discuss the tracking accounts further in Note 14.

The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy Consolidated are as follows:



GEOGRAPHIC COMPONENTS
(Dollars in millions)
	Pretax book income
	Years ended December 31,
	2017		2016		2015
U.S.	$	878	$	773	$	1,189
Non-U.S.	707		1,057		515
Total	$	1,585	$	1,830	$	1,704

U.S. pretax book income decreased in 2016 compared to 2015 at the California Utilities primarily due to the reallocation of 2012-2015 income tax benefits generated from income tax repairs deductions to ratepayers pursuant to the 2016 GRC FD, as we discuss in Note 14; at Sempra LNG & Midstream for the loss on permanent release of pipeline capacity, as we discuss in Note 15; and the impairment charge related to the investment in Rockies Express, as we discuss in Note 3. U.S. pretax income remained lower in 2017 due to the write-off of SDG&E’s wildfire regulatory asset, as we discuss in Note 15. Non-U.S. pretax book income was lower in 2017 and 2015 compared to 2016 primarily due to the noncash gain in 2016 associated with the remeasurement of our equity interest in IEnova Pipelines, as we discuss in Note 3.

The components of income tax expense are as follows:



INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Current:
U.S. federal	$	—		$	—		$	3
U.S. state	—			1			(24		)
Non-U.S.	116			171			123
Total	116			172			102
Deferred:
U.S. federal	536			78			242
U.S. state	297			9			34
Non-U.S.	327			135			(32		)
Total	1,160			222			244
Deferred investment tax credits	—			(5		)	(5		)
Total income tax expense	$	1,276		$	389		$	341
SDG&E:
Current:
U.S. federal	$	100		$	—		$	12
U.S. state	65			22			77
Total	165			22			89
Deferred:
U.S. federal	29			223			233
U.S. state	(41		)	38			(35		)
Total	(12		)	261			198
Deferred investment tax credits	2			(3		)	(3		)
Total income tax expense	$	155		$	280		$	284
SoCalGas:
Current:
U.S. federal	$	—		$	—		$	(1	)
U.S. state	23			40			12
Total	23			40			11
Deferred:
U.S. federal	144			123			122
U.S. state	(5		)	(18		)	7
Total	139			105			129
Deferred investment tax credits	(2		)	(2		)	(2		)
Total income tax expense	$	160		$	143		$	138

We show the components of deferred income taxes, which reflect the effects of the TCJA, at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below:



DEFERRED INCOME TAXES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	December 31,
	2017		2016
Deferred income tax liabilities:
Differences in financial and tax bases of fixed assets, investments and other assets⁽¹⁾	$	4,233	$	6,111
U.S. state and non-U.S. withholding tax on repatriation of foreign earnings	360		—
Regulatory balancing accounts	376		783
Property taxes	37		63
Other deferred income tax liabilities	117		143
Total deferred income tax liabilities	5,123		7,100
Deferred income tax assets:
Tax credits	1,066		431
Net operating losses	968		2,304
Compensation-related items	199		252
Postretirement benefits	251		434
Other deferred income tax assets	115		87
Accrued expenses not yet deductible	60		112
Deferred income tax assets before valuation allowances	2,659		3,620
Less: valuation allowances	133		31
Total deferred income tax assets	2,526		3,589
Net deferred income tax liability⁽²⁾	$	2,597	$	3,511


⁽¹⁾	In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.


⁽²⁾	At December 31, 2017 and 2016, includes $170 million and $234 million, respectively, recorded as a noncurrent asset and $2,767 million and $3,745 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.



DEFERRED INCOME TAXES – SDG&E AND SOCALGAS
(Dollars in millions)
	SDG&E				SoCalGas
	December 31,				December 31,
	2017		2016		2017		2016
Deferred income tax liabilities:
Differences in financial and tax bases of
utility plant and other assets	$	1,472	$	2,549	$	987	$	1,699
Regulatory balancing accounts	113		379		271		411
Property taxes	26		42		12		21
Other	10		10		1		4
Total deferred income tax liabilities	1,621		2,980		1,271		2,135
Deferred income tax assets:
Net operating losses	—		—		58		83
Tax credits	7		27		15		17
Postretirement benefits	43		98		152		244
Compensation-related items	5		8		25		32
State income taxes	14		—		7		19
Accrued expenses not yet deductible	3		7		12		20
Other	19		11		7		11
Total deferred income tax assets	91		151		276		426
Net deferred income tax liability	$	1,530	$	2,829	$	995	$	1,709

The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017.



NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS
(Dollars in millions)
	Unused amount at December 31, 2017		Year expiration begins
Sempra Energy Consolidated:
U.S. federal:
NOLs⁽¹⁾	$	3,145	2031
General business tax credits⁽¹⁾	389		2032
Foreign tax credits⁽²⁾	631		2024
U.S. state⁽²⁾:
NOLs	2,295		2019
General business tax credits	51		2018
Non-U.S.⁽²⁾
NOLs	607		2018
SoCalGas:
U.S. federal⁽¹⁾:
NOLs	$	334	2032
General business tax credits	12		2031


⁽¹⁾	We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.


⁽²⁾	We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.

At December 31, 2017, Sempra Energy recorded a valuation allowance against a portion of its total deferred income tax assets, as shown above in the “Deferred Income Taxes – Sempra Energy Consolidated” table. A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. Of the valuation allowances recorded to date, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses in various U.S. state and non-U.S. jurisdictions resulting in a deferred income tax asset related to NOLs, as shown in the “Net Operating Losses and Tax Credit Carryforwards” table above, that we currently do not believe will be realized on a more-likely-than-not basis. Of Sempra Energy’s total valuation allowance of $133 million at December 31, 2017, $20 million is related to non-U.S. NOLs and tax credits, $30 million to U.S. state NOLs and tax credits, and $83 million to U.S. foreign tax credits. Of Sempra Energy’s total valuation allowance of $31 million at December 31, 2016, $1 million was related to non-U.S. NOLs and $30 million to U.S. state NOLs and tax credits.

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:



RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2017			2016			2015
Sempra Energy Consolidated:
Balance at January 1	$	90		$	87		$	117
Increase in prior period tax positions	22			2			10
Decrease in prior period tax positions	(15		)	(2		)	—
Increase in current period tax positions	4			6			8
Settlements with taxing authorities	(12		)	(3		)	(48		)
Balance at December 31	$	89		$	90		$	87
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(77	)	$	(87	)	$	(83	)
increase the effective tax rate⁽¹⁾	20			36			32
SDG&E:
Balance at January 1	$	22		$	20		$	14
Increase in prior period tax positions	9			—			5
Decrease in prior period tax positions	(11		)	—			—
Increase in current period tax positions	—			2			2
Settlements with taxing authorities	(10		)	—			(1		)
Balance at December 31	$	10		$	22		$	20
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(7	)	$	(19	)	$	(16	)
increase the effective tax rate⁽¹⁾	1			13			11
SoCalGas:
Balance at January 1	$	29		$	27		$	19
Increase in prior period tax positions	3			—			2
Decrease in prior period tax positions	—			(2		)	—
Increase in current period tax positions	4			4			6
Settlements with taxing authorities	(1		)	—			—
Balance at December 31	$	35		$	29		$	27
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(26	)	$	(29	)	$	(27	)
increase the effective tax rate⁽¹⁾	20			24			21


⁽¹⁾	Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:



POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
	At December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Expiration of statutes of limitations on tax assessments	$	—		$	(2	)	$	(2	)
Potential resolution of audit issues with various
U.S. federal, state and local and non-U.S. taxing authorities	(8		)	(36		)	(32		)
	$	(8	)	$	(38	)	$	(34	)
SDG&E:
Expiration of statutes of limitations on tax assessments	$	—		$	(1	)	$	(1	)
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities	(6		)	(10		)	(8		)
	$	(6	)	$	(11	)	$	(9	)
SoCalGas:
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities	$	(2	)	$	(25	)	$	(22	)

Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Consolidated Statements of Operations. Sempra Energy Consolidated accrued a negligible amount and $1 million for interest expense and penalties at December 31, 2017 and 2016, respectively, on the Consolidated Balance Sheets, and recorded negligible amounts of interest income and penalties in each of 2017 and 2016 and $2 million in 2015 on the Consolidated Statements of Operations. SDG&E and SoCalGas accrued negligible amounts of interest expense and penalties at December 31, 2017 and 2016 on the Consolidated Balance Sheets, and recorded negligible amounts of interest expense and penalties in 2017, 2016 and 2015 on the Consolidated Statements of Operations.

INCOME TAX AUDITS

Sempra Energy is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2013. We are subject to examination by major state tax jurisdictions for tax years after 2008. Certain major non-U.S. income tax returns for tax years 2008 through the present are open to examination. We are also open to examination for non-U.S. income tax returns related to our prior interest in our commodities business, which we divested in 2010, for years 1996 through 2010.

In addition, we have filed state refund claims for tax years back to 2006. The pre-2009 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.

SDG&E and SoCalGas are subject to U.S. federal income tax as well as income tax of state jurisdictions. They remain subject to examination for U.S. federal tax years after 2013 and by state tax jurisdictions for tax years after 2008.

EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

We are required by applicable U.S. GAAP to:


▪	recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position;


▪	measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and


▪	recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of Sempra Energy and its consolidated subsidiaries.

Sempra Energy has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

IEnova has an unfunded noncontributory defined benefit plan covering all employees. Chilquinta Energía has an unfunded noncontributory defined benefit plan covering all employees hired before October 1, 1981 and an unfunded noncontributory termination indemnity plan covering represented employees. The plans generally provide defined benefits to retirees based on date of hire, years of service and final average earnings.

Sempra Energy also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses.

Chilquinta Energía also has two noncontributory postretirement benefit plans which cover represented employees – a health care plan and an energy subsidy plan that provides for reduced energy rates. The health care plan includes benefits for retirees’ spouses and dependents.

Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $455 million and $430 million at December 31, 2017 and 2016, respectively.

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Special Termination Benefits Affecting 2017 and 2016

In 2017, certain represented and in 2016, certain nonrepresented employees age 62 or older with 5 years of service or age 55 to 61 with 10 years of service that retired under the Voluntary Retirement Enhancement Program offered in either of those years received an additional postretirement health benefit in the form of a $100,000 Health Reimbursement Account. We treated the benefit obligation attributable to the Health Reimbursement Account as a special termination benefit. This resulted in increases to the recorded liability for PBOP and net periodic benefit cost of $18 million for each of Sempra Energy Consolidated and SoCalGas in 2017, and $26 million for Sempra Energy Consolidated, $14 million for SDG&E and $11 million for SoCalGas in 2016.

The Voluntary Retirement Enhancement Program resulted in a higher than expected number of retirements in 2017 and 2016. As a result, the total lump sum benefits paid from the Sempra Energy nonqualified and SoCalGas qualified pension plans in 2017, and the SDG&E qualified pension plan in 2016, exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $194 million at Sempra Energy Consolidated and $175 million at SoCalGas in 2017, and $75 million at each of Sempra Energy Consolidated and SDG&E in 2016. This also resulted in settlement charges in net periodic benefit cost of $38 million at Sempra Energy Consolidated and $30 million at SoCalGas in 2017, and $16 million at each of Sempra Energy Consolidated and SDG&E in 2016. The settlement charges at SoCalGas in 2017, and at SDG&E in 2016, were recorded as regulatory assets on the Consolidated Balance Sheets. Measurement dates of December 31, 2017 and 2016 were used for the respective settlement accounting triggered in each year, as the year-to-date lump sum benefit payments first exceeded the settlement threshold in December of both of those years.

Divestiture Affecting 2016

On September 12, 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas, as we discuss in Note 3. The benefit obligations and plan assets of the benefit plans that covered employees of Mobile Gas and Willmut Gas were transferred to the buyer on the date of sale. This resulted in decreases to the recorded pension liability and other postretirement benefit plan liability of $61 million and $6 million, respectively, and decreases to pension plan assets and other postretirement benefit plan assets of $44 million and $4 million, respectively, for Sempra Energy Consolidated.

Benefit Obligations and Assets

The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2017 and 2016, and a statement of the funded status at December 31, 2017 and 2016:



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	3,679		$	3,649		$	922		$	963
Service cost	117			107			21			20
Interest cost	151			160			39			42
Contributions from plan participants	—			—			20			20
Actuarial loss (gain)	286			116			6			(81		)
Benefit payments	(182		)	(217		)	(63		)	(61		)
Divestiture of EnergySouth	—			(61		)	—			(6		)
Plan amendments	1			—			—			—
Special termination benefits	—			—			18			26
Curtailments	(1		)	—			—			—
Settlements	(194		)	(75		)	—			(1		)
Net obligation at December 31	3,857			3,679			963			922

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	2,459			2,484			1,057			1,003
Actual return on plan assets	421			207			185			94
Employer contributions	155			104			10			6
Contributions from plan participants	—			—			20			20
Benefit payments	(182		)	(217		)	(63		)	(61		)
Divestiture of EnergySouth	—			(44		)	—			(4		)
Settlements	(194		)	(75		)	—			(1		)
Fair value of plan assets at December 31	2,659			2,459			1,209			1,057
Funded status at December 31	$	(1,198	)	$	(1,220	)	$	246		$	135
Net recorded (liability) asset at December 31	$	(1,198	)	$	(1,220	)	$	246		$	135



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	935		$	965		$	190		$	165
Service cost	29			29			5			5
Interest cost	38			41			8			7
Contributions from plan participants	—			—			7			7
Actuarial loss (gain)	50			7			(9		)	6
Benefit payments	(83		)	(25		)	(16		)	(14		)
Special termination benefits	—			—			—			14



Settlements	—			(75		)	—			—
Transfer of liability from (to) other plans	2			(7		)	—			—
Net obligation at December 31	971			935			185			190

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	714			752			169			161
Actual return on plan assets	120			59			30			13
Employer contributions	22			3			5			2
Contributions from plan participants	—			—			7			7
Benefit payments	(83		)	(25		)	(16		)	(14		)
Settlements	—			(75		)	—			—
Transfer of assets from other plans	3			—			—			—
Fair value of plan assets at December 31	776			714			195			169
Funded status at December 31	$	(195	)	$	(221	)	$	10		$	(21	)
Net recorded (liability) asset at December 31	$	(195	)	$	(221	)	$	10		$	(21	)



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	2,343		$	2,255		$	691		$	752
Service cost	76			67			14			14
Interest cost	98			101			29			32
Contributions from plan participants	—			—			13			13
Actuarial loss (gain)	216			77			16			(86		)
Benefit payments	(73		)	(158		)	(44		)	(45		)
Special termination benefits	—			—			18			11
Settlements	(175		)	—			—			—
Transfer of liability from other plans	1			1			—			—
Net obligation at December 31	2,486			2,343			737			691

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	1,579			1,537			870			822
Actual return on plan assets	269			128			151			79
Employer contributions	93			72			3			1
Contributions from plan participants	—			—			13			13
Benefit payments	(73		)	(158		)	(44		)	(45		)
Settlements	(175		)	—			—			—
Transfer of assets from other plans	1			—			—			—
Fair value of plan assets at December 31	1,694			1,579			993			870
Funded status at December 31	$	(792	)	$	(764	)	$	256		$	179
Net recorded (liability) asset at December 31	$	(792	)	$	(764	)	$	256		$	179

Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and Other Postretirement Benefit Plans” and updates to census data. In 2017, 2016 and 2015, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. We have incorporated these assumptions, adjusted for the Sempra Energy companies’ actual mortality experience, in our calculations for each of those years. Actuarial losses in pension plans at Sempra Energy Consolidated in 2017 were driven primarily by actuarial losses at SDG&E and SoCalGas due to a decrease in discount rates and, additionally at SoCalGas, actuarial losses due to updated census data. Actuarial losses in PBOP plans at Sempra Energy Consolidated in 2017 were driven primarily by actuarial losses at SDG&E and SoCalGas due to a decrease in discount rates, offset by actuarial gains at SDG&E and partially offset by actuarial gains at SoCalGas due to a reduction in the 2018 expected health care costs.

Net Assets and Liabilities

The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.

The 10-percent corridor accounting method is used at Sempra Energy Consolidated, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10-percent corridor accounting methods help mitigate volatility of net periodic costs from year to year.

We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in Accumulated Other Comprehensive Income (Loss) on the balance sheet. The California Utilities record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on agreements with regulatory agencies.

The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their plans as authorized by the CPUC. The annual contributions to the pension plans are limited to a minimum required funding amount as determined by the IRS. The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Until the date of sale, Mobile Gas recorded annual pension and other postretirement net periodic benefit costs based on an estimate of the net periodic cost at the beginning of the year calculated in accordance with U.S. GAAP for pension and PBOP plans, as authorized by the Alabama Public Service Commission. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.

The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31:



PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
Sempra Energy Consolidated:
Noncurrent assets	$	—		$	—		$	266		$	179
Current liabilities	(69		)	(56		)	(1		)	—
Noncurrent liabilities	(1,129		)	(1,164		)	(19		)	(44		)
Net recorded (liability) asset	$	(1,198	)	$	(1,220	)	$	246		$	135
SDG&E:
Noncurrent assets	$	—		$	—		$	10		$	—
Current liabilities	(13		)	(10		)	—			—
Noncurrent liabilities	(182		)	(211		)	—			(21		)
Net recorded (liability) asset	$	(195	)	$	(221	)	$	10		$	(21	)
SoCalGas:
Noncurrent assets	$	—		$	—		$	256		$	179
Current liabilities	(3		)	(2		)	—			—
Noncurrent liabilities	(789		)	(762		)	—			—
Net recorded (liability) asset	$	(792	)	$	(764	)	$	256		$	179

Amounts recorded in AOCI at December 31, 2017 and 2016, net of income tax effects and amounts recorded as regulatory assets, are as follows:



AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017		2016
Sempra Energy Consolidated:
Net actuarial (loss) gain	$	(84	)	$	(95	)	$	4	$	3
Prior service cost	(4		)	(4		)	—		—
Total	$	(88	)	$	(99	)	$	4	$	3
SDG&E:
Net actuarial loss	$	(8	)	$	(8	)
SoCalGas:
Net actuarial loss	$	(6	)	$	(6	)
Prior service cost	(2		)	(3		)
Total	$	(8	)	$	(9	)

The accumulated benefit obligation for defined benefit pension plans at December 31, 2017 and 2016 was as follows:



ACCUMULATED BENEFIT OBLIGATION
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	2017		2016		2017		2016		2017		2016
Accumulated benefit obligation	$	3,551	$	3,465	$	930	$	904	$	2,241	$	2,167

Sempra Energy, SDG&E and SoCalGas each have a funded pension plan. We also have unfunded pension plans at Sempra Energy, SDG&E, SoCalGas, IEnova and Chilquinta Energía. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:



OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	2017		2016
Sempra Energy Consolidated:
Projected benefit obligation	$	3,623	$	3,431
Accumulated benefit obligation	3,334		3,227
Fair value of plan assets	2,659		2,459
SDG&E:
Projected benefit obligation	$	939	$	902
Accumulated benefit obligation	900		874
Fair value of plan assets	776		714
SoCalGas:
Projected benefit obligation	$	2,462	$	2,320
Accumulated benefit obligation	2,220		2,148
Fair value of plan assets	1,694		1,579

Net Periodic Benefit Cost

The following three tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI

SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Pension benefits

Other postretirement benefits



	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	117		$	107		$	114		$	21		$	20		$	26
Interest cost	151			160			154			39			42			44
Expected return on assets	(161		)	(166		)	(173		)	(66		)	(69		)	(68		)
Amortization of:
Prior service cost (credit)	11			11			11			1			—			(4		)
Actuarial loss (gain)	36			30			38			(4		)	(1		)	—
Settlement and curtailment charges	38			16			4			—			—			—
Special termination benefits	—			—			—			18			26			—
Regulatory adjustment	(42		)	(57		)	(110		)	—			(11		)	12
Total net periodic benefit cost	150			101			38			9			7			10

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss (gain)	—			26			17			(2		)	(2		)	(4		)
Prior service cost	1			—			4			—			—			—
Amortization of actuarial loss	(18		)	(10		)	(14		)	—			—			—
Amortization of prior service cost	(1		)	(1		)	—			—			—			—
Total recognized in OCI	(18		)	15			7			(2		)	(2		)	(4		)
Total recognized in net periodic benefit cost and OCI	$	132		$	116		$	45		$	7		$	5		$	6



NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	29		$	29		$	29		$	5		$	5		$	7
Interest cost	38			41			39			8			7			8
Expected return on assets	(47		)	(49		)	(54		)	(11		)	(12		)	(11		)
Amortization of:
Prior service cost	1			1			8			3			3			3
Actuarial loss (gain)	9			10			2			—			(1		)	—
Settlement charge	—			16			—			—			—			—
Special termination benefits	—			—			—			—			14			—
Regulatory adjustment	(8		)	(45		)	(20		)	—			(14		)	—
Total net periodic benefit cost	22			3			4			5			2			7

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss (gain)	2			1			(6		)	—			—			—
Amortization of actuarial loss	(1		)	(1		)	(1		)	—			—			—
Total recognized in OCI	1			—			(7		)	—			—			—
Total recognized in net periodic benefit cost and OCI	$	23		$	3		$	(3	)	$	5		$	2		$	7



NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	76		$	67		$	74		$	14		$	14		$	17
Interest cost	98			101			98			29			32			34
Expected return on assets	(103		)	(103		)	(106		)	(53		)	(56		)	(56		)
Amortization of:



Prior service cost (credit)	9			9			9			(3		)	(4		)	(7		)
Actuarial loss (gain)	19			11			21			(3		)	—			—
Settlement charge	30			—			—			—			—			—
Special termination benefits	—			—			—			18			11			—
Regulatory adjustment	(34		)	(12		)	(90		)	—			3			12
Total net periodic benefit cost	95			73			6			2			—			—

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss	—			4			—			—			—			—
Prior service cost	—			2			2			—			—			—
Amortization of prior service cost	(1		)	—			—			—			—			—
Total recognized in OCI	(1		)	6			2			—			—			—
Total recognized in net periodic benefit cost and OCI	$	94		$	79		$	8		$	2		$	—		$	—

The estimated net loss for the pension and PBOP plans that will be amortized from AOCI into net periodic benefit cost in 2018 is $10 million for Sempra Energy Consolidated and $1 million for each of SDG&E and SoCalGas. The estimated prior service cost that will be similarly amortized in 2018 is $1 million for each of Sempra Energy Consolidated and SoCalGas and a negligible amount for SDG&E.

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the IEnova and Chilquinta Energía plans, we develop the discount rate assumptions based on the results of a third party modeling tool that matches each plan’s expected cash flows to interest rates and expected maturity values of individually selected bonds in a hypothetical portfolio. The model controls the level of accumulated surplus that may result from the selection of bonds based solely on their premium yields by limiting the number of years to look back for selection to 3 years for pre-30-year and 6 years for post-30-year benefit payments. Additionally, the model ensures that an adequate number of bonds are selected in the portfolio by limiting the amount of the plan’s benefit payments that can be met by a single bond to 7.5 percent.

We selected individual bonds from a universe of Bloomberg AA-rated bonds that:


▪	have an outstanding issue of at least $50 million;


▪	are non-callable (or callable with make-whole provisions);


▪	exclude collateralized bonds; and


▪	exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded.

This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics:


▪	The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio.


▪	Recent events have caused significant price volatility to which rating agencies have not reacted.


▪	Lack of liquidity is causing price quotes to vary significantly from broker to broker.

We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP.

We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. We develop the discount rate assumptions for the plans at Chilquinta Energía based on 10-year Chilean government bond yields and the expected local long-term rate of inflation. These methods for developing the discount rate are required when there is no deep market for high quality corporate bonds.

Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.

The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:



WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION
AT DECEMBER 31
	Pension benefits				Other postretirement benefits
	2017		2016		2017		2016
Sempra Energy Consolidated:
Discount rate	3.65	%	4.08	%	3.70	%	4.19	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SDG&E:
Discount rate	3.64	%	4.08	%	3.65	%	4.15	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SoCalGas:
Discount rate	3.65	%	4.10	%	3.70	%	4.20	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00



WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
YEARS ENDED DECEMBER 31
	Pension benefits						Other postretirement benefits
	2017		2016		2015		2017		2016		2015
Sempra Energy Consolidated:
Discount rate	4.08	%	4.46	%	4.09	%	4.19	%	4.49	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.47		6.98		6.98
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SDG&E:
Discount rate	4.08	%	4.35	%	4.00	%	4.15	%	4.50	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.91		6.90		6.91
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SoCalGas:
Discount rate	4.10	%	4.50	%	4.15	%	4.20	%	4.50	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.37		7.00		7.00
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:



ASSUMED HEALTH CARE COST TREND RATES
AT DECEMBER 31
	Other postretirement benefit plans⁽¹⁾
	Pre-65 retirees						Retirees aged 65 years and older
	2017		2016		2015		2017		2016		2015
Health care cost trend rate assumed for next year	7.00	%	8.00	%	8.10	%	5.00	%	5.50	%	5.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	5.00	%	5.00	%	5.00	%	4.50	%	4.50	%	4.50	%
Year the rate reaches the ultimate trend	2022		2022		2022		2022		2022		2022

⁽¹⁾

Excludes Mobile Gas plan. For Mobile Gas, which we deconsolidated on September 12, 2016, the health care cost trend rate assumed for next year for all retirees was 8.10 percent in 2015; the ultimate trend was 5.00 percent in 2015; and the year the rate reaches the ultimate trend was 2022 in 2015. For Chilquinta Energía, the health care cost trend rate assumed for next year, and the ultimate trend, was 3.00 percent in each of 2017, 2016 and 2015.

A one-percent change in assumed health care cost trend rates would have had the following effects in 2017:



EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES
(Dollars in millions)
	Sempra Energy Consolidated					SDG&E					SoCalGas
	1%		1%			1%		1%			1%		1%
	increase		decrease			increase		decrease			increase		decrease
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$	5	$	(4	)	$	1	$	—		$	4	$	(3	)
Effect on the health care component of the
accumulated other postretirement
benefit obligations	53		(44		)	3		(2		)	48		(40		)

Plan Assets

Investment Allocation Strategy for Sempra Energy’s Pension Master Trust

Sempra Energy’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts as we discuss below for certain of the California Utilities’ PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra Energy.

The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ target asset allocations are


▪	38 percent domestic equity


▪	26 percent international equity


▪	18 percent long credit


▪	8 percent ultra-long duration government securities


▪	5 percent return-seeking credit


▪	5 percent real assets

The asset allocation of the plans is reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:


▪	long-term cost


▪	variability and level of contributions


▪	funded status


▪	a range of expected outcomes over varying confidence levels

We maintain asset allocations at strategic levels with reasonable bands of variance.

In accordance with the Sempra Energy pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.

Rate of Return Assumption

The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 7-percent expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 7 percent and 9 percent on return-seeking assets and between 3 percent and 5 percent for risk-mitigating assets. Certain trusts that hold assets for the SDG&E other postretirement benefit plan are subject to taxation, which impacts the expected after-tax return on assets in the plan.

Concentration of Risk

Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.

Investment Strategy for SDG&E’s and SoCalGas’ Other Postretirement Benefit Plans

SDG&E’s and SoCalGas’ PBOP plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Certain assets of SoCalGas’ PBOP plans, which are held in the pension master trust, are invested based on an allocation that seeks to mitigate risks for the assets of these plans, with 38 percent invested in return-seeking and 62 percent invested in risk-mitigating assets. The assets in the Voluntary Employee Beneficiary Association trusts are invested at an allocation similar to the pension master trust, with 74 percent invested in return-seeking and 26 percent invested in risk-mitigating assets. These allocations are periodically reviewed to ensure that plan assets are best positioned to meet plan obligations.

Fair Value of Pension and Other Postretirement Benefit Plan Assets

We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ PBOP plans based on the fair value hierarchy, except for certain investments measured at net asset value (NAV).

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Investments in certain fixed income securities are valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks for the remaining fixed income securities.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Private Equity Funds – These funds consist of investments in private equities that are held by limited partnerships following various strategies, including private equity and corporate finance. These partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. The value is determined based on the NAV of the proportionate share of an ownership interest in partners’ capital. Holdings in these types of private equity funds are negligible, as the funds are well past their expected investment term and have distributed the bulk of proceeds from investment sales.

Derivative Financial Instruments – Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index future contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.

There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented and there were no changes in the valuation techniques used.

SDG&E and SoCalGas each hold a proportionate share of investment assets in the pension master trust at Sempra Energy Consolidated. The fair values of our pension plan assets by asset category are as follows:



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Equity securities:
Domestic	$	946	$	—	$	946
International	538		—		538
Registered investment companies	102		—		102
Fixed income securities:
Domestic government bonds	242		27		269
International government bonds	—		12		12
Domestic corporate bonds	—		338		338
International corporate bonds	—		64		64
Registered investment companies	—		6		6
Other	—		1		1
Total investment assets in the fair value hierarchy	$	1,828	$	448	2,276
Investments measured at NAV:
Common/collective trusts					384
Private equity funds					4
Total investment assets⁽¹⁾					$	2,664
SDG&E’s proportionate share of investment assets					$	777
SoCalGas’ proportionate share of investment assets					$	1,697

	Fair value at December 31, 2016
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Equity securities:
Domestic	$	884	$	—	$	884
International	522		—		522
Registered investment companies	127		—		127
Fixed income securities:
Domestic government bonds	214		32		246
International government bonds	—		9		9
Domestic corporate bonds	—		346		346
International corporate bonds	—		94		94
Registered investment companies	—		14		14
Total investment assets in the fair value hierarchy	$	1,747	$	495	2,242
Investments measured at NAV:
Common/collective trusts					223
Private equity funds					4
Total investment assets⁽²⁾					$	2,469
SDG&E’s proportionate share of investment assets					$	717
SoCalGas’ proportionate share of investment assets					$	1,585


⁽¹⁾	Excludes cash and cash equivalents of $13 million and accounts payable of $18 million.


⁽²⁾	Excludes cash and cash equivalents of $14 million and accounts payable of $24 million.

The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SoCalGas’ PBOP plans and SDG&E’s PBOP plan trusts are as follows:



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1		Level 2		Total
SDG&E:
Equity securities:
Domestic	$	46	$	—	$	46
International	26		—		26
Registered investment companies	52		—		52
Fixed income securities:
Domestic government bonds	12		1		13
International government bonds	—		1		1
Domestic corporate bonds	—		17		17
International corporate bonds	—		3		3
Registered investment companies	—		17		17
Total investment assets in the fair value hierarchy	136		39		175
Investments measured at NAV – Common/collective trusts					20
Total investment assets⁽¹⁾					195

SoCalGas:
Equity securities:
Domestic	78		—		78
International	44		—		44
Registered investment companies	41		—		41
Fixed income securities:
Domestic government bonds	125		13		138
International government bonds	—		7		7
Domestic corporate bonds	—		164		164
International corporate bonds	—		28		28
Registered investment companies	—		85		85
Total investment assets in the fair value hierarchy	288		297		585
Investments measured at NAV – Common/collective trusts					406
Total investment assets⁽²⁾					991

Other Sempra Energy:
Equity securities:
Domestic	7		—		7
International	5		—		5
Registered investment companies	1		—		1
Fixed income securities:
Domestic government bonds	1		1		2
Domestic corporate bonds	—		2		2
International corporate bonds	—		1		1
Total investment assets in the fair value hierarchy	14		4		18
Investments measured at NAV – Common/collective trusts					2
Private equity funds					1
Total other Sempra Energy investment assets					21

Total Sempra Energy Consolidated investment assets in the fair value hierarchy	$	438	$	340
Total Sempra Energy Consolidated investment assets⁽³⁾					$	1,207


⁽¹⁾	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.


⁽²⁾	Excludes cash and cash equivalents of $4 million and accounts payable of $2 million held in SoCalGas PBOP plan trusts.


⁽³⁾	Excludes cash and cash equivalents of $5 million and accounts payable of $3 million at Sempra Energy Consolidated.



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2016
	Level 1		Level 2		Total
SDG&E:
Equity securities:
Domestic	$	41	$	—	$	41
International	24		—		24
Registered investment companies	46		—		46
Fixed income securities:
Domestic government bonds	10		1		11
Domestic corporate bonds	—		16		16
International corporate bonds	—		3		3
Registered investment companies	—		17		17
Total investment assets in the fair value hierarchy	121		37		158
Investments measured at NAV – Common/collective trusts					11
Total investment assets⁽¹⁾					169

SoCalGas:
Equity securities:
Domestic	130		—		130
International	77		—		77
Registered investment companies	46		—		46
Fixed income securities:
Domestic government bonds	52		8		60
International government bonds	—		2		2
Domestic corporate bonds	—		94		94
International corporate bonds	—		28		28
Registered investment companies	—		47		47
Total investment assets in the fair value hierarchy	305		179		484
Investments measured at NAV – Common/collective trusts					386
Total investment assets⁽²⁾					870

Other Sempra Energy:
Equity securities:
Domestic	6		—		6
International	3		—		3
Fixed income securities:
Domestic government bonds	1		—		1
International government bonds	—		1		1
Domestic corporate bonds	—		2		2
International corporate bonds	—		1		1
Registered investment companies	—		1		1
Total investment assets in the fair value hierarchy	10		5		15
Investments measured at NAV – Common/collective trusts					3
Total other Sempra Energy investment assets					18

Total Sempra Energy Consolidated investment assets in the fair value hierarchy	$	436	$	221
Total Sempra Energy Consolidated investment assets⁽³⁾					$	1,057


⁽¹⁾	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.


⁽²⁾	Excludes cash and cash equivalents of $4 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts.


⁽³⁾	Excludes cash and cash equivalents of $5 million and accounts payable of $5 million at Sempra Energy Consolidated.

Future Payments

We expect to contribute the following amounts to our pension and PBOP plans in 2018:



EXPECTED CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Pension plans	$	226	$	48	$	113
Other postretirement benefit plans	9		3		2

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.



EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	Pension benefits		Other postretirement benefits		Pension benefits		Other postretirement benefits		Pension benefits		Other postretirement benefits
2018	$	351	$	52	$	90	$	10	$	192	$	38
2019	304		52		76		10		188		39
2020	294		54		74		10		179		40
2021	285		53		71		11		173		40
2022	273		53		68		11		172		40
2023-2027	1,217		262		314		52		782		197

PROFIT SHARING PLANS

Under Chilean law, Chilquinta Energía is required to pay all employees either (1) 30 percent of Chilquinta Energía’s taxable income after deducting a 10-percent return on equity, allocated in proportion to the annual salary of each employee or (2) 25 percent of each employee’s annual salary, with a maximum mandatory profit sharing of 4.75 months of Chile’s legal minimum salary. Chilquinta Energía has elected the second option but calculates the profit sharing amounts with actual employee salaries instead of the legal minimum salary, resulting in a higher cost. The amounts are paid out each pay period. Chilquinta Energía recorded annual profit sharing expense of $7 million for 2017, $5 million for 2016 and $3 million for 2015 related to this plan.

Under Peruvian law, Luz del Sur is required to pay their employees 5 percent of Luz del Sur’s taxable income, paid once a year and allocated as follows: 50 percent based on each employee’s annual hours worked and 50 percent based on each employee’s annual salary. Luz del Sur recorded annual profit sharing expense of $12 million in 2017 and $10 million in both 2016 and 2015 related to this plan.

SAVINGS PLANS

Sempra Energy offers trusteed savings plans to all domestic employees, all employees in Mexico and certain employees in Chile. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.

Employer contributions to the savings plans were as follows:



EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	2017		2016		2015
Sempra Energy Consolidated	$	41	$	42	$	43
SDG&E	14		15		17
SoCalGas	22		22		21

The market value of Sempra Energy common stock held by the savings plans was $1.1 billion at both December 31, 2017 and 2016.

SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Share-based Compensation

SHARE-BASED COMPENSATION

SEMPRA ENERGY EQUITY COMPENSATION PLANS

Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including:


▪	non-qualified stock options


▪	incentive stock options


▪	restricted stock awards


▪	restricted stock units


▪	stock appreciation rights


▪	performance awards


▪	stock payments


▪	dividend equivalents

Eligible employees, including those from the California Utilities, participate in Sempra Energy’s share-based compensation plans as a component of their compensation package.

In the three years ended December 31, 2017, Sempra Energy had the following types of equity awards outstanding:

▪

Non-Qualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a four-year period, and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements, in accordance with the terms of the grant, or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment.

▪

Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra Energy common stock at the end of three-year (for awards granted during or after 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra Energy’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our targets for awards that vest based on EPS growth.


◦	For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50 percent of the number of granted RSUs may be issued.


◦	For awards granted during or after 2014, up to an additional 100 percent of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.

◦

For awards granted in 2015 and 2016, and certain awards granted in 2017, that vest based on Sempra Energy’s total return to shareholders, a modifier adds 20 percent to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra Energy and reduces the award’s payout by 20 percent for performance in the bottom quartile. However, in no event will more than an additional 100 percent of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices.

If Sempra Energy’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis.


▪	Other Performance-Based Restricted Stock Units: RSUs were granted in 2014 and 2015 in connection with the creation of Cameron LNG JV.


◦	The 2014 awards vest to the extent that the Compensation Committee of Sempra Energy’s board of directors determines that the objectives of the joint venture are continuing to be achieved. These awards vest on the anniversary of the grant date over a period of either two or three years.


◦	The 2015 awards vest to the extent that the Compensation Committee of Sempra Energy’s board of directors determines that Sempra Energy has achieved positive cumulative net income for fiscal years 2015 through 2017 and Cameron LNG JV has commenced commercial operations of the first train.


▪	Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest at the end of three-year (for awards granted during or after 2015) or four-year service periods.


▪	Restricted Stock Awards: RSAs are solely service-based and generally vest at the end of four years of service. Accelerated vesting of RSAs may occur upon eligibility for retirement. Holders of RSAs have full voting rights.

For RSA and RSU awards, vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, in accordance with severance pay agreements, or at the discretion of the Compensation Committee of Sempra Energy’s board of directors. Dividend equivalents on shares subject to RSAs and RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSAs and RSUs to which the dividends relate.

In April 2013, the IEnova board of directors approved the IEnova 2013 Long-Term Incentive Plan. The purpose of this plan is to align the interests of employees and directors of IEnova with its shareholders. All awards issued from this plan and any related dividend equivalents will settle in cash at vesting based on the price of IEnova common stock. In 2017, 2016 and 2015, IEnova granted 1,043,709 RSUs, 378,367 RSUs and 278,538 RSUs, respectively, from this plan, 1,374,114 of which remain outstanding at December 31, 2017. During 2017, 2016 and 2015, IEnova paid cash of $2 million, $1 million and $4 million, respectively, to settle vested awards.

SHARE-BASED AWARDS AND COMPENSATION EXPENSE

At December 31, 2017, 5,589,925 common shares were authorized and available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for non-qualified stock options, RSAs and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, in the year that an employee becomes eligible for retirement, the remaining expense related to the employee’s awards is recognized immediately. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. Beginning in 2016, we recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments. In 2015, $52 million in excess tax benefits was recorded within Sempra Energy’s Shareholders’ Equity.

Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra Energy plans’ corporate staff costs. Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:



SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Share-based compensation expense, before income taxes	$	78		$	46		$	48
Income tax benefit	(31		)	(18		)	(19		)
	$	47		$	28		$	29

Capitalized share-based compensation cost	$	9		$	7		$	6
Excess income tax benefit	$	—		$	(34	)	$	—
SDG&E:
Share-based compensation expense, before income taxes	$	13		$	7		$	8
Income tax benefit	(5		)	(3		)	(3		)
	$	8		$	4		$	5

Capitalized share-based compensation cost	$	5		$	4		$	4
Excess income tax benefit	$	—		$	(7	)	$	—
SoCalGas:
Share-based compensation expense, before income taxes	$	17		$	8		$	10
Income tax benefit	(7		)	(3		)	(4		)
	$	10		$	5		$	6



Capitalized share-based compensation cost	$	4	$	3		$	2
Excess income tax benefit	$	—	$	(4	)	$	—

SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS

We use a Black-Scholes option-pricing model to estimate the fair value of each non-qualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on the historical volatility of Sempra Energy’s common stock price. We base the average expected life for options on the contractual term of the option and expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected life assumed at the date of the grant.

The following table shows a summary of non-qualified stock options at December 31, 2017 and activity for the year then ended:



NON-QUALIFIED STOCK OPTIONS

	Common shares under option		Weighted- average exercise price		Weighted- average remaining contractual term (in years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2017	360,255		$	52.46
Exercised	(164,454	)	$	55.04
Outstanding at December 31, 2017	195,801		$	50.30	1.5	$	11

Vested at December 31, 2017	195,801		$	50.30	1.5	$	11
Exercisable at December 31, 2017	195,801		$	50.30	1.5	$	11

The aggregate intrinsic value at December 31, 2017 is the total of the difference between Sempra Energy’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for non-qualified stock options exercised in the last three years was


▪	$9 million in 2017


▪	$8 million in 2016


▪	$12 million in 2015

No stock options were granted in 2017, 2016 or 2015. All outstanding stock options were fully vested and all compensation cost related to stock options had been recognized as of December 31, 2014.

We received cash of $9 million from stock option exercises during 2017.

SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS

We use a Monte-Carlo simulation model to estimate the fair value of our RSAs and our RSUs that vest based on Sempra Energy’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return, and a number of other variables. Below are key assumptions for awards granted in 2017, 2016 and 2015 for Sempra Energy:



KEY ASSUMPTIONS FOR AWARDS GRANTED

	Years ended December 31,
	2017		2016		2015
Risk-free rate of return	1.5	%	1.3	%	1.1	%
Stock price volatility	17		16		14

Restricted Stock Awards

No RSAs were granted in 2017, 2016 or 2015. All outstanding RSAs were fully vested and all compensation cost related to RSAs had been recognized as of December 31, 2016. The total fair value of RSA shares vested during the year was a negligible amount in 2016 and $1 million in 2015.

Restricted Stock Units

We provide below a summary of Sempra Energy’s RSUs as of December 31, 2017 and the activity during the year.



RESTRICTED STOCK UNITS

	Performance-based restricted stock units				Service-based restricted stock units
	Units		Weighted- average grant-date fair value		Units		Weighted- average grant-date fair value
Nonvested at January 1, 2017	1,954,322		$	88.58	305,736		$	94.68
Granted	424,760		$	110.54	93,619		$	101.88
Vested	(637,577	)	$	57.42	(108,880	)	$	79.61
Forfeited	(39,888	)	$	103.17	(4,580	)	$	97.84
Nonvested at December 31, 2017⁽¹⁾	1,701,617		$	105.84	285,895		$	98.81
Expected to vest at December 31, 2017	1,670,885		$	105.38	282,106		$	98.65

⁽¹⁾

Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, except for those issued in connection with the creation of Cameron LNG JV, up to an additional 50 percent (100 percent for awards granted during or after 2014) of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.

The total fair value of RSU shares vested during the year was $45 million in 2017 and $46 million in each of 2016 and 2015.

The $17 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2017 is expected to be recognized over a weighted-average period of 1.9 years. The weighted-average per-share fair values for performance-based RSUs granted were $100.37 and $123.30 in 2016 and 2015, respectively. The weighted-average per-share fair values for service-based RSUs granted were $93.59 and $111.43 in 2016 and 2015, respectively.

DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

HEDGE ACCOUNTING

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

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

ENERGY DERIVATIVES

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

▪

The California Utilities use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

▪

SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.

▪

Sempra Mexico, Sempra LNG & Midstream and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Consolidated Statements of Operations.


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

We summarize net energy derivative volumes at December 31, 2017 and 2016 as follows:



NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
		December 31,
Commodity	Unit of measure	2017	2016
California Utilities:
SDG&E:
Natural gas	MMBtu	39	48
Electricity	MWh	3	4
Congestion revenue rights	MWh	59	48
SoCalGas – natural gas	MMBtu	—	1

Energy-Related Businesses:
Sempra LNG & Midstream – natural gas	MMBtu	3	31
Sempra Mexico – natural gas	MMBtu	4	—

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

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy and its other subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

At December 31, 2017 and 2016, the net notional amounts of our interest rate derivatives, excluding joint ventures, were:



INTEREST RATE DERIVATIVES
(Dollars in millions)
	December 31, 2017			December 31, 2016
	Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges⁽¹⁾	$	861	2018-2032	$	924	2017-2032
SDG&E:
Cash flow hedge⁽¹⁾	295		2018-2019	305		2017-2019


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

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.

We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or inflation.

In addition, Sempra South American Utilities and its joint ventures use foreign currency derivatives to manage foreign currency rate risk. We discuss these derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4.

At December 31, 2017 and 2016, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:



FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	December 31, 2017			December 31, 2016
	Notional amount		Maturities	Notional amount		Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$	408	2018-2023	$	408	2017-2023
Other foreign currency derivatives⁽¹⁾	345		2018-2019	86		2017-2018


⁽¹⁾	In the first quarter of 2018, we entered into foreign currency derivatives with notional amounts totaling $650 million that expire between December 2018 and January 2019.

FINANCIAL STATEMENT PRESENTATION

The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets at December 31, 2017 and 2016, including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions.



DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017
	Current assets: Fixed-price contracts and other derivatives⁽¹⁾			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives⁽²⁾			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments⁽³⁾	$	5		$	2		$	(51	)	$	(165	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	—			—			(1		)	—
Commodity contracts not subject to rate recovery	81			8			(72		)	(6		)
Associated offsetting commodity contracts	(67		)	(5		)	67			5
Commodity contracts subject to rate recovery	28			101			(65		)	(120		)
Associated offsetting commodity contracts	—			(1		)	—			1
Associated offsetting cash collateral	—			—			19			4
Net amounts presented on the balance sheet	47			105			(103		)	(281		)
Additional cash collateral for commodity contracts not subject to rate recovery	2			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	17			—			—			—
Total⁽⁴⁾	$	66		$	105		$	(103	)	$	(281	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments⁽³⁾	$	—		$	—		$	(10	)	$	(3	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	26			101			(63		)	(120		)
Associated offsetting commodity contracts	—			(1		)	—			1
Associated offsetting cash collateral	—			—			19			4
Net amounts presented on the balance sheet	26			100			(54		)	(118		)
Additional cash collateral for commodity contracts subject to rate recovery	16			—			—			—
Total⁽⁴⁾	$	42		$	100		$	(54	)	$	(118	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	2		$	—		$	(2	)	$	—
Net amounts presented on the balance sheet	2			—			(2		)	—
Additional cash collateral for commodity contracts subject to rate recovery	1			—			—			—
Total	$	3		$	—		$	(2	)	$	—


⁽¹⁾	Included in Current Assets: Other for SoCalGas.


⁽²⁾	Included in Current Liabilities: Other for SoCalGas.


⁽³⁾	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.


⁽⁴⁾	Normal purchase contracts previously measured at fair value are excluded.



DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2016
	Current assets: Fixed-price contracts and other derivatives⁽¹⁾			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives⁽²⁾			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments⁽³⁾	$	7		$	2		$	(24	)	$	(228	)
Commodity contracts not subject to rate recovery	—			—			(14		)	—
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	248			36			(254		)	(28		)
Associated offsetting commodity contracts	(242		)	(27		)	242			27
Associated offsetting cash collateral	—			(1		)	16			1
Commodity contracts subject to rate recovery	37			73			(57		)	(150		)
Associated offsetting commodity contracts	(9		)	(1		)	9			1
Associated offsetting cash collateral	—			—			5			13
Net amounts presented on the balance sheet	41			82			(77		)	(364		)
Additional cash collateral for commodity contracts not subject to rate recovery	10			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	32			—			—			—
Total⁽⁴⁾	$	83		$	82		$	(77	)	$	(364	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments⁽³⁾	$	—		$	—		$	(13	)	$	(12	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	33			73			(51		)	(150		)
Associated offsetting commodity contracts	(6		)	(1		)	6			1
Associated offsetting cash collateral	—			—			3			13
Net amounts presented on the balance sheet	27			72			(55		)	(148		)
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	30			—			—			—
Total⁽⁴⁾	$	58		$	72		$	(55	)	$	(148	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	4		$	—		$	(6	)	$	—
Associated offsetting commodity contracts	(3		)	—			3			—
Associated offsetting cash collateral	—			—			2			—
Net amounts presented on the balance sheet	1			—			(1		)	—
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	2			—			—			—
Total	$	4		$	—		$	(1	)	$	—


⁽¹⁾	Included in Current Assets: Other for SoCalGas.


⁽²⁾	Included in Current Liabilities: Other for SoCalGas.


⁽³⁾	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.


⁽⁴⁾	Normal purchase contracts previously measured at fair value are excluded.

The table below includes the effects of derivative instruments designated as fair value hedges on the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. There were no fair value hedges outstanding during the year ended December 31, 2017.



FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2016			2015
Sempra Energy Consolidated:
Interest rate instruments	Interest Expense	$	3		$	6
Interest rate instruments	Other Income, Net	(2		)	(5		)
Total⁽¹⁾		$	1		$	1


⁽¹⁾	There was no hedge ineffectiveness in 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.

The effects of derivative instruments designated as cash flow hedges on the Consolidated Statements of Operations and in OCI and AOCI for the years ended December 31 were:



CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss) recognized in OCI										Pretax gain (loss) reclassified from AOCI into earnings
	Years ended December 31,										Years ended December 31,
	2017			2016			2015			Location	2017			2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments⁽¹⁾	$	19		$	(8	)	$	(18	)	Interest Expense	$	4		$	(17	)	$	(18	)
Interest rate instruments	(25		)	(9		)	(80		)	Equity Earnings, Before Income Tax	(8		)	(10		)	(12		)
Interest rate and foreign exchange instruments	—			—			—			Remeasurement of Equity Method Investment	—			(7		)	—
Interest rate and foreign exchange instruments	(9		)	5			(20		)	Equity Earnings, Net of Income Tax	(12		)	(5		)	(13		)
Foreign exchange instruments	4			4			—			Revenues: Energy- Related Businesses	2			—			—
Commodity contracts not subject to rate recovery	3			(13		)	12			Revenues: Energy- Related Businesses	(9		)	6			14
Total⁽²⁾	$	(8	)	$	(21	)	$	(106	)		$	(23	)	$	(33	)	$	(29	)
SDG&E:
Interest rate instruments⁽¹⁾⁽³⁾	$	(2	)	$	(2	)	$	(6	)	Interest Expense	$	(13	)	$	(12	)	$	(12	)
SoCalGas:
Interest rate instruments	$	—		$	—		$	—		Interest Expense	$	—		$	(1	)	$	(1	)


⁽¹⁾	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.


⁽²⁾	There was $5 million, $4 million and $2 million of losses from ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015, respectively.


⁽³⁾	There was negligible hedge ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015.

For Sempra Energy Consolidated, we expect that net losses of $33 million, which are net of income tax benefit, that are currently recorded in AOCI (including $9 million of losses in noncontrolling interest related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. SoCalGas expects that $1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature.

For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at December 31, 2017 is approximately 14 years and 1 year for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 18 years.

The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2017			2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments	Other Income, Net	$	49		$	(32	)	$	(4	)
Foreign exchange instruments	Equity Earnings, Net of Income Tax	1			3			(4		)
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	16			(18		)	42
Commodity contracts not subject to rate recovery	Operation and Maintenance	—			1			(1		)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	54			(53		)	(126		)
Commodity contracts subject to rate recovery	Cost of Natural Gas	(2		)	(4		)	1
Total		$	118		$	(103	)	$	(92	)
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	54		$	(53	)	$	(126	)
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—		$	1		$	(1	)
Commodity contracts subject to rate recovery	Cost of Natural Gas	(2		)	(4		)	1
Total		$	(2	)	$	(3	)	$	—

CONTINGENT FEATURES

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

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at December 31, 2017 and 2016 is $6 million and $10 million, respectively. At December 31, 2017, if the credit ratings of Sempra Energy were reduced below investment grade, $6 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position at December 31, 2017 and 2016 is $1 million and negligible, respectively. At December 31, 2017, if the credit ratings of SDG&E were reduced below investment grade, $1 million of additional assets could be required to be posted as collateral for these derivative contracts.

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

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASURES

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 in “Financial Statement Presentation.”

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

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 in the tables below include the following:

▪

Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

▪

For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information.”


▪	Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both December 31, 2017 and 2016.

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



RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491		$	5	$	—	$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45			9		—		54
Municipal bonds	—			250		—		250
Other securities	—			217		—		217
Total debt securities	45			476		—		521
Total nuclear decommissioning trusts⁽¹⁾	536			481		—		1,017
Interest rate and foreign exchange instruments	—			7		—		7
Commodity contracts not subject to rate recovery	5			12		—		17
Effect of netting and allocation of collateral⁽²⁾	2			—		—		2
Commodity contracts subject to rate recovery	—			2		126		128
Effect of netting and allocation of collateral⁽²⁾	12			—		5		17
Total	$	555		$	502	$	131	$	1,188

Liabilities:
Interest rate and foreign exchange instruments	$	—		$	217	$	—	$	217
Commodity contracts not subject to rate recovery	—			6		—		6
Commodity contracts subject to rate recovery	23			7		154		184
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	230	$	154	$	384

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508		$	—	$	—	$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36			16		—		52
Municipal bonds	—			206		—		206
Other securities	—			141		—		141
Total debt securities	36			363		—		399
Total nuclear decommissioning trusts⁽¹⁾	544			363		—		907
Interest rate and foreign exchange instruments	—			9		—		9
Commodity contracts not subject to rate recovery	—			15		—		15
Effect of netting and allocation of collateral⁽²⁾	2			7		—		9
Commodity contracts subject to rate recovery	1			3		96		100
Effect of netting and allocation of collateral⁽²⁾	27			—		5		32
Total	$	574		$	397	$	101	$	1,072

Liabilities:
Interest rate and foreign exchange instruments	$	—		$	252	$	—	$	252
Commodity contracts not subject to rate recovery	16			11		—		27
Effect of netting and allocation of collateral⁽²⁾	(17		)	—		—		(17		)
Commodity contracts subject to rate recovery	19			8		170		197
Effect of netting and allocation of collateral⁽²⁾	(18		)	—		—		(18		)
Total	$	—		$	271	$	170	$	441


⁽¹⁾	Excludes cash balances and cash equivalents.


⁽²⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491		$	5	$	—	$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45			9		—		54
Municipal bonds	—			250		—		250
Other securities	—			217		—		217
Total debt securities	45			476		—		521
Total nuclear decommissioning trusts⁽¹⁾	536			481		—		1,017
Commodity contracts subject to rate recovery	—			—		126		126
Effect of netting and allocation of collateral⁽²⁾	11			—		5		16
Total	$	547		$	481	$	131	$	1,159

Liabilities:
Interest rate instruments	$	—		$	13	$	—	$	13
Commodity contracts subject to rate recovery	23			5		154		182
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	18	$	154	$	172

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508		$	—	$	—	$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36			16		—		52
Municipal bonds	—			206		—		206
Other securities	—			141		—		141
Total debt securities	36			363		—		399
Total nuclear decommissioning trusts⁽¹⁾	544			363		—		907
Commodity contracts not subject to rate recovery	—			—		—		—
Effect of netting and allocation of collateral⁽²⁾	1			—		—		1
Commodity contracts subject to rate recovery	1			2		96		99
Effect of netting and allocation of collateral⁽²⁾	25			—		5		30
Total	$	571		$	365	$	101	$	1,037

Liabilities:
Interest rate instruments	$	—		$	25	$	—	$	25
Commodity contracts subject to rate recovery	17			7		170		194
Effect of netting and allocation of collateral⁽²⁾	(16		)	—		—		(16		)
Total	$	1		$	32	$	170	$	203


⁽¹⁾	Excludes cash balances and cash equivalents.


⁽²⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3			Total
Assets:
Commodity contracts subject to rate recovery	$	—		$	2	$	—		$	2
Effect of netting and allocation of collateral⁽¹⁾	1			—		—			1
Total	$	1		$	2	$	—		$	3
Liabilities:
Commodity contracts subject to rate recovery	$	—		$	2	$	—		$	2
Total	$	—		$	2	$	—		$	2

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3			Total
Assets:
Commodity contracts not subject to rate recovery	$	—		$	—	$	—		$	—
Effect of netting and allocation of collateral⁽¹⁾	1			—		—			1
Commodity contracts subject to rate recovery	—			1		—			1
Effect of netting and allocation of collateral⁽¹⁾	2			—		—			2
Total	$	3		$	1	$	—		$	4
Liabilities:
Commodity contracts subject to rate recovery	$	2		$	1	$	—		$	3
Effect of netting and allocation of collateral⁽¹⁾	(2		)	—		—		—	(2		)
Total	$	—		$	1	$	—		$	1


⁽¹⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

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



LEVEL 3 RECONCILIATIONS⁽¹⁾
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Balance at January 1	$	(74	)	$	19		$	107
Realized and unrealized gains (losses)	34			(120		)	(134		)
Allocated transmission instruments	6			8			12
Settlements	6			19			34
Balance at December 31	$	(28	)	$	(74	)	$	19
Change in unrealized gains (losses) relating to
instruments still held at December 31	$	30		$	(101	)	$	(27	)

⁽¹⁾ Excludes the effect of contractual ability to settle contracts under master netting agreements.

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

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the CAISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, are in the following ranges:



CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS

Settlement year		Price per MWh
2018	$	(7.25	)	to	$	11.99
2017		(11.88	)	to		6.93
2016		(23.81	)	to		10.23

The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 9.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. These inputs range from $22.55 per MWh to $51.01 per MWh at December 31, 2017, and $17.40 per MWh to $56.67 per MWh at December 31, 2016. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 9.

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

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, accounts and notes receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets at December 31, 2017 and 2016:



FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	December 31, 2017
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates⁽¹⁾	$	604	$	—	$	528	$	96	$	624
Long-term amounts due to unconsolidated affiliates	35		—		32		—		32
Total long-term debt⁽²⁾⁽³⁾	17,138		817		17,134		458		18,409
SDG&E:
Total long-term debt⁽³⁾⁽⁴⁾	$	4,868	$	—	$	5,073	$	295	$	5,368
SoCalGas:
Total long-term debt⁽⁵⁾	$	3,009	$	—	$	3,192	$	—	$	3,192

	December 31, 2016
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates⁽¹⁾	$	184	$	—	$	91	$	84	$	175
Total long-term debt⁽²⁾⁽³⁾	15,068		—		15,455		492		15,947
SDG&E:
Total long-term debt⁽³⁾⁽⁴⁾	$	4,654	$	—	$	4,727	$	305	$	5,032
SoCalGas:
Total long-term debt⁽⁵⁾	$	3,009	$	—	$	3,131	$	—	$	3,131


⁽¹⁾	Excluding accumulated interest outstanding of $29 million and $17 million at December 31, 2017 and 2016, respectively, and excluding foreign currency translation of $35 million on a Mexican peso-denominated loan at December 31, 2017.


⁽²⁾	Before reductions for unamortized discount (net of premium) and debt issuance costs of $143 million and $109 million at December 31, 2017

and 2016, respectively, and excluding build-to-suit and capital lease obligations of $877 million and $383 million at December 31, 2017 and 2016, respectively. We discuss our long-term debt in Note 5.


⁽³⁾	Level 3 instruments include $295 million and $305 million at December 31, 2017 and 2016, respectively, related to Otay Mesa VIE.


⁽⁴⁾	Before reductions for unamortized discount and debt issuance costs of $45 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $732 million and $240 million at December 31, 2017 and 2016, respectively.


⁽⁵⁾	Before reductions for unamortized discount and debt issuance costs of $24 million and $27 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $1 million at December 31, 2017.

We determine the fair value of certain long-term amounts due from/to unconsolidated affiliates and long-term debt based on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value certain other long-term amounts due from unconsolidated affiliates using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).

We provide the fair values for the securities held in the NDT funds related to SONGS in Note 13.

NON-RECURRING FAIR VALUE MEASURES

Sempra Mexico

IEnova Pipelines. In September 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in IEnova Pipelines, increasing its ownership interest to 100 percent. As a result of IEnova obtaining control over IEnova Pipelines, in the year ended December 31, 2016, Sempra Mexico recognized a pretax gain of $617 million ($432 million after-tax) for the excess of the acquisition-date fair value of its previously held equity interest in IEnova Pipelines ($1.144 billion) over the carrying value of that interest ($520 million) and losses reclassified from AOCI ($7 million), included as Remeasurement of Equity Method Investment on Sempra Energy’s Consolidated Statement of Operations. The valuation technique used to measure the acquisition-date fair value of our equity interest in IEnova Pipelines immediately prior to the business acquisition was based on the fair value of the entire business combination ($2.288 billion) less the fair value of the consideration paid ($1.144 billion, the equity sale price). We discuss the IEnova Pipelines acquisition in Note 3.

TdM. In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM natural gas-fired power plant, and classified it as held for sale on the Sempra Energy Consolidated Balance Sheet, as we discuss in Note 3. In September 2016, we received market information that indicated that the fair value of TdM may be less than its carrying value. As a result, after performing an analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ($111 million after-tax) in the third quarter of 2016. In 2017, Sempra Mexico received a purchase price offer resulting from negotiations with an active market participant. This new market information indicated that the fair value of TdM was lower than its carrying value at June 30, 2017. As a result, in the second quarter of 2017, Sempra Mexico further reduced the carrying value of TdM by recognizing a noncash impairment charge of $71 million. Impairments recorded for TdM are included in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. Market values resulting from a third-party bidding process and a purchase price offer are considered to be Level 2 inputs in the fair value hierarchy, as they represent observable pricing inputs.

Sempra LNG & Midstream

Rockies Express. As we discuss in Note 3, in March 2016, Sempra LNG & Midstream agreed to sell its 25-percent interest in Rockies Express for cash consideration of $440 million, subject to adjustment at closing. In March 2016, we recorded a noncash impairment of our investment in Rockies Express of $44 million ($27 million after-tax). The charge is included in Equity Earnings, Before Income Tax, on the Sempra Energy Consolidated Statement of Operations for the year ended December 31, 2016. We considered the sale price for our equity interest in Rockies Express to be a market participants’ view of the total value of Rockies Express and measured the fair value of our investment based on the equity sale price.

The following table summarizes significant inputs impacting our non-recurring fair value measures:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Estimated

fair

value

Valuation technique

Fair

value

hierarchy

% of

fair value

measurement

Inputs used to

develop

measurement

Range of

inputs

Investment in IEnova Pipelines

1,144

⁽¹⁾

Market approach

Level 2

100%

Equity sale price

100%

TdM

145

⁽²⁾

Market approach

Level 2

100%

Purchase price offers

100%

TdM

⁽³⁾

Market approach

Level 2

100%

Purchase price offer

100%

Investment in
Rockies Express

440

⁽⁴⁾

Market approach

Level 2

100%

Equity sale price

100%


⁽¹⁾	At measurement date of September 26, 2016, immediately prior to acquiring a 100-percent ownership interest in IEnova Pipelines.


⁽²⁾	At measurement date of September 29, 2016.


⁽³⁾	At measurement date of June 30, 2017. At December 31, 2017, TdM has a carrying value of $78 million, reflecting subsequent business activity, and is classified as held for sale.


⁽⁴⁾	At measurement date of March 29, 2016. On May 9, 2016, Sempra LNG & Midstream sold its equity interest in Rockies Express.

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

+ References + Details

PREFERRED STOCK

12 Months Ended

Dec. 31, 2017

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE

Preferred Stock

PREFERRED STOCK

Sempra Energy and SDG&E are authorized to issue up to 50 million and 45 million shares of preferred stock, respectively. At December 31, 2017 and 2016, Sempra Energy and SDG&E have no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance.

In January 2018, Sempra Energy issued 17,250,000 shares of mandatory convertible preferred stock and received proceeds of approximately $1.69 billion (net of underwriting discounts, but before related expenses), which we discuss in Note 18.

SoCalGas is authorized to issue up to an aggregate of 11 million shares of preferred stock, series preferred stock and preference stock. At December 31, 2017 and 2016, SoCalGas has the following preferred stock outstanding:



PREFERRED STOCK OUTSTANDING
(Dollars in millions, except per share amounts)
	December 31,
	2017			2016
$25 par value, authorized 1,000,000 shares:
6% Series, 79,011 shares outstanding	$	3		$	3
6% Series A, 783,032 shares outstanding	19			19
SoCalGas - Total preferred stock	22			22
Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises	(2		)	(2		)
Sempra Energy - Total preferred stock of subsidiary	$	20		$	20

None of SoCalGas’ outstanding preferred stock is callable, and no shares are subject to mandatory redemption.

All outstanding shares have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid dividends.

In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize 5 million shares of series preferred stock and 5 million shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock and series preferred stock. Other rights and privileges of any new series of such stock would be established by the SoCalGas board of directors at the time of issuance.

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

SEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE

The following table provides EPS computations for the years ended December 31, 2017, 2016 and 2015. Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.



EARNINGS PER SHARE COMPUTATIONS AND DIVIDENDS DECLARED
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2017		2016		2015
Numerator:
Earnings/Income attributable to common shares	$	256	$	1,370	$	1,349

Denominator:
Weighted-average common shares outstanding for basic EPS⁽¹⁾	251,545		250,217		248,249
Dilutive effect of stock options, RSAs and RSUs⁽²⁾	755		938		2,674
Weighted-average common shares outstanding for diluted EPS	252,300		251,155		250,923

EPS:
Basic	$	1.02	$	5.48	$	5.43
Diluted	$	1.01	$	5.46	$	5.37

Dividends declared per share of common stock⁽³⁾	$	3.29	$	3.02	$	2.80


⁽¹⁾	Includes average fully vested RSUs held in our Deferred Compensation Plan of 609 in 2017, 568 in 2016 and 491 in 2015. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.


⁽²⁾	Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8, dilutive RSUs may vary widely from period-to-period.


⁽³⁾	Our board of directors has the discretion to determine the payment and amount of future dividends.

The potentially dilutive impact from stock options, RSAs and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS excludes 237,741, zero and 722 potentially dilutive shares for the years ended December 31, 2017, 2016 and 2015, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.

We are authorized to issue 750 million shares of no par value common stock. The following table provides common stock activity for the years ended December 31, 2017, 2016 and 2015.



COMMON STOCK ACTIVITY

	Years ended December 31,
	2017		2016		2015
Common shares outstanding, January 1	250,152,514		248,298,080		246,330,884
RSUs vesting⁽¹⁾	362,022		1,363,555		1,499,062
Stock options exercised	164,454		167,742		227,815
Savings plan issuance	567,428		653,607		652,631
Common stock investment plan⁽²⁾	254,047		266,056		249,665
Issuance of RSUs held in our Deferred Compensation Plan	7,811		—		—
Shares repurchased⁽³⁾	(149,299	)	(596,526	)	(661,977	)
Common shares outstanding, December 31	251,358,977		250,152,514		248,298,080


⁽¹⁾	Includes dividend equivalents.


⁽²⁾	Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.


⁽³⁾	From time to time, we purchase shares of our common stock or units from long-term incentive plan participants who elect to sell to us a sufficient number of vested RSAs or RSUs to meet minimum statutory tax withholding requirements.

On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock in a registered public offering, pursuant to forward sale agreements. In connection with the overallotment option granted to the underwriters, on January 9, 2018, we issued 3,504,672 shares of our common stock and received net proceeds of $368 million (net of underwriting discounts, but before deducting other related expenses) for such shares, which we discuss in Note 18.

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

12 Months Ended

Dec. 31, 2017

San Onofre Nuclear Generating Station (SONGS)

SAN ONOFRE NUCLEAR GENERATING STATION

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

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

SONGS STEAM GENERATOR REPLACEMENT PROJECT

As part of the SGRP, the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.

The replacement steam generators were designed and provided by MHI. In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents.

On March 13, 2017, the Tribunal overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is offset by these costs, resulting in a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million, resulting in a net damage award of $12 million, which was paid by MHI to SDG&E in March 2017. These amounts include certain adjustments to calculations supporting the Tribunal’s findings. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded the proceeds from the MHI arbitration by reducing Operation and Maintenance for previously incurred legal costs of $11 million, and shared the remaining $1 million equally between ratepayers and shareholders.

SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE

In November 2012, in response to the outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage.

In November 2014, the CPUC issued a final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement) in the SONGS OII proceeding executed by SDG&E along with Edison, TURN, ORA and two other intervenors. The Amended Settlement Agreement does not affect ongoing or future proceedings before the NRC, or any litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries addressed in the final decision) or any proceedings addressing decommissioning activities and costs.

The Amended Settlement Agreement provides for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, including base plant and construction work in progress, but excluding its investment in the SGRP, generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to:


▪	SDG&E’s weighted-average return on debt, plus


▪	50 percent of SDG&E’s weighted-average return on preferred stock, as authorized in the CPUC’s cost of capital (discussed in Note 14) proceeding then in effect (collectively, SONGS return on rate base)

In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest.

In December 2016, the CPUC issued another procedural ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. Pursuant to the December ruling and a subsequent procedural ruling, the parties met to confer, engaged a mediator and held confidential mediation discussions in June, July and August of 2017.

In August 2017, the parties filed status reports providing their recommendations for resolving the OII given their unsuccessful efforts at reaching a settlement through mediation. SDG&E and Edison recommended that the Amended Settlement Agreement, as adopted by the CPUC, should be affirmed and the pending intervenor petitions dismissed. Intervening parties recommended various alternative courses of action, including modifying the Amended Settlement Agreement or rejecting it in favor of litigation. In October 2017, the CPUC issued a ruling establishing a process to bring the proceeding to a conclusion. This ruling establishes a status conference and includes a preliminary schedule for additional testimony, hearings and briefings.

On January 30, 2018, SDG&E, Edison, ORA, TURN and other intervenors entered into a settlement agreement (Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify the Amended Settlement Agreement approved by the CPUC in November 2014. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. On February 1, 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. On February 6, 2018, the CPUC granted the parties’ motion to stay the proceedings and established a tentative procedural schedule with public participation hearings in April and July, evidentiary hearings in April and May, and briefing in June of 2018.

The Revised Settlement Agreement is subject to CPUC approval. The parties to the Revised Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. In the event that the CPUC fails to approve the Revised Settlement Agreement, the proceeding will remain open and subject to previous rulings in the SONGS OII, and the Amended Settlement Agreement will remain in effect, unless it is modified or set aside by the CPUC as a result of the OII proceeding.

In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement.

The timing of a ruling by the CPUC on the Joint Motion for Adoption of the Settlement Agreement is unclear. There is no assurance that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of the OII proceeding, which could result in a substantial reduction in our expected recovery or in payments to customers. These outcomes could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows.

Disallowances, Refunds and Recoveries

If the Revised Settlement Agreement is approved by the CPUC, SDG&E and Edison will cease rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of the date their combined remaining SONGS regulatory assets equal $775 million (the Cessation Date). Currently, the estimated Cessation Date is December 19, 2017. The Cessation Date is partly dependent on the outcome of Edison’s pending request to the CPUC, in a separate proceeding, for approval to apply certain proceeds received from the DOE to reduce Edison’s SONGS regulatory asset. If this request is rejected by the CPUC, then the estimated Cessation Date will be April 21, 2018. In either case, under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. SDG&E and Edison will refund to customers SONGS-related amounts recovered in rates after the Cessation Date.

In the event that the CPUC takes an action that has the effect of invalidating the Utility Shareholder Agreement, SDG&E may, in its discretion, withdraw from the Revised Settlement Agreement, in which case Edison shall remain a party to the Revised Settlement Agreement, but the Revised Settlement Agreement shall be terminated as to SDG&E. In such a scenario, SDG&E would return to its litigation position before the CPUC in the SONGS OII that existed prior to the Revised Settlement Agreement.

Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject, negotiating in good faith to seek a resolution acceptable to all parties. CPUC rules do not provide for any fixed time period for the CPUC to act on proposed settlements.

Utility Shareholder Agreement

On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that SDG&E will release Edison from any and all claims that SDG&E had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement becomes effective only upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commences 30 days after the first fiscal quarter in which the CPUC approves the Revised Settlement Agreement, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement.

Accounting and Financial Impacts

As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison totaling $152 million, $32 million classified as current and $120 million classified as noncurrent, as of December 31, 2017. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset, which SDG&E believes is now no longer probable of recovery.

Assuming the Revised Settlement Agreement is approved, SDG&E and Sempra Energy do not expect that implementation of the Revised Settlement Agreement in combination with the Utility Shareholder Agreement will have a material adverse impact on either company. However, until the CPUC approves the Revised Settlement Agreement as proposed, there can be no assurance that the SONGS OII proceeding will conclude as contemplated by SDG&E in accordance with the Revised Settlement Agreement and the Utility Shareholder Agreement, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement, or take other action that may be adverse to SDG&E and Sempra Energy. Such alternative outcomes could have a material adverse effect on SDG&E’s and Sempra Energy’s results of operations, financial condition and cash flows.

SETTLEMENT WITH NEIL

As we discuss below, NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E’s share of which was $80 million. Pursuant to the terms of the Amended Settlement Agreement, after reimbursement of legal fees and a 5-percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through the ERRA.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. In December 2016, Edison announced that, following a 10-month competitive bid process, it had contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years. SDG&E is responsible for approximately 20 percent of the total contract price.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.4 billion (in 2014 dollars), of which SDG&E’s share is $899 million. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. SDG&E has received authorization from the CPUC to access NDT funds of up to $362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 SONGS Units 2 and 3 costs as decommissioning costs are incurred.

In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized.

Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies⁽¹⁾	$	54	$	—	$	—		$	54
Municipal bonds⁽¹⁾	245		7		(2		)	250
Other securities⁽²⁾	215		3		(1		)	217
Total debt securities	514		10		(3		)	521
Equity securities	171		326		(1		)	496
Cash and cash equivalents	16		—		—			16
Total	$	701	$	336	$	(4	)	$	1,033
At December 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	$	52	$	—	$	—		$	52
Municipal bonds	203		4		(1		)	206
Other securities	141		2		(2		)	141
Total debt securities	396		6		(3		)	399
Equity securities	143		366		(1		)	508
Cash and cash equivalents	119		—		—			119
Total	$	658	$	372	$	(4	)	$	1,026


⁽¹⁾	Maturity dates are 2018-2048.


⁽²⁾	Maturity dates are 2018-2064.

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



SALES OF SECURITIES
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Proceeds from sales⁽¹⁾	$	1,314		$	1,134		$	577
Gross realized gains	157			111			29
Gross realized losses	(14		)	(29		)	(15		)


⁽¹⁾	Excludes securities that are held to maturity.

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification. In 2017 and 2016, sale and purchase activities in our NDT increased significantly compared to 2015 as a result of continuing changes to our asset allocations initiated in the fourth quarter of 2016 to reduce our equity volatility, lower our duration risk, and increase exposure to municipal bonds and intermediate credit. This shift in our asset mix is intended to reduce the overall risk profile of the NDT in anticipation of significant cash withdrawals over the next 10 years to fund the SONGS decommissioning.

ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL

SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $607 million at December 31, 2017. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The asset retirement obligation at December 31, 2017 for Unit 1 is based on a cost study prepared in 2016 that is pending CPUC approval. The asset retirement obligation at December 31, 2017 for Units 2 and 3 is based on a CPUC-approved cost study prepared in 2014 that reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. SDG&E’s share of total decommissioning costs in 2017 dollars is approximately $1 billion.

U.S. Department of Energy Nuclear Fuel Disposal

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel by 2019 and to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from 2006 through 2013. In May 2016, Edison refunded SDG&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS O&M cost balancing account.

In September 2016, Edison filed claims with the DOE for $56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers.

In October 2017, Edison filed claims with the DOE for $58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $12 million. It is unclear whether the claim will be resolved through settlement or arbitration, when resolution is expected, and whether Edison will receive an award for the full claim amount.

The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017.

NUCLEAR INSURANCE

Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement, as described below. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, which has not yet been obtained. We expect a decision in the first quarter of 2018.

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13 billion of SFP. If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG&E’s contribution would be up to $50.9 million. This amount is subject to an annual maximum of $7.6 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $450 million to $100 million and withdraw from participation in the SFP for SONGS.

The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $1.06 billion. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL, as we discuss above. Effective January 10, 2018, the NRC approved Edison’s request to reduce its property damage insurance requirement for SONGS from $1.06 billion to $50 million.

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

REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.



REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2017			2016
SDG&E:
Fixed-price contracts and other derivatives	$	96		$	141
Costs related to SONGS plant closure⁽¹⁾	—			183
Costs related to wildfire litigation	—			353
Deferred income taxes (refundable) recoverable in rates	(281		)	1,014
Pension and other postretirement benefit plan obligations	153			210
Removal obligations	(1,846		)	(1,725		)
Unamortized loss on reacquired debt	9			12
Environmental costs	29			48
Legacy meters⁽¹⁾	—			16
Sunrise Powerlink fire mitigation	119			118
Regulatory balancing accounts⁽²⁾
Commodity – electric	82			35
Gas transportation	22			61
Safety and reliability	48			20
Public purpose programs	(70		)	(106		)
Other balancing accounts	233			249
Other regulatory liabilities	(70		)	(2		)
Total SDG&E	(1,476		)	627
SoCalGas:
Pension and other postretirement benefit plan obligations	513			563
Employee benefit costs	45			45
Removal obligations	(924		)	(972		)
Deferred income taxes (refundable) recoverable in rates	(437		)	417
Unamortized loss on reacquired debt	8			10
Environmental costs	22			22
Workers’ compensation	12			10
Regulatory balancing accounts⁽²⁾
Commodity – gas, including transportation	151			207
Safety and reliability	266			230
Public purpose programs	(274		)	(270		)
Other balancing accounts	(114		)	(204		)
Other regulatory (liabilities) assets	(64		)	8
Total SoCalGas	(796		)	66
Sempra Mexico:
Deferred income taxes recoverable in rates	83			71
Total Sempra Energy Consolidated	$	(2,189	)	$	764


⁽¹⁾	Regulatory assets earning a rate of return.


⁽²⁾	At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively.

In the table above:

▪

Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. We discuss these fixed-price contracts and other derivatives further in Note 9.

▪

Regulatory assets arising from the SONGS plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline. Pursuant to the Revised Settlement Agreement, rate recovery of SONGS costs remaining as a regulatory asset as of the Cessation Date will cease. Under the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison in lieu of amounts SDG&E would have collected from ratepayers. We discuss these matters further in Note 13.

▪

Regulatory assets for CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties. In December 2017, the CPUC issued a final decision, denying SDG&E’s request to recover these costs. In 2017, SDG&E wrote off the wildfire regulatory asset resulting in a charge of $351 million, as we discuss in Note 15 in “SDG&E – 2007 Wildfire Litigation and Net Cost Recovery Status.”

▪

Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below. In 2017, as a result of the TCJA, lowering the U.S. statutory corporate federal income tax from 35 percent to 21 percent resulted in excess deferred income tax balances that we expect to refund to ratepayers in accordance with the IRS normalization rules and as determined by the CPUC and the FERC. We discuss the TCJA and the impacts on Sempra Energy, SDG&E and SoCalGas in more detail in Note 6.


▪	Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.


▪	The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.


▪	Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs.


▪	Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 10 years for SDG&E and from 3 years to 8 years for SoCalGas.


▪	Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 15.


▪	The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E has fully recovered this asset in rate base.


▪	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 52-year period. We discuss the trust further in Note 15.


▪	The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

▪

Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Absent balancing account treatment, variations in covered costs, such as the cost of fuel supply and certain O&M costs, from amounts approved by the CPUC would increase volatility in utility earnings. Balancing account treatment eliminates the volatility in earnings that would otherwise result from variances in the covered costs compared to the authorized amounts.

Amortization expense on regulatory assets for the years ended December 31, 2017, 2016 and 2015 was $50 million, $65 million and $62 million, respectively, at Sempra Energy Consolidated, $49 million, $63 million and $60 million, respectively, at SDG&E, and $1 million, $2 million and $2 million, respectively at SoCalGas.

CALIFORNIA UTILITIES MATTERS

CPUC General Rate Case

The CPUC uses a GRC proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of O&M and to provide the opportunity to realize their authorized rates of return on their investment.

2019 General Rate Case

On October 6, 2017, SDG&E and SoCalGas filed their 2019 GRC applications requesting CPUC approval of test year revenue requirements for 2019 and attrition year adjustments for 2020 through 2022. SDG&E and SoCalGas requested revenue requirements for 2019 of $2.199 billion and $2.989 billion, respectively, which is an increase of $217 million and $533 million over their respective 2018 revenue requirements (the 2018 revenue requirements reflect the impact of updated testimony filed in January 2018). The California Utilities are proposing post-test year revenue requirement changes using various adjustment factors which are estimated to result in annual increases of approximately 5 percent to 7 percent at SDG&E and approximately 6 percent to 8 percent at SoCalGas. Our 2019 GRC applications do not reflect the impact of the TCJA, which we discuss in Note 6. In April 2018, SDG&E and SoCalGas will be updating their applications to reflect the impact of the TCJA. We are assessing the impact of the new tax law on our 2018 operations and have a tax tracking mechanism for net tax benefits that will flow to ratepayers. We intend to work with the CPUC to determine the mechanism for passing on the savings to ratepayers.

As part of the 2019 GRC, the CPUC will review the California Utilities’ interim accountability reports, which compare the authorized and actual spending for certain safety-related activities for 2014 through 2016. In June 2017, SDG&E and SoCalGas filed their first interim accountability reports comparing authorized and actual spending in 2014 and 2015 for certain safety-related activities. Similar data for 2016 was provided with the 2019 GRC filings in a second interim accountability report. The stated purpose of the interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC.

The results of the rate case may materially and adversely differ from what is contained in the GRC applications.

Risk Assessment Mitigation Phase Reporting and Impact on the 2019 GRC Filings

In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities in California. The framework is intended to assist in assessing safety risks and the utilities’ plans to help ensure that such risks are adequately addressed. In advance of filing the California Utilities’ 2019 GRC applications discussed above, two proceedings occurred: the Safety Model Assessment Proceeding and the RAMP. In the Safety Model Assessment Proceeding, the California Utilities demonstrated the models used to prioritize and mitigate risks in order for the CPUC to establish guidelines and standards for these models.

In November 2016, as part of the new framework, SDG&E and SoCalGas filed their first RAMP report presenting a comprehensive assessment of their key safety risks and proposed activities for mitigating such risks. The report details these key safety risks, which include critical operational issues such as natural gas pipeline safety and wildfire safety, and addresses their classification, scoring, mitigation, alternatives, safety culture, quantitative analysis, data collection and lessons learned.

In March 2017, the CPUC’s Safety and Enforcement Division issued its evaluation report providing generally favorable feedback on the California Utilities’ RAMP report, but recommending more detailed analysis of the risks the California Utilities presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report. However, SDG&E and SoCalGas included funding requests in their respective 2019 GRC filings for proposed projects or activities outlined in their RAMP reports.

Senate Bill 549. In September 2017, SB 549 was signed into law, requiring that SDG&E and SoCalGas (as electric and gas corporations) annually notify the CPUC when revenue authorized by the CPUC for maintenance, safety or reliability is redirected to other purposes. This requirement is effective beginning January 1, 2018. The form of this reporting is not yet defined by the CPUC, though it could be incorporated into an ongoing proceeding or report otherwise required to be submitted to the CPUC.

2016 General Rate Case

In June 2016, the CPUC issued a final decision in the 2016 GRC. The 2016 GRC FD adopted a 2016 revenue requirement of $2.204 billion for SoCalGas and $1.791 billion for SDG&E. The 2016 GRC FD was effective retroactive to January 1, 2016, and the California Utilities recorded the retroactive impacts in the second quarter of 2016. The 2016 GRC FD also required certain refunds to be paid to customers and establishes a two-way income tax expense memorandum account, each discussed below.

The 2016 GRC FD also adopted subsequent annual escalation of the adopted revenue requirements by 3.5 percent for years 2017 and 2018 and continuation of the Z-Factor mechanism for qualifying cost recovery. The Z-Factor mechanism allows the California Utilities to seek cost recovery of significant cost increases, under certain unforeseen circumstances, incurred between GRC filings, subject to a $5 million deductible per event. Also, the 2016 GRC FD denied a separate request for a four-year GRC period and instead adopted a three-year GRC period (through 2018).

The 2016 GRC FD results in certain accounting impacts associated with flow-through income tax repairs deductions. In general, the 2016 GRC FD considers that the income tax benefits obtained from income tax repairs deductions exceeded amounts forecasted by the California Utilities from 2011 to 2015, and that they were attributed to shareholders during that time. The 2016 GRC FD reallocated the economic benefit of this tax deduction forecasting difference to ratepayers. Accordingly, revenues corresponding to income tax repair deductions that exceeded forecasted amounts relating to 2015, which were tracked in memorandum accounts, were ordered to be refunded to customers. The 2015 estimated amounts in the memorandum accounts totaled $72 million for SoCalGas and $37 million for SDG&E. Pursuant to this refund requirement, SoCalGas and SDG&E recorded regulatory liabilities for these amounts, resulting in after-tax charges to earnings of $43 million and $22 million, respectively, in the second quarter of 2016 (summarized below). In addition, the 2016 GRC FD reduced rate base by $38 million at SoCalGas and $55 million at SDG&E. The corresponding reductions in the 2016 revenue requirement were $5 million at SoCalGas and $7 million at SDG&E (which reductions are included in the adopted 2016 revenue requirement amounts described above). The rate base reductions reallocate to ratepayers the economic benefits associated with tax repair deductions that were previously provided to the shareholders for the period of 2012-2014 for SoCalGas and 2011-2014 for SDG&E. The rate base reductions did not result in an impairment of any of our reported assets, but have impacted our revenues and earnings prospectively.

The 2016 GRC FD also requires us to notify the CPUC if the 2012-2015 repairs deductions estimated in this GRC are different from the actual repairs deductions for SoCalGas and SDG&E. SoCalGas and SDG&E recorded regulatory liabilities of $11 million and $15 million, respectively, related to 2012-2014, resulting in after-tax charges to earnings for these differences of $6 million and $9 million in the second quarter of 2016 for SoCalGas and SDG&E, respectively (summarized below). In the third quarter of 2016, SoCalGas and SDG&E completed their 2015 calendar year tax returns, and final tax deductions associated with tax repair benefits to be refunded to ratepayers associated with the 2015 memo account were lower than the amounts estimated in 2015. Accordingly, the amounts to be refunded decreased by $19 million for SoCalGas and $5 million for SDG&E. In October 2016, SoCalGas and SDG&E filed a regulatory account update with the CPUC to reflect their final total 2015 repair allowance deductions of $53 million and $32 million, respectively. After recording the related income tax effect and corresponding regulatory revenue adjustments for income tax purposes, there was no net impact to earnings from the adjustments to the 2015 tax repairs deductions recorded in the third quarter of 2016. Accordingly, the earnings impacts in the table below are also the earnings impacts for the year ended December 31, 2016.

Following is a summary of the 2016 earnings impacts from the 2016 GRC FD:



EARNINGS IMPACTS IN 2016 FROM THE 2016 GRC FD
(Dollars in millions)
	SoCalGas						SDG&E
	Pretax earnings (charge)			After-tax earnings (charge)			Pretax earnings (charge)			After-tax earnings (charge)
Adjustments to revenue related to tax
repairs deductions:
2015 memorandum account balance	$	(72	)	$	(43	)	$	(37	)	$	(22	)
True-up of 2012-2014 estimates to actuals	(11		)	(6		)	(15		)	(9		)
Total	$	(83	)	$	(49	)	$	(52	)	$	(31	)

As discussed above, the 2016 GRC FD required the establishment of two-way income tax expense memorandum accounts to track any revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred by SoCalGas and SDG&E from 2016 through 2018. The variances to be tracked include tax expense differences relating to:


▪	net revenue changes;


▪	mandatory tax law, tax accounting, tax procedural, or tax policy changes; and


▪	elective tax law, tax accounting, tax procedural, or tax policy changes.

Starting in the second quarter of 2016, SoCalGas and SDG&E began tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense incurred. At December 31, 2017, the recorded regulatory liability associated with these tracked amounts totaled $69 million and $65 million for SoCalGas and SDG&E, respectively. The recorded liability is primarily related to lower income tax expense incurred than was forecasted in the GRC relating to tax repairs deductions, self-developed software deductions and certain book-over-tax depreciation. We are currently assessing the impact of federal tax reform on 2018 operations and will track such impacts in the tracking accounts. The tracking accounts will remain open, and we expect they will be reviewed in the 2019 GRC proceedings. Federal tax reform, which we discuss in Note 6, could result in significant amounts recorded in these tracking accounts beginning in 2018.

CPUC Cost of Capital

In July 2017, the CPUC issued a final decision adopting, with certain modifications, the joint petition filed in February 2017 by SDG&E, SoCalGas, PG&E and Edison, along with ORA and TURN. The final decision provides a two-year extension for each of the utilities to file its next respective cost of capital application, extending the filing date to April 2019 for a 2020 test year. The final decision also reduces the ROE for SDG&E from 10.30 percent to 10.20 percent and for SoCalGas from 10.10 percent to 10.05 percent, effective from January 1, 2018 through December 31, 2019. SDG&E’s and SoCalGas’ ratemaking capital structures will remain at current levels until modified, if at all, by a future cost of capital decision by the CPUC. In September 2017, SDG&E and SoCalGas filed advice letters to update their cost of capital for the actual cost of long-term debt through August 2017 and forecasted cost through 2018. SDG&E and SoCalGas did not file for changes to preferred stock costs, because no issuances of preferred stock through 2018 are anticipated.

In October 2017, the CPUC approved the embedded cost of debt presented in the filed advice letters, resulting in a revised return on rate base for SDG&E from 7.79 percent to 7.55 percent and for SoCalGas from 8.02 percent to 7.34 percent, effective January 1, 2018, as depicted in the table below:



AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC

SDG&E							SoCalGas
Authorized weighting		Return on rate base		Weighted return on rate base			Authorized weighting		Return on rate base		Weighted return on rate base
45.25	%	4.59	%	2.08	%	Long-Term Debt	45.60	%	4.33	%	1.97	%
2.75		6.22		0.17		Preferred Stock	2.40		6.00		0.14
52.00		10.20		5.30		Common Equity	52.00		10.05		5.23
100.00	%			7.55	%		100.00	%			7.34	%

As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below:



IMPACT OF THE EMBEDDED COST OF DEBT

	SDG&E						SoCalGas
	Cost of debt			Return on rate base			Cost of debt			Return on rate base
Current	5.00		%	7.79		%	5.77		%	8.02		%
Authorized, effective January 1, 2018	4.59		%	7.55		%	4.33		%	7.34		%
Differences	(41	)	bps	(24	)	bps	(144	)	bps	(68	)	bps

The automatic CCM will be in effect to adjust 2019 cost of capital, if necessary. Unless changed by the operation of the CCM, the updated costs of long-term debt and the new ROEs will remain in effect through December 31, 2019. The cost of capital changes will also apply to capital expenditures in 2018 and 2019 for incremental projects not funded through the GRC revenue requirement.

SDG&E MATTERS

FERC Rate Matters and Cost of Capital

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.

SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows:



SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC

	Weighting		Return on rate base		Weighted return on rate base
Long-Term Debt	43.44	%	4.21	%	1.83	%
Common Equity	56.56		10.05		5.68
	100.00	%			7.51	%

SDG&E expects to file its TO5 formula rate request with the FERC by June 2018, to be effective January 1, 2019.

REGULATORY MATTERS

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Regulatory Matters

SAN ONOFRE NUCLEAR GENERATING STATION

SONGS STEAM GENERATOR REPLACEMENT PROJECT

SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE


▪	SDG&E’s weighted-average return on debt, plus


▪	50 percent of SDG&E’s weighted-average return on preferred stock, as authorized in the CPUC’s cost of capital (discussed in Note 14) proceeding then in effect (collectively, SONGS return on rate base)

Disallowances, Refunds and Recoveries

Utility Shareholder Agreement

Accounting and Financial Impacts

SETTLEMENT WITH NEIL

NUCLEAR DECOMMISSIONING AND FUNDING

Nuclear Decommissioning Trusts

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies⁽¹⁾	$	54	$	—	$	—		$	54
Municipal bonds⁽¹⁾	245		7		(2		)	250
Other securities⁽²⁾	215		3		(1		)	217
Total debt securities	514		10		(3		)	521
Equity securities	171		326		(1		)	496
Cash and cash equivalents	16		—		—			16
Total	$	701	$	336	$	(4	)	$	1,033
At December 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	$	52	$	—	$	—		$	52
Municipal bonds	203		4		(1		)	206
Other securities	141		2		(2		)	141
Total debt securities	396		6		(3		)	399
Equity securities	143		366		(1		)	508
Cash and cash equivalents	119		—		—			119
Total	$	658	$	372	$	(4	)	$	1,026


⁽¹⁾	Maturity dates are 2018-2048.


⁽²⁾	Maturity dates are 2018-2064.

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



SALES OF SECURITIES
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Proceeds from sales⁽¹⁾	$	1,314		$	1,134		$	577
Gross realized gains	157			111			29
Gross realized losses	(14		)	(29		)	(15		)


⁽¹⁾	Excludes securities that are held to maturity.

ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL

U.S. Department of Energy Nuclear Fuel Disposal

NUCLEAR INSURANCE

REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.



REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2017			2016
SDG&E:
Fixed-price contracts and other derivatives	$	96		$	141
Costs related to SONGS plant closure⁽¹⁾	—			183
Costs related to wildfire litigation	—			353
Deferred income taxes (refundable) recoverable in rates	(281		)	1,014
Pension and other postretirement benefit plan obligations	153			210
Removal obligations	(1,846		)	(1,725		)
Unamortized loss on reacquired debt	9			12
Environmental costs	29			48
Legacy meters⁽¹⁾	—			16
Sunrise Powerlink fire mitigation	119			118
Regulatory balancing accounts⁽²⁾
Commodity – electric	82			35
Gas transportation	22			61
Safety and reliability	48			20
Public purpose programs	(70		)	(106		)
Other balancing accounts	233			249
Other regulatory liabilities	(70		)	(2		)
Total SDG&E	(1,476		)	627
SoCalGas:
Pension and other postretirement benefit plan obligations	513			563
Employee benefit costs	45			45
Removal obligations	(924		)	(972		)
Deferred income taxes (refundable) recoverable in rates	(437		)	417
Unamortized loss on reacquired debt	8			10
Environmental costs	22			22
Workers’ compensation	12			10
Regulatory balancing accounts⁽²⁾
Commodity – gas, including transportation	151			207
Safety and reliability	266			230
Public purpose programs	(274		)	(270		)
Other balancing accounts	(114		)	(204		)
Other regulatory (liabilities) assets	(64		)	8
Total SoCalGas	(796		)	66
Sempra Mexico:
Deferred income taxes recoverable in rates	83			71
Total Sempra Energy Consolidated	$	(2,189	)	$	764


⁽¹⁾	Regulatory assets earning a rate of return.


⁽²⁾	At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively.

In the table above:

▪


▪	Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.


▪	The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.


▪	Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs.


▪	Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 10 years for SDG&E and from 3 years to 8 years for SoCalGas.


▪	Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 15.


▪	The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E has fully recovered this asset in rate base.


▪	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 52-year period. We discuss the trust further in Note 15.


▪	The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

▪

CALIFORNIA UTILITIES MATTERS

CPUC General Rate Case

2019 General Rate Case

The results of the rate case may materially and adversely differ from what is contained in the GRC applications.

Risk Assessment Mitigation Phase Reporting and Impact on the 2019 GRC Filings

2016 General Rate Case

Following is a summary of the 2016 earnings impacts from the 2016 GRC FD:



EARNINGS IMPACTS IN 2016 FROM THE 2016 GRC FD
(Dollars in millions)
	SoCalGas						SDG&E
	Pretax earnings (charge)			After-tax earnings (charge)			Pretax earnings (charge)			After-tax earnings (charge)
Adjustments to revenue related to tax
repairs deductions:
2015 memorandum account balance	$	(72	)	$	(43	)	$	(37	)	$	(22	)
True-up of 2012-2014 estimates to actuals	(11		)	(6		)	(15		)	(9		)
Total	$	(83	)	$	(49	)	$	(52	)	$	(31	)


▪	net revenue changes;


▪	mandatory tax law, tax accounting, tax procedural, or tax policy changes; and


▪	elective tax law, tax accounting, tax procedural, or tax policy changes.

CPUC Cost of Capital



AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC

SDG&E							SoCalGas
Authorized weighting		Return on rate base		Weighted return on rate base			Authorized weighting		Return on rate base		Weighted return on rate base
45.25	%	4.59	%	2.08	%	Long-Term Debt	45.60	%	4.33	%	1.97	%
2.75		6.22		0.17		Preferred Stock	2.40		6.00		0.14
52.00		10.20		5.30		Common Equity	52.00		10.05		5.23
100.00	%			7.55	%		100.00	%			7.34	%

As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below:



IMPACT OF THE EMBEDDED COST OF DEBT

	SDG&E						SoCalGas
	Cost of debt			Return on rate base			Cost of debt			Return on rate base
Current	5.00		%	7.79		%	5.77		%	8.02		%
Authorized, effective January 1, 2018	4.59		%	7.55		%	4.33		%	7.34		%
Differences	(41	)	bps	(24	)	bps	(144	)	bps	(68	)	bps

SDG&E MATTERS

FERC Rate Matters and Cost of Capital

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.

SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows:



SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC

	Weighting		Return on rate base		Weighted return on rate base
Long-Term Debt	43.44	%	4.21	%	1.83	%
Common Equity	56.56		10.05		5.68
	100.00	%			7.51	%

SDG&E expects to file its TO5 formula rate request with the FERC by June 2018, to be effective January 1, 2019.

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies

NOTE 15. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

At December 31, 2017, loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $92 million for Sempra Energy Consolidated, including $3 million for SDG&E and $88 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $83 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below. We discuss our policy regarding accrual of legal fees in Note 1.

SDG&E

2007 Wildfire Litigation and Net Cost Recovery Status

SDG&E has resolved all litigation associated with three wildfires that occurred in October 2007, except one appeal that remains pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E maintains reserves for the wildfire litigation and adjusts these reserves as information becomes available and amounts are estimable.

SDG&E recorded regulatory assets for CPUC-related costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. In September 2015, SDG&E filed an application with the CPUC seeking authority to recover these CPUC-related costs in rates over a six- to ten-year period. The requested amount was the net estimated CPUC-related cost incurred by SDG&E after deductions for insurance reimbursement and third-party settlement recoveries, and reflected a voluntary 10-percent shareholder contribution applied to the net regulatory asset for wildfire costs. In August 2017, the CPUC issued a proposed decision denying SDG&E’s request to recover the 2007 wildfire costs submitted in our application. In consideration of the proposed decision (including the actions not taken through the October 26, 2017 CPUC meeting), we concluded that the wildfire regulatory asset no longer met the probability threshold for recovery required by U.S. GAAP. Accordingly, SDG&E wrote off the wildfire regulatory asset, resulting in a charge of $351 million ($208 million after-tax) in the third quarter of 2017, in Write-off of Wildfire Regulatory Asset on the Consolidated Statements of Operations for Sempra Energy and SDG&E. In December 2017, the CPUC issued a final decision upholding the proposed decision. SDG&E will continue to vigorously pursue recovery of these costs, which were incurred through settling claims brought under the doctrine of inverse condemnation. SDG&E applied to the CPUC for rehearing of its decision on January 2, 2018. The CPUC may grant a rehearing, modify its decision, or deny the request and affirm its original decision. We will appeal the decision with the California Courts of Appeal seeking to reverse the CPUC’s decision, if necessary.

Concluded Matter

SDG&E participated as a claimant and respondent in an arbitration proceeding initiated by Edison in October 2013 against MHI seeking damages stemming from the failure of the MHI replacement steam generators at the SONGS nuclear power plant. In March 2017, the Tribunal found MHI liable for breach of contract, subject to a contractual limitation of liability, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. We discuss this arbitration and decision further in Note 13.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

On October 23, 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak), located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is one of more than 100 injection-and-withdrawal wells at the storage facility. SoCalGas worked closely with several of the world’s leading experts to stop the Leak, and on February 18, 2016, DOGGR confirmed that the well was permanently sealed. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon natural gas storage facility as a result of the Leak.

Local Community Mitigation Efforts. Pursuant to a stipulation and order by the LA Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. Following the permanent sealing of the well, the DPH conducted testing in certain homes in the Porter Ranch community, and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home. In May 2016, the LA Superior Court ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016.

In May 2016, the DPH also issued a directive that SoCalGas additionally professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five-mile radius of the Aliso Canyon natural gas storage facility and experienced symptoms from the Leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.

The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. To the extent any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. At December 31, 2017, SoCalGas estimates that its costs related to the Leak are $913 million, which includes $887 million of costs recovered or probable of recovery from insurance. Of the $913 million of costs, approximately 60 percent is for the temporary relocation program (including cleaning costs and certain labor costs). Other estimated costs include amounts for efforts to control the well, stop the Leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to investigate the cause of the Leak. The remaining portion of the $913 million includes legal costs incurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, the estimated costs to settle certain actions and other costs. The value of lost gas reflects the replacement cost of volumes purchased through December 2017 and estimates for purchases in 2018. As of mid-January 2018, SoCalGas has replaced all lost gas. SoCalGas adjusts its estimated total liability associated with the Leak as additional information becomes available. The $913 million represents management’s best estimate of these costs related to the Leak. Of these costs, a substantial portion has been paid and $84 million is accrued as Reserve for Aliso Canyon Costs as of December 31, 2017 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets for amounts expected to be paid after December 31, 2017.

As of December 31, 2017, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the Leak of $418 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. This amount is net of insurance retentions and $469 million of insurance proceeds we received through December 31, 2017 related to control-of-well expenses, lost gas and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

As described in “Governmental Investigations and Civil and Criminal Litigation” below, the actions against us seek compensatory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the above amounts as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs that may be imposed. The recorded amounts above also do not include the costs to clean additional homes pursuant to the Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate of $913 million does not include certain other costs expensed by Sempra Energy through December 31, 2017 associated with defending shareholder derivative lawsuits.

In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account may be refunded to ratepayers.

Insurance. Excluding directors’ and officers’ liability insurance, we have four kinds of insurance policies that together provide between $1.2 billion to $1.4 billion in insurance coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the Leak. Subject to various policy limits, exclusions and conditions, based on what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the Leak and stop or reduce emissions, the root cause analysis being conducted to investigate the cause of the Leak, the value of lost natural gas, costs incurred to mitigate the actual natural gas released, costs associated with litigation and claims by nearby residents and businesses, any costs to clean additional homes pursuant to the Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we have received insurance payments for portions of control-of-well expenses, lost gas and temporary relocation costs. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining additional insurance recovery for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

At December 31, 2017, SoCalGas’ estimated costs related to the Leak of $913 million include $887 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Any costs not included in the $913 million cost estimate could be material. To the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including DOGGR, DPH, SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, CPUC, PHMSA, EPA, Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. Other federal agencies (e.g., the DOE and the U.S. Department of the Interior) investigated the incident as part of a joint interagency task force. In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The timing of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC.

As of February 22, 2018, 373 lawsuits, including over 45,000 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. All of these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action discussed below, are coordinated before a single court in the LA Superior Court for pretrial management (the Coordination Proceeding).

Pursuant to the Coordination Proceeding, in March 2017, the individuals and business entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees.

In January 2017, pursuant to the Coordination Proceeding, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, one on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In December 2017, the California Court of Appeal, Second Appellate District ruled that the purely economic damages alleged in the Business Class Action are not recoverable under the law.

In addition to the lawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and certain of its directors in the SDCA. Five shareholder derivative actions are also pending in the Coordination Proceeding alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017.

Three actions filed by public entities are pending in the Coordination Proceeding. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the LA Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and damages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the DPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the Leak, as well as punitive damages and attorneys’ fees.

Second, in August 2016, the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney, filed a third amended complaint on behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Unfair Competition Law, violations of California Health and Safety Code sections 41700 (prohibiting discharge of air contaminants that cause annoyance to the public) and 25510 (requiring reporting of the release of hazardous material), as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties.

Third, a petition for writ of mandate filed by the County of Los Angeles is pending against DOGGR and its State Oil and Gas Supervisor and the CPUC and its Executive Director, as to which SoCalGas is the real party in interest. The petition alleges that in issuing its July 2017 determination that the requirements for the resumption of injection operations were met (discussed under “Natural Gas Storage Operations and Reliability” below), DOGGR failed to comply with the provisions of SB 380, which requires a comprehensive safety review of the Aliso Canyon natural gas storage facility before injection of natural gas may resume. The County alleges, among other things, that DOGGR failed to comply with the provisions of SB 380 in declaring the safety review complete and authorizing the resumption of injection of natural gas into the facility before the root cause analysis was complete, failing to make its safety-review documents available to the public and failing to address seismic risks to the field as part of its safety review. The County further alleges that CEQA required DOGGR to prepare an EIR before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, and to produce records in response to the County’s Public Records Act request as well as declaratory and injunctive relief against any authorization to inject natural gas and attorneys’ fees.

A complaint filed by the SCAQMD against SoCalGas seeking civil penalties for alleged violations of several nuisance related statutory provisions arising from the Leak and delays in stopping the Leak was settled in February 2017, pursuant to which SoCalGas paid $8.5 million, of which $1 million is to be used to pay for a health study. The SCAQMD’s complaint was dismissed in February 2017.

Separately, in February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the Leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. Pursuant to a settlement agreement with the Los Angeles County District Attorney’s Office, SoCalGas agreed to plead no contest to the notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $75,000, penalty assessments of approximately $233,500, and operational commitments estimated to cost approximately $5 million, reimbursement and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Certain individuals residing near the Aliso Canyon natural gas storage facility who objected to the settlement have filed a notice of appeal of the judgment, contending they should be granted restitution.

The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Regulatory Proceedings. In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region. The CPUC indicated it intends to conduct the proceeding in two phases, with Phase 1 undertaking a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 using those analyses and scenarios to evaluate the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility. The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The CPUC adopted a high-level Phase 1 schedule contemplating public participation hearings and workshops beginning in April 2017, but no hearings until Phase 2.

Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas does not believe the Aliso Canyon natural gas storage facility or any portion of the facility was out of service (as that term is meant in Section 455.5) for nine consecutive months, SoCalGas provided notification out of an abundance of caution to demonstrate its commitment to regulatory compliance and transparency, and because obtaining authorization to resume injection operations at the facility required more time than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of the facility was out of service for nine consecutive months under section 455.5, and if so, whether the CPUC should disallow costs for such period from SoCalGas’ rates. Under section 455.5, hearings on the investigation are to be held, if necessary, in conjunction with SoCalGas’ 2019 GRC proceeding. If the CPUC determines that all or any portion of the facility was out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders and Additional Regulation. In January 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency in Los Angeles County due to the Leak. The Governor’s Order imposes various orders with respect to: stopping the Leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (2) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response while protecting ratepayers, and CARB must develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (3) DOGGR, CPUC, CARB and the CEC must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.

In December 2015, SoCalGas made a commitment to mitigate the actual natural gas released from the Leak and has been working on a plan to accomplish the mitigation. In March 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program, which set forth its recommended approach to achieve full mitigation of the emissions from the Leak. The CARB program requires that reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to the amount of the emissions from the Leak, and that the amount of reductions required be derived using the global warming potential based on a 20-year term (rather than the 100-year term the CARB and other state and federal agencies use in regulating emissions), resulting in a target of approximately 9,000,000 metric tons of carbon dioxide equivalent. CARB’s program also calls for all of the mitigation to occur in California over the next five to ten years without the use of allowances or offsets. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the greenhouse gas impacts of the Leak. We have not agreed with CARB’s estimate of methane released and continue to work with CARB on developing a mitigation plan.

Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 25, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and in accordance with SB 380, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility. In April and June of 2017, SoCalGas advised the CAISO, CEC, CPUC and PHMSA of its concerns that the inability to inject natural gas into the Aliso Canyon natural gas storage facility posed a risk to energy reliability in Southern California. Limited withdrawals of natural gas from the Aliso Canyon natural gas storage facility were made in 2017 to augment natural gas supplies during critical demand periods.

On July 19, 2017, DOGGR issued its determination that SoCalGas had met the requirements of SB 380 for the resumption of injection operations, including all safety requirements. On the same date, the CPUC’s Executive Director issued his concurrence with that determination, and DOGGR issued its Order to: Test and Take Temporary Actions Upon Resuming Injection: Aliso Canyon Gas Storage Facility lifting the prohibition on injection at the Aliso Canyon natural gas storage facility, subject to certain requirements after injection resumed, including limitations on the rate at which SoCalGas may withdraw natural gas from the field. The CPUC additionally issued a directive to SoCalGas to maintain a range of working gas in the Aliso Canyon natural gas storage facility at a target of 23.6 Bcf (approximately 28 percent of its maximum capacity), and at all times above 14.8 Bcf, later amended to require the range be maintained from zero Bcf to 24.6 Bcf of working gas. The County of Los Angeles filed a petition for writ of mandate seeking declaratory and injunctive relief and a stay of DOGGR’s order lifting the prohibition against injecting natural gas at the facility. We provide further detail regarding the County of Los Angeles’ suit above in “Governmental Investigations and Civil and Criminal Litigation.” Having completed the steps outlined by state agencies to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections.

If the Aliso Canyon natural gas storage facility were determined to have been out of service for any meaningful period of time or permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2017, the Aliso Canyon natural gas storage facility has a net book value of $644 million, including $252 million of construction work in progress for the project to construct a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Sempra Mexico

Property Disputes and Permit Challenges

Energía Costa Azul. Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its ECA LNG terminal near Ensenada, Mexico. A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of the SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. Both challenges are pending to be resolved by a Federal Court in Mexico. Sempra Mexico expects additional proceedings regarding the claims.

Several administrative challenges are pending in Mexico before the Mexican environmental protection agency and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization issued to ECA in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.

Two real property cases have been filed against ECA. In one case, filed in the federal Agrarian Court in 2006, the plaintiffs seek to annul the recorded property title for a parcel on which the ECA LNG terminal is situated and to obtain possession of a different parcel that allegedly sits in the same place. A second complaint was served in April 2012 seeking to invalidate the contract by which ECA purchased another of the terminal parcels, on the grounds the purchase price was unfair; the plaintiff filed a second complaint in 2013 in the federal Agrarian Court seeking an order that SEDATU issue title to her. In January 2016, the federal Agrarian Court ruled against the plaintiff, and the plaintiff appealed the ruling. Sempra Mexico expects further proceedings on these two matters.

Guaymas-El Oro Segment of the Sonora Pipeline. IEnova’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment, and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of the Sonora natural gas pipeline that crosses its territory. Representatives of the Bácum community filed a legal challenge in Mexican Federal Court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. The judge granted a suspension order that prohibited the construction of such segment through the Bácum community territory. Because the pipeline does not pass through the Bácum community, IEnova did not believe the order prohibited construction in the remainder of the Yaqui territory. As a result of the dispute, however, IEnova was delayed in the construction of the approximately 14 kilometers of pipeline that pass through territory of the Yaqui tribe. The CFE agreed to extend the deadline for commercial operations until the second quarter of 2017. Construction of the Guaymas-El Oro segment was completed, and commercial operations began in May 2017. Following the start of commercial operations, an appellate court ruled that the scope of the suspension encompassed the wider Yaqui territory. The legal challenge remains pending. IEnova has subsequently reported damage and declared a force majeure event for the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has interrupted its operations since August 23, 2017. There is no material economic impact as of December 31, 2017. The Sasabe-Puerto Libertad-Guaymas segment remains in full operation.

Concluded Matters

Energía Costa Azul. A property claimant 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 ECA LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions. In September 2015, the Court granted Sempra Energy’s motion for summary judgment and closed the case. The claimant appealed the summary judgment and an earlier order dismissing certain of his causes of action. In July 2017, the Ninth Circuit Court of Appeal issued a ruling affirming the summary judgment and dismissal of his other causes of action, except one alleging theft of personal property in connection with the alleged eviction. In September 2017, the District Court dismissed the remaining claim.

Energía Sierra Juárez. In December 2012, Backcountry Against Dumps, Donna Tisdale and the Protect Our Communities Foundation filed a complaint in the SDCA seeking to invalidate the presidential permit issued by the DOE for Energía Sierra Juárez’s cross-border generation tie line connecting the Energía Sierra Juárez wind project in Mexico to the electric grid in the U.S. The suit alleged violations of the NEPA, the Endangered Species Act, the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. Plaintiffs filed a motion for summary judgment, which the court largely denied in September 2015. One NEPA claim, however, was not resolved – whether the Environmental Impact Statement’s assessment of alleged extraterritorial impacts of the generation tie line in the U.S. on the environment in Mexico was inadequate (the “extraterritorial impact issue”) – and was the subject of additional briefing in 2016. On January 30, 2017, the Court issued a ruling on the extraterritorial impact issue and, contrary to its prior ruling, ruled that the Environmental Impact Statement was deficient for not considering the effects in Mexico of both the U.S. and Mexican portion of the generation tie line and the wind farm itself. On August 29, 2017, the Court denied the plaintiffs request to vacate the presidential permit or enjoin operation of the generation tie line and remanded the case to the DOE for preparation of a supplemental Environmental Impact Statement that addresses the deficiencies identified by the Court, and entered judgment ending the case.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. RBS, our partner in the joint venture, paid an £86 million assessment in October 2014 to HMRC for denied VAT refund claims filed in connection with the purchase of carbon credit allowances by RBS SEE, a subsidiary of RBS Sempra Commodities. RBS SEE has since been sold to JP Morgan and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. After paying the assessment, RBS filed a Notice of Appeal of the assessment with the First-Tier Tribunal. The First-Tier Tribunal held a preliminary hearing in September 2016 to determine whether HMRC’s assessment was time-barred. In January 2017, the First-Tier Tribunal issued a decision in favor of HMRC concluding that the assessment was not time-barred. RBS has decided not to appeal the First-Tier Tribunal’s decision to the Upper Tribunal. There will be a hearing on the substantive matter regarding whether RBS knew or should have known that certain vendors in the trading chain did not remit their VAT to HMRC.

During 2015, liquidators, acting on behalf of ten companies (the Companies) that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly, filed a claim in the High Court of Justice asserting damages of £160 million against RBS and Mercuria Energy Europe Trading Limited (the Defendants). The claim alleges that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay. The £160 million is comprised of a claim by the Companies for £80 million for equitable compensation due to dishonest assistance, and a claim by the liquidators for compensation in the same amount under the Insolvency Act of 1986. The parties have agreed that to the extent the Companies’ claims are successful, the liquidators cannot collect under the Insolvency Act of 1986; however, the award amount is ultimately determined by the Court. Trial of the matter has been set for the summer of 2018. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from us and RBS.

Our remaining investment in RBS Sempra Commodities of $67 million at December 31, 2017 is accounted for under the equity method and reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters. We discuss RBS Sempra Commodities further in Note 4.

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

CONTRACTUAL COMMITMENTS

Natural Gas Contracts

SoCalGas has the responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio. Purchases are from various producing regions in the southwestern U.S., U.S. Rockies, and Canada and are primarily based on published monthly bid-week indices.

SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2031.

Sempra LNG & Midstream’s and Sempra Mexico’s businesses have various capacity agreements for natural gas storage and transportation. In addition, Sempra Mexico has a natural gas purchase agreement to fuel a natural gas-fired power plant.

In May 2016, Sempra LNG & Midstream permanently released certain pipeline capacity that it held with Rockies Express and others. The effect of the permanent capacity releases resulted in a pretax charge of $206 million ($123 million after-tax), which is included in Other Cost of Sales on the Sempra Energy Consolidated Statement of Operations. The charge represented an acceleration of costs that would otherwise have been recognized over the duration of the contracts. Sempra LNG & Midstream has recorded a liability for these costs, less expected proceeds generated from the permanent capacity releases. Sempra LNG & Midstream’s related obligation to make future capacity payments through November 2019 is included in the table below.

In May 2017, Sempra LNG & Midstream received settlement proceeds of $57 million from a breach of contract claim against a counterparty in bankruptcy court. Of the total proceeds, $47 million related to the $206 million charge we recorded in 2016 resulting from the permanent release of certain pipeline capacity. Sempra LNG & Midstream recorded the settlement proceeds as a reduction to Other Cost of Sales on Sempra Energy’s Consolidated Statement of Operations in 2017.

At December 31, 2017, the future estimated payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:



FUTURE ESTIMATED PAYMENTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Storage and transportation		Natural gas⁽¹⁾		Total⁽¹⁾
2018	$	231	$	61	$	292
2019	146		—		146
2020	48		—		48
2021	46		1		47
2022	44		1		45
Thereafter	127		—		127
Total estimated payments	$	642	$	63	$	705


⁽¹⁾	Excludes amounts related to the LNG purchase agreement discussed below.



FUTURE ESTIMATED PAYMENTS – SOCALGAS
(Dollars in millions)
	Transportation		Natural gas		Total
2018	$	108	$	—	$	108
2019	59		—		59
2020	29		—		29
2021	27		1		28
2022	27		1		28
Thereafter	81		—		81
Total estimated payments	$	331	$	2	$	333

Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra Energy Consolidated and SoCalGas were as follows:



PAYMENTS UNDER NATURAL GAS CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,429	$	1,169	$	1,200
SoCalGas	1,213		966		975

LNG Purchase Agreement

Sempra LNG & Midstream has a purchase agreement for the supply of LNG to the ECA terminal. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2018 to 2029. Although this agreement specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra LNG & Midstream.

At December 31, 2017, the following LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered:



LNG COMMITMENT AMOUNTS
(Dollars in millions)
2018	$	302
2019	383
2020	391
2021	403
2022	411
Thereafter	2,935
Total	$	4,825

Actual LNG purchases in 2017, 2016 and 2015 have been significantly lower than the maximum amount provided under the agreement due to the customer electing to divert most cargoes as allowed by the agreement.

Purchased-Power Contracts

For 2018, SDG&E expects to meet its customer power requirements from the following resource types:


▪	Long-term contracts: 43 percent (of which 37 percent is provided by renewable energy contracts expiring on various dates through 2041)


▪	Other SDG&E-owned generation and tolling contracts (including OMEC): 56 percent


▪	Spot market purchases: 1 percent

Chilquinta Energía and Luz del Sur also have purchased-power contracts, expiring on various dates extending through 2031, which cover most of the consumption needs of the companies’ customers. These commitments are included under Sempra Energy Consolidated in the table below.

At December 31, 2017, the future estimated payments under long-term purchased-power contracts are as follows:



FUTURE ESTIMATED PAYMENTS – PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E
2018	$	702	$	577
2019	690		571
2020	631		510
2021	633		510
2022	598		496
Thereafter	5,726		5,457
Total estimated payments⁽¹⁾⁽²⁾	$	8,980	$	8,121


⁽¹⁾	Excludes purchase agreements accounted for as capital leases and amounts related to Otay Mesa VIE, as it is consolidated by Sempra Energy and SDG&E.


⁽²⁾	Includes $5.4 billion of expected payments under purchase agreements accounted for as operating leases at SDG&E, comprising renewable energy PPAs for which there are no future minimum operating lease payments.

Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E and Luz del Sur are required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments under purchased-power contracts were as follows:



PAYMENTS UNDER PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,694	$	1,667	$	1,573
SDG&E	781		752		715

Operating Leases

Sempra Energy Consolidated, SDG&E and SoCalGas have operating leases on real and personal property expiring at various dates from 2018 through 2054. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from two percent to five percent at Sempra Energy Consolidated, SDG&E and SoCalGas. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year, and most leases contain extension options that we could exercise.

The California Utilities have operating lease agreements for future acquisitions of fleet vehicles with an aggregate maximum lease limit of $250 million, $133 million of which has been utilized as of December 31, 2017.

Rent expense for operating leases was as follows:



RENT EXPENSE – OPERATING LEASES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	109	$	77	$	78
SDG&E	28		28		27
SoCalGas	43		38		39

At December 31, 2017, the rental commitments payable in future years under all noncancelable operating leases, including estimated payments, are as follows:



FUTURE RENTAL PAYMENTS – OPERATING LEASES
(Dollars in millions)
	2018		2019		2020		2021		2022		Thereafter		Total
Sempra Energy Consolidated:
Future minimum lease payments	$	85	$	57	$	51	$	48	$	42	$	300	$	583
Future estimated rental payments	13		12		12		12		13		46		108
Total future rental commitments	$	98	$	69	$	63	$	60	$	55	$	346	$	691
SDG&E:
Future minimum lease payments	$	22	$	21	$	20	$	19	$	18	$	54	$	154
Future estimated rental payments	2		2		2		2		2		3		13
Total future rental commitments	$	24	$	23	$	22	$	21	$	20	$	57	$	167
SoCalGas:
Future minimum lease payments	$	29	$	25	$	20	$	19	$	13	$	36	$	142
Future estimated rental payments	11		10		10		10		11		43		95
Total future rental commitments	$	40	$	35	$	30	$	29	$	24	$	79	$	237

Capital Leases

Power Purchase Agreements

SDG&E has five PPAs with peaker plant facilities, one of which went into commercial operation in June 2017. All five are accounted for as capital leases, four with a 25-year term and one with a 9-year term. At December 31, 2017, the aggregate carrying value of these capital lease obligations is $731 million.

In 2017, SDG&E satisfied all of the conditions precedent for a CPUC-approved 20-year PPA with a 500-MW power plant facility that is under construction. Beginning with the initial delivery of the contracted power, scheduled in June 2018, the PPA will be accounted for as a capital lease.

The entities that own the peaker plant facilities are VIEs of which SDG&E is not the primary beneficiary. SDG&E does not have any additional implicit or explicit financial responsibility related to these VIEs.

At December 31, 2017, the future minimum lease payments and present value of the net minimum lease payments under these capital leases for both Sempra Energy Consolidated and SDG&E are as follows:



FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENTS
(Dollars in millions)
2018	$	192
2019	210
2020	210
2021	210
2022	210
Thereafter	3,299
Total minimum lease payments⁽¹⁾	4,331
Less: estimated executory costs	(502		)
Less: interest⁽²⁾	(2,548		)
Present value of net minimum lease payments⁽³⁾	$	1,281


⁽¹⁾	This amount will be recorded over the lives of the leases as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.


⁽²⁾	Amount necessary to reduce net minimum lease payments to present value at the inception of the leases.

⁽³⁾

Includes $13 million in Current Portion of Long-Term Debt and $718 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2017. The remaining present value of net minimum lease payments of $550 million will be recorded as a capital lease obligation when construction of the power plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2018.

The annual amortization charge for the PPAs was $8 million in 2017 and $4 million in each of 2016 and 2015.

Headquarters Build-to-Suit Lease

Sempra Energy has a 25-year, build-to-suit lease for its San Diego, California, headquarters completed in 2015. We began occupying the building in the second half of 2015, concurrent with the termination of the prior headquarters lease. As a result of our involvement during and after the construction period, we have recorded the related assets and financing liability for construction costs incurred under this build-to-suit leasing arrangement.

The building is being depreciated on a straight-line basis over its estimated useful life and the associated lease payments are allocated between interest expense and amortization of the financing obligation over the lease period. Further, a portion of the lease payments pertain to the lease of the underlying land and are recorded as rental expense. The balance of the financing obligation, representing the net present value of the future minimum lease payments on the building, is $138 million at December 31, 2017.

At December 31, 2017, the future minimum lease payments on the lease are as follows:



FUTURE MINIMUM PAYMENTS – BUILD-TO-SUIT LEASE
(Dollars in millions)
2018	$	10
2019	10
2020	11
2021	11
2022	11
Thereafter	234
Total minimum lease payments	$	287

Other Capital Leases

At December 31, 2017, the future minimum lease payments under capital leases for fleet vehicles and other assets for Sempra Energy Consolidated are $4 million in 2018, $2 million in 2019, $1 million in 2020, negligible in 2021 and 2022 and $8 million thereafter. The net present value of the minimum lease payments is $8 million at December 31, 2017.

The California Utilities entered into new capital leases in 2017 for additional fleet vehicles. At December 31, 2017, the related capital lease obligations were $1 million each at SDG&E and SoCalGas, payable in 2018.

The annual depreciation charge for fleet vehicles and other assets in 2017, 2016 and 2015 was $3 million, $2 million and $4 million, respectively, at Sempra Energy Consolidated, including $1 million, $1 million and $2 million, respectively, at SDG&E and $2 million, $1 million and $2 million, respectively, at SoCalGas.

Construction and Development Projects

Sempra Energy Consolidated has various capital projects in progress in the U.S., Mexico and South America. Sempra Energy’s total commitments under these projects are approximately $527 million, requiring future payments of $257 million in 2018, $62 million in 2019, $44 million in 2020, $24 million in 2021, $16 million in 2022 and $124 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.

SDG&E

At December 31, 2017, SDG&E has commitments to make future payments of $117 million for construction projects that include


▪	$72 million for infrastructure improvements for natural gas and electric transmission and distribution operations;


▪	$35 million for the engineering, material procurement and construction costs primarily associated with the Sycamore-Peñasquitos Transmission Project; and


▪	$10 million related to spent fuel management at SONGS.

SDG&E expects future payments under these contractual commitments to be $78 million in 2018, $9 million in 2019, $19 million in 2020, $5 million in 2021, $1 million in 2022 and $5 million thereafter.

California Utilities

At December 31, 2017, SDG&E and SoCalGas have commitments to make future payments of $10 million for contracts related to the procurement of gas rotary meters. SDG&E expects the future payments under these contractual commitments to approximate $1 million each year in 2018 through 2020. SoCalGas expects the future payments under these contractual commitments to approximate $3 million in 2018 and $2 million each year in 2019 and 2020.

Sempra South American Utilities

At December 31, 2017, Sempra South American Utilities has commitments to make future payments of $16 million for the construction of substations and related transmission lines. The future payments under these contractual commitments are all expected to be made in 2018.

Sempra Mexico

At December 31, 2017, Sempra Mexico has commitments to make future payments of $289 million for contracts related to the construction of various natural gas pipelines and ongoing maintenance services. Sempra Mexico expects future payments under these contractual commitments to be $73 million in 2018, $46 million in 2019, $19 million in 2020, $17 million in 2021, $15 million in 2022 and $119 million thereafter.

Sempra Renewables

At December 31, 2017, Sempra Renewables has commitments to make future payments of $89 million for contracts related to the construction of renewable energy projects. Sempra Renewables expects future payments under these contractual commitments to be $80 million in 2018, $4 million in 2019, $3 million in 2020 and $2 million in 2021.

Sempra LNG & Midstream

At December 31, 2017, Sempra LNG & Midstream has commitments to make future payments of $6 million primarily for natural gas transportation projects. The future payments under these contractual commitments are all expected to be made in 2018.

OTHER COMMITMENTS

SDG&E

We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 13.

In connection with the completion of the Sunrise Powerlink project in 2012, 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 $3 million per year in 2018 through 2022 and $104 million thereafter, subject to escalation of 2 percent per year, for a remaining 52-year period. At December 31, 2017, the present value of these future payments of $119 million has been recorded as a regulatory asset as the amounts represent a cost that is expected to be recovered from customers in the future, and the related liability was $119 million.

Sempra LNG & Midstream

Additional consideration for a 2006 comprehensive legal settlement with the State of California to resolve the Continental Forge litigation included an agreement that, for a period of 18 years beginning in 2011, Sempra LNG & Midstream would sell to the California Utilities, subject to annual CPUC approval, up to 500 million cubic feet per day of regasified LNG from Sempra Mexico’s ECA facility that is not delivered or sold in Mexico at the price indexed to the California border minus $0.02 per MMBtu. There are no specified minimums required, and to date, Sempra LNG & Midstream has not been required to deliver any natural gas pursuant to this agreement.

ENVIRONMENTAL ISSUES

Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.

In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes that could adversely affect Sempra LNG & Midstream and Sempra Mexico. The California Utilities’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.

We discuss environmental matters related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

Other Environmental Issues

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:



CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated⁽¹⁾	$	92	$	53	$	64
SDG&E	46		17		24
SoCalGas	45		35		39


⁽¹⁾	In cases of non-wholly owned affiliates, includes only our share.

We have not identified any significant environmental issues outside the U.S.

At the California Utilities, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing us, except for those related to the Aliso Canyon natural gas storage facility leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities at sites for which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.

The table below shows the status at December 31, 2017 of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:



STATUS OF ENVIRONMENTAL SITES

	# Sites complete⁽¹⁾	# Sites in process
SDG&E:
Manufactured-gas sites	3	—
Third-party waste-disposal sites	2	1
SoCalGas:
Manufactured-gas sites	39	3
Third-party waste-disposal sites	5	2


⁽¹⁾	There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities at undiscounted amounts when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.

The following table shows our accrued liabilities for environmental matters at December 31, 2017:



ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
	Manufactured- gas sites		Waste disposal sites (PRP)⁽¹⁾		Other hazardous waste sites		Total⁽²⁾
SDG&E⁽³⁾	$	—	$	2	$	2	$	4
SoCalGas⁽⁴⁾	22		1		1		24
Other	—		1		—		1
Total Sempra Energy	$	22	$	4	$	3	$	29


⁽¹⁾	Sites for which we have been identified as a PRP.


⁽²⁾	Includes $9 million, $1 million and $8 million classified as current liabilities, and $20 million, $3 million and $16 million classified as noncurrent liabilities on Sempra Energy’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.


⁽³⁾	Does not include SDG&E’s liability for SONGS marine environment mitigation.


⁽⁴⁾	Does not include SoCalGas’ liability for environmental matters for the natural gas leak at the Aliso Canyon natural gas storage facility. We discuss matters related to the leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

We expect to pay the majority of these accruals over the next three years.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 13, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the estimated mitigation costs is $68 million, of which $44 million has been incurred through December 31, 2017 and $24 million is accrued for remaining costs through 2050, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. The requirements for enhanced fish protection and restoration of coastal wetlands for the SONGS mitigation are in process. Work on the artificial reef that was dedicated in 2008 continues. The CCC has stated that it now requires an expansion of the reef because the existing reef may be too small to consistently meet the performance standards. In December 2016, SDG&E and Edison filed a joint application with the CPUC seeking rate recovery of the costs of the reef expansion. In October 2017, SDG&E, Edison, TURN and ORA filed a joint motion requesting approval of a settlement agreement that amends the rate recovery application and allows costs to be recorded to a memorandum account until rate recovery is approved in the second half of 2018. Rates, if approved, would be effective January 2019. SDG&E’s share of the reef expansion costs currently forecasted through 2020 is $4 million. We expect a decision on the settlement agreement in the first half of 2018.

CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems designed to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile and Peru.

As they become operational, projects owned or partially owned by Sempra LNG & Midstream, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers, customers and partners to perform under long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects.

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

We have six separately managed reportable segments, as follows:


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


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


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

▪

Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3.


▪	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S.

▪

Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In September 2016, Sempra LNG & Midstream sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express. Sempra LNG & Midstream also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015. We discuss these divestitures in Note 3.

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

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

The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 4. Amounts labeled as “All other” in the following tables consist primarily of parent organizations.



SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
REVENUES
SDG&E	$	4,476		$	4,253		$	4,219
SoCalGas	3,785			3,471			3,489
Sempra South American Utilities	1,567			1,556			1,544
Sempra Mexico	1,196			725			669
Sempra Renewables	94			34			36
Sempra LNG & Midstream	540			508			653
Adjustments and eliminations	(1		)	—			(2		)
Intersegment revenues⁽¹⁾	(450		)	(364		)	(377		)
Total	$	11,207		$	10,183		$	10,231
INTEREST EXPENSE
SDG&E	$	203		$	195		$	204
SoCalGas	102			97			84
Sempra South American Utilities	38			38			32
Sempra Mexico	97			13			23
Sempra Renewables	15			4			3
Sempra LNG & Midstream	39			43			72
All other	284			282			263
Intercompany eliminations	(119		)	(119		)	(120		)
Total	$	659		$	553		$	561
INTEREST INCOME
SoCalGas	$	1		$	1		$	4
Sempra South American Utilities	28			21			19
Sempra Mexico	23			6			7



Sempra Renewables	7			5			4
Sempra LNG & Midstream	56			71			75
Intercompany eliminations	(69		)	(78		)	(80		)
Total	$	46		$	26		$	29
DEPRECIATION AND AMORTIZATION
SDG&E	$	670		$	646		$	604
SoCalGas	515			476			461
Sempra South American Utilities	54			49			50
Sempra Mexico	156			77			70
Sempra Renewables	38			6			6
Sempra LNG & Midstream	42			47			49
All other	15			11			10
Total	$	1,490		$	1,312		$	1,250
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	155		$	280		$	284
SoCalGas	160			143			138
Sempra South American Utilities	80			80			67
Sempra Mexico	227			188			11
Sempra Renewables	(226		)	(38		)	(49		)
Sempra LNG & Midstream	(119		)	(80		)	28
All other	999			(184		)	(138		)
Total	$	1,276		$	389		$	341



SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Years ended December 31 or at December 31,
	2017			2016			2015
EARNINGS (LOSSES)
SDG&E	$	407		$	570		$	587
SoCalGas⁽²⁾	396			349			419
Sempra South American Utilities	186			156			175
Sempra Mexico	169			463			213
Sempra Renewables	252			55			63
Sempra LNG & Midstream	150			(107		)	44
All other	(1,304		)	(116		)	(152		)
Total	$	256		$	1,370		$	1,349
ASSETS
SDG&E	$	17,844		$	17,719		$	16,515
SoCalGas	14,159			13,424			12,104
Sempra South American Utilities	4,060			3,591			3,235
Sempra Mexico	8,554			7,542			3,783
Sempra Renewables	2,898			3,644			1,441
Sempra LNG & Midstream	4,872			5,564			5,566
All other	915			475			734
Intersegment receivables	(2,848		)	(4,173		)	(2,228		)
Total	$	50,454		$	47,786		$	41,150
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E	$	1,555		$	1,399		$	1,133
SoCalGas	1,367			1,319			1,352
Sempra South American Utilities	244			194			154
Sempra Mexico	248			330			302
Sempra Renewables	497			835			81
Sempra LNG & Midstream	20			117			87
All other	18			20			47
Total	$	3,949		$	4,214		$	3,156
GEOGRAPHIC INFORMATION
Long-lived assets⁽³⁾:
United States	$	31,487		$	28,351		$	26,132
Mexico	5,363			4,814			3,160
South America	2,180			1,863			1,652
Total	$	39,030		$	35,028		$	30,944
Revenues⁽⁴⁾:
United States	$	8,547		$	8,004		$	8,119
South America	1,567			1,556			1,544
Mexico	1,093			623			568
Total	$	11,207		$	10,183		$	10,231


⁽¹⁾	Revenues for reportable segments include intersegment revenues of $7 million, $74 million, $103 million and $266 million for 2017, $6 million, $76 million, $102 million and $180 million for 2016, and $9 million, $75 million, $101 million and $192 million for 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.


⁽²⁾	After preferred dividends.


⁽³⁾	Includes net PP&E and investments.


⁽⁴⁾	Amounts are based on where the revenue originated, after intercompany eliminations.

QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Data [Abstract]

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (UNAUDITED)

We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below:



SEMPRA ENERGY
(In millions, except per share amounts)
	Quarters ended
	March 31		June 30		September 30		December 31
2017:
Revenues	$	3,031	$	2,533	$	2,679	$	2,964
Expenses and other income	$	2,276	$	2,118	$	2,664	$	2,564

Net income (loss)	$	452	$	248	$	102	$	(451	)
Earnings (losses) attributable to Sempra Energy	$	441	$	259	$	57	$	(501	)

Basic per-share amounts⁽¹⁾:
Net income (loss)	$	1.80	$	0.99	$	0.41	$	(1.80	)
Earnings (losses) attributable to Sempra Energy	$	1.76	$	1.03	$	0.23	$	(1.99	)
Weighted-average common shares outstanding	251.1		251.4		251.7		251.9

Diluted per-share amounts⁽¹⁾⁽²⁾:
Net income (loss)	$	1.79	$	0.98	$	0.41	$	(1.80	)
Earnings (losses) attributable to Sempra Energy	$	1.75	$	1.03	$	0.22	$	(1.99	)
Weighted-average common shares outstanding	252.2		252.8		253.4		251.9
2016:
Revenues	$	2,622	$	2,156	$	2,535	$	2,870
Expenses and other income	$	2,167	$	2,268	$	1,553	$	2,365

Net income	$	364	$	27	$	719	$	409
Earnings attributable to Sempra Energy	$	353	$	16	$	622	$	379

Basic per-share amounts⁽¹⁾:
Net income	$	1.46	$	0.11	$	2.87	$	1.63
Earnings attributable to Sempra Energy	$	1.41	$	0.06	$	2.48	$	1.51
Weighted-average common shares outstanding	249.7		250.1		250.4		250.6

Diluted per-share amounts⁽¹⁾:
Net income	$	1.45	$	0.11	$	2.85	$	1.62
Earnings attributable to Sempra Energy	$	1.40	$	0.06	$	2.46	$	1.51
Weighted-average common shares outstanding	251.5		252.0		252.4		251.6


⁽¹⁾	Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year.


⁽²⁾	In the quarter ended December 31, 2017, the total weighted-average number of potentially dilutive securities was 0.8 million. However, these securities were not included in the computation of U.S. GAAP losses per common share since to do so would have decreased the loss per share.

In 2017, Sempra Energy’s income tax expense included $870 million related to the impact of the TCJA, as we discuss in Note 6.

In September 2017, SDG&E recognized a charge of $351 million ($208 million after-tax) for the write-off of its wildfire regulatory asset, which we discuss in Note 15.

In June 2017 and September 2016, Sempra Mexico recognized impairment charges of $71 million ($47 million after noncontrolling interests) and $131 million ($111 million after-tax; $90 million after-tax and after noncontrolling interests), respectively, related to assets held for sale at TdM. We discuss the impairments in Notes 3 and 10.

In September 2016, Sempra Mexico recorded a $617 million noncash gain ($432 million after-tax; $350 million after-tax and after noncontrolling interests) associated with the remeasurement of its equity interest in IEnova Pipelines, which we discuss in Note 3.

In May 2016, Sempra LNG & Midstream recorded a pretax charge of $206 million ($123 million after-tax) related to permanently released pipeline capacity with Rockies Express and others, which we discuss in Note 15. In May 2017, Sempra LNG & Midstream recorded $47 million ($28 million after-tax) for settlement proceeds received from a breach of contract claim against a counterparty related to the charge.

In March 2016, Sempra LNG & Midstream recognized an impairment charge of $44 million ($27 million after-tax) on its investment in Rockies Express, which we discuss in Notes 3 and 10.



SDG&E
(Dollars in millions)
	Quarters ended
	March 31			June 30			September 30			December 31
2017:
Operating revenues	$	1,057		$	1,058		$	1,236		$	1,125
Operating expenses	779			817			1,290			877
Operating income (loss)	$	278		$	241		$	(54	)	$	248

Net income (loss)	$	157		$	153		$	(19	)	$	130
(Earnings) losses attributable to noncontrolling interest	(2		)	(4		)	(9		)	1
Earnings (losses) attributable to common shares	$	155		$	149		$	(28	)	$	131
2016:
Operating revenues	$	991		$	992		$	1,209		$	1,061
Operating expenses	755			822			886			800
Operating income	$	236		$	170		$	323		$	261

Net income	$	137		$	87		$	194		$	147
(Earnings) losses attributable to noncontrolling interest	(1		)	13			(11		)	4
Earnings attributable to common shares	$	136		$	100		$	183		$	151



SOCALGAS
(Dollars in millions)
	Quarters ended
	March 31		June 30			September 30		December 31
2017:
Operating revenues	$	1,241	$	770		$	684	$	1,090
Operating expenses	926		675			674		888
Operating income	$	315	$	95		$	10	$	202

Net income	$	203	$	59		$	7	$	128
Dividends on preferred stock	—		(1		)	—		—
Earnings attributable to common shares	$	203	$	58		$	7	$	128
2016:
Operating revenues	$	1,033	$	617		$	686	$	1,135
Operating expenses	739		628			648		899
Operating income (loss)	$	294	$	(11	)	$	38	$	236

Net income	$	199	$	—		$	—	$	151
Dividends on preferred stock	—		(1		)	—		—
Earnings (losses) attributable to common shares	$	199	$	(1	)	$	—	$	151

SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters each year.

SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

SEMPRA ENERGY

As part of our plans to finance the proposed Merger that we discuss in Note 3, we completed the following transactions in January 2018.

Common Stock Offering

On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock, no par value, in a registered public offering at $107.00 per share ($105.074 per share after deducting the underwriting discount), pursuant to forward sale agreements with each of Morgan Stanley & Co. LLC, an affiliate of RBC Capital Markets, LLC and an affiliate of Barclays Capital Inc. (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 3,504,672 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 26,869,158. We received net proceeds of $368 million (net of underwriting discounts, but before deducting other related expenses) from the sale of shares to cover overallotments.

The initial forward sale price under the forward sale agreements is $105.074 per share, which is the public offering price in the common stock offering less the underwriting discount. However, the forward sale price is subject to adjustment pursuant to the forward sale agreements. We did not initially receive any proceeds from the sale of our common stock sold by the forward sellers to the underwriters. We expect to settle a portion of the forward sale agreements and receive proceeds, subject to certain adjustments, from the sale of those shares of common stock concurrently with, or prior to, the closing of our proposed Merger. We expect to settle the remaining portion of the forward sale agreements after the Merger, if completed, in multiple settlements on or prior to December 15, 2019, which is the final settlement date under the forward sale agreements. At the initial forward sale price of $105.074 per share, we expect that the net proceeds from full physical settlement of the forward sale agreements would be approximately $2.46 billion (after deducting the underwriting discount, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements).

In the case of any forward sales that settle after the closing of the Merger, we intend to use the net proceeds to repay indebtedness incurred to finance a portion of the cost of the Merger Consideration and associated transaction costs. If for any reason the Merger has not closed on or prior to December 1, 2018, or the Merger Agreement is terminated at any time prior to such date, then we expect to use the net proceeds from this offering for general corporate purposes, which may include, in our sole discretion, voluntary redemption of the mandatory convertible preferred stock discussed below, debt repayment (including repayment of commercial paper), capital expenditures, investments and possibly repurchases of our common stock at the discretion of our board of directors.

Although we expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the forward purchasers upon the occurrence of certain events.

Before the issuance of shares of our common stock, if any, upon settlement of the forward sale agreements, we expect that the shares issuable upon settlement of the forward sale agreements will be reflected in our diluted EPS calculation using the treasury stock method. Under this method, the number of shares of our common stock used in calculating diluted EPS is deemed to be increased by the excess, if any, of the number of shares of common stock that would be issued upon full physical settlement of the forward sale agreements over the number of shares of common stock that could be purchased by us in the market (based on the average market price of our common stock during the applicable reporting period) using the proceeds receivable upon full physical settlement (based on the adjusted forward sale price at the end of the reporting period). Consequently, we anticipate there will be no dilutive effect on our EPS except during periods when the average market price of shares of our common stock is above the applicable adjusted forward sale price, which is initially $105.074 per share, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. However, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.

Mandatory Convertible Preferred Stock Offering

On January 9, 2018, in a separate registered public offering, we sold 17,250,000 shares of our 6% mandatory convertible preferred stock, series A (mandatory convertible preferred stock) at $100.00 per share (or $98.20 per share after deducting the underwriting discount), including 2,250,000 shares purchased by the underwriters as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of mandatory convertible preferred stock has a liquidation value of $100.

We intend to use the net proceeds of approximately $1.69 billion (net of underwriting discounts, but before related expenses) from this offering to finance a portion of the Merger Consideration and associated transaction costs. If the proposed Merger is not consummated on or prior to December 1, 2018, or the Merger Agreement is terminated at any time prior to such date, then we expect to use the net proceeds for general corporate purposes, which may include, in our sole discretion, the redemption of the mandatory convertible preferred stock, debt repayment (including repayment of commercial paper), capital expenditures, investments and possibly repurchases of our common stock at the discretion of our board of directors.

Mandatory Conversion

Unless earlier converted or redeemed, each share of the mandatory convertible preferred stock will automatically convert on the mandatory conversion date, which is expected to be January 15, 2021, into not less than 0.7629 and not more than 0.9345 shares of our common stock, subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion of the mandatory convertible preferred stock will be determined based on the volume-weighted average market value per share of our common stock over the 20 consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding January 15, 2021, which we refer to as the “settlement period.” The following table illustrates the conversion rate per share of the mandatory convertible preferred stock, subject to certain anti-dilution adjustments:



CONVERSION RATES

Applicable market value per share of our common stock		Conversion rate (number of shares of our common stock to be received upon conversion of each share of mandatory convertible preferred stock)

Greater than $131.075 (which is the threshold appreciation price)		0.7629 shares (approximately equal to $100.00 divided by the threshold appreciation price)
Equal to or less than $131.075 but greater than or equal to $107.00		Between 0.7629 and 0.9345 shares, determined by dividing $100.00 by the applicable market value of our common stock
Less than $107.00 (which is the initial price)		0.9345 shares (approximately equal to $100.00 divided by the initial price)

Dividends

Dividends on the mandatory convertible preferred stock will be payable quarterly, beginning on April 15, 2018, on a cumulative basis when, as and if declared by our board of directors. We may pay quarterly declared dividends in cash, or subject to certain limitations, in shares of our common stock, no par value, or in any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97 percent of the volume-weighted average price per share over the five consecutive trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date. The holders of mandatory convertible preferred stock will have no voting rights. However, under certain circumstances regarding nonpayment for six or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the mandatory convertible preferred stock, voting together as a single class with holders of any and all other outstanding preferred stock of equal rank having similar voting rights, will be entitled to elect two directors to fill such newly created directorships. This right shall terminate when all accumulated dividends have been paid in full and the authorized number of directors shall automatically decrease by two, subject to revesting of that right in the event of each subsequent nonpayment.

Acquisition Termination Redemption

If the proposed Merger has not closed on or before December 1, 2018, the Merger Agreement is terminated or if we determine in our reasonable judgment that the proposed Merger will not occur, we may, at our option, redeem the mandatory convertible preferred stock, in whole but not in part, at a redemption amount per share, in cash, equal to an acquisition termination make-whole amount. However, if the acquisition termination share price exceeds the initial price, then, subject to certain limitations, we may pay part or all of the redemption price in shares of our common stock.

The redemption of the mandatory convertible preferred stock gives us the option to redeem, in whole but not in part, the mandatory convertible preferred stock at a make-whole redemption price per share that includes a make-whole adjustment which could provide a redemption price that exceeds the initial public offering price of $100.00 per share, plus accrued and unpaid dividends. We may satisfy the redemption price by delivering cash, common stock or a combination thereof.

Conversion at the Option of the Holder

At any time prior to January 15, 2021, holders may elect to convert each share of the mandatory convertible preferred stock into shares of our common stock at the minimum conversion rate of 0.7629 shares of our common stock per share of the mandatory convertible preferred stock, subject to anti-dilution adjustments. However, if holders elect to convert any shares of the mandatory convertible preferred stock during a specified period beginning on the effective date of a fundamental change, as defined, such shares of the mandatory convertible preferred stock will be converted into shares of our common stock at a fundamental change conversion rate, and the holders will also be entitled to receive a fundamental change dividend make-whole amount and accumulated dividend amount.

Ranking

The mandatory convertible preferred stock will rank with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:


▪	senior to our common stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;


▪	junior to our existing and future indebtedness and other liabilities; and


▪	structurally subordinated to any existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.

The conversion of the mandatory convertible preferred stock would have resulted in the issuance of approximately 16.1 million shares of our common stock, subject to possible adjustment pursuant to the terms of the mandatory convertible preferred stock, based on the last reported sale price of our common stock on the New York Stock Exchange on December 29, 2017, which was $106.92 per share. However, if the mandatory convertible preferred stock had been issued January 1, 2017 and dividends paid for the full year 2017, an adjustment for the shares issuable on conversion would not have been reflected in our computation of diluted EPS for 2017 because the issuance of those shares would be anti-dilutive.

Long-Term Debt Offering

On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses):



NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount		Maturity	Interest payments
Floating Rate⁽¹⁾ Notes due 2019	$	500	July 15, 2019	Quarterly
Floating Rate⁽²⁾ Notes due 2021	700		January 15, 2021	Quarterly
2.400% Senior Notes due 2020	500		February 1, 2020	Semi-annually
2.900% Senior Notes due 2023	500		February 1, 2023	Semi-annually
3.400% Senior Notes due 2028	1,000		February 1, 2028	Semi-annually
3.800% Senior Notes due 2038	1,000		February 1, 2038	Semi-annually
4.000% Senior Notes due 2048	800		February 1, 2048	Semi-annually


⁽¹⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points.


⁽²⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points.

The 2019 floating rate notes are not subject to redemption at our option. At our option, we may redeem some or all of the 2021 floating rate notes at any time on or after January 14, 2019 at the applicable redemption price per the terms of the notes. At our option, we may redeem some or all of the fixed rate notes of each series at any time at the applicable redemption price for such series of fixed rate notes.

We intend to use the net proceeds from this offering to finance a portion of the Merger Consideration and associated transaction costs. If we do not consummate the Merger on or prior to December 1, 2018, or if, on or prior to such date, the Merger agreement is terminated, we will be required to redeem all of the outstanding notes (other than the 2028 notes) at a redemption price equal to 101 percent of the principal amount of the notes we are required to redeem, plus accrued and unpaid interest, if any. The 2028 notes are not subject to this special mandatory redemption. If we are required to redeem the notes, we may use all or a portion of the net proceeds we received from the issuance of these notes to pay all or a portion of the redemption price of the notes we are required to redeem, and we intend to use any remaining net proceeds for general corporate purposes, which may include, in our sole discretion, voluntary redemption of our mandatory convertible preferred stock, repayment of other debt (including repayment of commercial paper), capital expenditures, investments and possibly, repurchases of our common stock at the discretion of our board of directors.

Ranking

The notes are unsecured and unsubordinated obligations, ranking on a parity in right of payment with all of our other unsecured and unsubordinated indebtedness and guarantees. If the proposed Merger is consummated, the notes will also be effectively subordinated to all existing and future indebtedness and other liabilities of Oncor Holdings, Oncor and their respective subsidiaries.

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information of Parent



SEMPRA ENERGY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Years ended December 31,
	2017			2016			2015
Interest expense	$	(293	)	$	(277	)	$	(261	)
Operation and maintenance	(87		)	(81		)	(66		)
Other income (expense), net	107			(2		)	7
Income tax benefit	33			181			150
Loss before equity in earnings of subsidiaries	(240		)	(179		)	(170		)
Equity in earnings of subsidiaries, net of income taxes	496			1,549			1,519
Net income/earnings	$	256		$	1,370		$	1,349
Basic earnings per common share	$	1.02		$	5.48		$	5.43
Weighted-average number of shares outstanding (thousands)	251,545			250,217			248,249
Diluted earnings per common share	$	1.01		$	5.46		$	5.37
Weighted-average number of shares outstanding (thousands)	252,300			251,155			250,923

See Notes to Condensed Financial Information of Parent.



SEMPRA ENERGY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31,
	Pretax amount			Income tax benefit (expense)			Net-of-tax amount
2017:
Net income	$	223		$	33		$	256
Other comprehensive income (loss):
Foreign currency translation adjustments	107			—			107
Financial instruments	2			1			3
Pension and other postretirement benefits	20			(8		)	12
Total other comprehensive income	129			(7		)	122
Comprehensive income	$	352		$	26		$	378
2016:
Net income	$	1,189		$	181		$	1,370
Other comprehensive income (loss):
Foreign currency translation adjustments	42			—			42
Financial instruments	(6		)	11			5
Pension and other postretirement benefits	(13		)	4			(9		)
Total other comprehensive income	23			15			38
Comprehensive income	$	1,212		$	196		$	1,408
2015:
Net income	$	1,199		$	150		$	1,349
Other comprehensive income (loss):
Foreign currency translation adjustments	(260		)	—			(260		)
Financial instruments	(80		)	33			(47		)
Pension and other postretirement benefits	(3		)	1			(2		)
Total other comprehensive loss	(343		)	34			(309		)
Comprehensive income	$	856		$	184		$	1,040

See Notes to Condensed Financial Information of Parent.



SEMPRA ENERGY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017		December 31, 2016
Assets:
Cash and cash equivalents	$	104	$	12
Due from affiliates	83		73
Income taxes receivable	272		—
Other current assets	6		2
Total current assets	465		87

Investments in subsidiaries	17,924		17,329
Due from affiliates	2		—
Deferred income taxes	1,802		2,570
Other assets	656		592
Total assets	$	20,849	$	20,578

Liabilities and shareholders’ equity:
Current portion of long-term debt	$	500	$	600
Due to affiliates	280		359
Income taxes payable	—		153
Other current liabilities	396		374
Total current liabilities	1,176		1,486

Long-term debt	6,198		5,100
Due to affiliates	300		517
Other long-term liabilities	505		524

Commitments and contingencies (Note 4)

Shareholders’ equity	12,670		12,951
Total liabilities and shareholders’ equity	$	20,849	$	20,578

See Notes to Condensed Financial Information of Parent.



SEMPRA ENERGY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2017			2016⁽¹⁾			2015⁽¹⁾

Net cash provided by (used in) operating activities	$	89		$	(3	)	$	95

Expenditures for property, plant and equipment	(11		)	(5		)	(43		)
Purchase of trust assets	—			—			(5		)
Decrease (increase) in loans to affiliates, net	—			457			(457		)
Expenditures for Merger-related transaction costs	(12		)	—			—
Net cash (used in) provided by investing activities	(23		)	452			(505		)

Common stock dividends paid	(755		)	(686		)	(628		)
Issuances of common stock	47			51			52
Repurchases of common stock	(15		)	(56		)	(74		)
Issuances of long-term debt	1,595			499			1,248
Payments on long-term debt	(600		)	(750		)	—
(Decrease) increase in loans from affiliates, net	(239		)	504			(230		)
Tax benefit related to share-based compensation	—			—			52
Other	(7		)	(3		)	(9		)
Net cash provided by (used in) financing activities	26			(441		)	411

Increase in cash and cash equivalents	92			8			1
Cash and cash equivalents, January 1	12			4			3
Cash and cash equivalents, December 31	$	104		$	12		$	4

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued Merger-related transaction costs	$	31		$	—		$	—
Financing of build-to-suit property	—			—			61
Common dividends issued in stock	53			53			55
Dividends declared but not paid	207			189			174


⁽¹⁾	As adjusted for the retrospective adoption of ASU 2016-15, which we discuss in Note 2.

See Notes to Condensed Financial Information of Parent.

BASIS OF PRESENTATION

Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information.

Other Income, Net, on the Condensed Statements of Operations includes


▪	$56 million, $23 million and $3 million of gains on dedicated assets in support of our executive retirement and deferred compensation plans in 2017, 2016 and 2015, respectively; and


▪	$50 million and $(28) million net gains (losses) primarily from the settlement of foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova in 2017 and 2016, respectively.

Additional information on Sempra Energy’s foreign currency derivatives is provided in Note 9 of the Notes to Consolidated Financial Statements.

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures.

ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice. Of the eight issues addressed in ASU 2016-15, we were impacted by the following issues:


▪	Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below)


▪	Issue 6 – distributions received from equity method investments

The standard must be adopted retrospectively. We early adopted ASU 2016-15 in the fourth quarter of 2017. Upon adoption of ASU 2016-15, our Condensed Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-15
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Statements of Cash Flows:
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(178	)	$	175		$	(3	)	$	(255	)	$	350		$	95

Cash flows from investing activities:
Dividends received from subsidiaries⁽¹⁾	175			(175		)	—			350			(350		)	—
Net cash provided by (used in) investing activities	627			(175		)	452			(155		)	(350		)	(505		)


⁽¹⁾	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017						2016
	As reported			Recast			As reported			Recast
Sempra Energy Condensed Statements of Operations:
Operation and maintenance	$	(87	)	$	(80	)	$	(81	)	$	(76	)
Other income (expense), net	107			100			(2		)	(7		)

LONG-TERM DEBT

The following table shows the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016

2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease	138			137
	6,737			5,734
Current portion of long-term debt	(500		)	(600		)
Unamortized discount on long-term debt	(13		)	(10		)



Unamortized debt issuance costs	(26		)	(24		)
Total long-term debt	$	6,198		$	5,100

Excluding the build-to-suit lease and market value adjustments for interest rate swaps, maturities of long-term debt are $500 million in 2018, $1 billion in 2019, $900 million in 2020, $850 million in 2021, $500 million in 2022 and $2.85 billion thereafter.

Additional information on Sempra Energy’s long-term debt is provided in Note 5 of the Notes to Consolidated Financial Statements.

COMMITMENTS AND CONTINGENCIES

For contingencies and guarantees related to Sempra Energy, refer to Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements.

SUBSEQUENT EVENTS

For subsequent events related to Sempra Energy, refer to Note 18 of the Notes to Consolidated Financial Statements.

Organization, Consolidation and Presentation of Financial Statements [Abstract]

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA (Policies)

12 Months Ended

Dec. 31, 2017

Principles of Consolidation

PRINCIPLES OF CONSOLIDATION

Sempra Energy


▪	Sempra Utilities, which includes our SDG&E, SoCalGas and Sempra South American Utilities reportable segments; and


▪	Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments.

We provide descriptions of each of our segments in Note 16.

SDG&E

SoCalGas

SoCalGas’ common stock is wholly owned by PE, which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:


▪	the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;


▪	the Consolidated Financial Statements and related Notes of SDG&E and its VIE; and


▪	the Financial Statements and related Notes of SoCalGas.

Use of Estimates in the Preparation of the Financial Statements

Subsequent Events

Regulatory Operations

EFFECTS OF REGULATION

Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of:


▪	the nature of the event giving rise to the assessment;


▪	existing statutes and regulatory code;


▪	legal precedents;


▪	regulatory principles and analogous regulatory actions;


▪	testimony presented in regulatory hearings;


▪	regulatory orders;


▪	a commission-authorized mechanism established for the accumulation of costs;


▪	status of applications for rehearings or state court appeals;


▪	specific approval from a commission; and


▪	historical experience.

We provide information concerning regulatory assets and liabilities in Notes 13 and 14.

Fair Value Measurements

FAIR VALUE MEASUREMENTS


▪	quoted forward prices for commodities


▪	time value


▪	current market and contractual prices for the underlying instruments


▪	volatility factors


▪	other relevant economic measures

Fair Value of Financial Instruments

RECURRING FAIR VALUE MEASURES

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 in “Financial Statement Presentation.”

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 in the tables below include the following:

▪


▪	Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both December 31, 2017 and 2016.

Cash and Cash Equivalents

CASH AND CASH EQUIVALENTS

Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.

Collection Allowances

COLLECTION ALLOWANCES

We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables.

Greenhouse Gas Allowances and Emissions and Renewable Energy Certificates

INVENTORIES

Income Taxes

INCOME TAXES

Under the regulatory accounting treatment required for flow-through temporary differences, as discussed in Note 6, the California Utilities and Sempra Mexico recognize


▪	regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and


▪	regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers.


▪	repairs expenditures related to a certain portion of utility plant fixed assets


▪	the equity portion of AFUDC


▪	a portion of the cost of removal of utility plant assets


▪	utility self-developed software expenditures


▪	depreciation on a certain portion of utility plant assets


▪	state income taxes

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

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

RENEWABLE ENERGY CERTIFICATES

Property, Plant and Equipment (PP&E)

We capitalize interest costs incurred to finance capital projects. We also capitalize interest on equity method investments that have not commenced planned principal operations.

PROPERTY, PLANT AND EQUIPMENT

Our plant costs include


▪	labor


▪	materials and contract services


▪	expenditures for replacement parts incurred during a major maintenance outage of a generating plant

Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.

Goodwill and Other Intangible Assets

Other Intangible Assets primarily includes


▪	storage and development rights related to the Bay Gas and Mississippi Hub natural gas storage facilities.


▪	a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities.


▪	a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 3.

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill


▪	consideration of market transactions


▪	future cash flows


▪	the appropriate risk-adjusted discount rate


▪	country risk


▪	entity risk

Long-lived Assets

LONG-LIVED ASSETS


▪	significant decreases in the market price of an asset


▪	a significant adverse change in the extent or manner in which we use an asset or in its physical condition


▪	a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset


▪	a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset


▪	a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life

Variable Interest Entities (VIE)

VARIABLE INTEREST ENTITIES

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


▪	the purpose and design of the VIE;


▪	the nature of the VIE’s risks and the risks we absorb;


▪	the power to direct activities that most significantly impact the economic performance of the VIE; and


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

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

Contingencies

CONTINGENCIES


▪	information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and


▪	the amount of the loss can be reasonably estimated.

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

Legal Fees

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

LEGAL PROCEEDINGS

Comprehensive Income

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:


▪	foreign currency translation adjustments


▪	certain hedging activities


▪	changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans


▪	unrealized gains or losses on available-for-sale securities

The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to noncontrolling interests

Noncontrolling Interests

NONCONTROLLING INTERESTS

Operation and Maintenance Expenses

REVENUES

California Utilities

▪

Sempra South American Utilities

Sempra Infrastructure

Energy-Related Businesses

Sempra South American Utilities

Sempra Mexico

Sempra Mexico recognizes revenues from:


▪	pipeline transportation and storage of natural gas, LPG and ethane as capacity is provided. Certain of the revenues recognized from pipelines are under contracts that are accounted for as operating leases;


▪	sale of natural gas as deliveries are made;


▪	an LNG regasification terminal that generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements as capacity is provided;


▪	wind power generation facilities that generate revenues from selling electricity as the power is delivered at the interconnection point; and


▪	TdM, a natural gas-fired power plant that generates revenues from selling electricity and/or capacity to the CAISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point. At December 31, 2017, TdM is classified as held for sale, as we discuss in Note 3.

Sempra Renewables

Sempra LNG & Midstream

Other Cost of Sales

OTHER COST OF SALES

Other Cost of Sales primarily includes


▪	pipeline capacity costs, including the permanent release of pipeline capacity in 2016 and the associated recoveries in 2017, at Sempra LNG & Midstream;


▪	pipeline transportation and natural gas marketing costs at Sempra LNG & Midstream;


▪	electric construction services costs at Sempra South American Utilities’ energy-services companies; and


▪	energy management service fees and costs associated with construction performed for and invoiced to third parties at Sempra Mexico.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.

Foreign Currency Translation

FOREIGN CURRENCY TRANSLATION

New Accounting Standards

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.


▪	Issue 1 – debt prepayment or debt extinguishment costs


▪	Issue 3 – contingent consideration payments made after a business combination


▪	Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies)

Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities – other	$	63		$	(1	)	$	62		$	66		$	—		$	66
Changes in other assets	56			(7		)	49			(162		)	(7		)	(169		)
Net cash provided by operating activities	2,319			(8		)	2,311			2,905			(7		)	2,898

Cash flows from investing activities:
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired	(1,582		)	1,582			—			(200		)	200			—
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired	—			(1,504		)	(1,504		)	—			(198		)	(198		)
Increases in restricted cash	(139		)	139			—			(100		)	100			—
Decreases in restricted cash	175			(175		)	—			93			(93		)	—
Other	—			9			9			1			8			9
Net cash used in investing activities	(4,886		)	51			(4,835		)	(2,885		)	17			(2,868		)

Cash flows from financing activities:
Other	(10		)	(11		)	(21		)	(17		)	(3		)	(20		)
Net cash provided by (used in) financing activities	2,513			(11		)	2,502			(173		)	(3		)	(176		)

Effect of exchange rate changes on cash and cash equivalents	—			—			—			(14		)	14			—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—			(3		)	(3		)	—			(14		)	(14		)

Decrease in cash and cash equivalents	(54		)	54			—			(167		)	167			—
Decrease in cash, cash equivalents, and restricted cash	—			(25		)	(25		)	—			(160		)	(160		)

Cash and cash equivalents, January 1	403			(403		)	—			570			(570		)	—
Cash, cash equivalents and restricted cash, January 1	—			450			450			—			610			610
Cash and cash equivalents, December 31	349			(349		)	—			403			(403		)	—
Cash, cash equivalents and restricted cash, December 31	—			425			425			—			450			450
SDG&E Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Changes in other assets	$	(16	)	$	(4	)	$	(20	)	$	(122	)	$	(3	)	$	(125	)
Net cash provided by operating activities	1,327			(4		)	1,323			1,664			(3		)	1,661

Cash flows from investing activities:
Increases in restricted cash	(49		)	49			—			(39		)	39			—
Decreases in restricted cash	60			(60		)	—			35			(35		)	—
Other	—			6			6			—			5			5
Net cash used in investing activities	(1,319		)	(5		)	(1,324		)	(1,086		)	9			(1,077		)

Cash flows from financing activities:
Other⁽¹⁾	(4		)	(2		)	(6		)	(2		)	(2		)	(4		)
Net cash used in financing activities	(20		)	(2		)	(22		)	(566		)	(2		)	(568		)

(Decrease) increase in cash and cash equivalents	(12		)	12			—			12			(12		)	—
(Decrease) increase in cash, cash equivalents, and restricted cash	—			(23		)	(23		)	—			16			16

Cash and cash equivalents, January 1	20			(20		)	—			8			(8		)	—
Cash, cash equivalents and restricted cash, January 1	—			43			43			—			27			27
Cash and cash equivalents, December 31	8			(8		)	—			20			(20		)	—
Cash, cash equivalents and restricted cash, December 31	—			20			20			—			43			43

⁽¹⁾ Previously labeled “Debt issuance costs.”

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017				2016
	As reported		Recast		As reported		Recast
Sempra Energy Consolidated Statements of Operations:
Operation and maintenance	$	3,117	$	3,096	$	2,970	$	2,976
Other income, net	254		233		132		138
SDG&E Consolidated Statements of Operations:
Operation and maintenance	$	1,020	$	1,024	$	1,048	$	1,062
Operating income	713		709		990		976
Other income, net	66		70		50		64
SoCalGas Statements of Operations:



Operation and maintenance	$	1,479	$	1,474	$	1,385	$	1,391
Operating income	622		627		557		551
Other income, net	36		31		32		38

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures.

ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP.


▪	Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below)


▪	Issue 6 – distributions received from equity method investments



IMPACT FROM ADOPTION OF ASU 2016-15
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Statements of Cash Flows:
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(178	)	$	175		$	(3	)	$	(255	)	$	350		$	95

Cash flows from investing activities:
Dividends received from subsidiaries⁽¹⁾	175			(175		)	—			350			(350		)	—
Net cash provided by (used in) investing activities	627			(175		)	452			(155		)	(350		)	(505		)


⁽¹⁾	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017						2016
	As reported			Recast			As reported			Recast
Sempra Energy Condensed Statements of Operations:
Operation and maintenance	$	(87	)	$	(80	)	$	(81	)	$	(76	)
Other income (expense), net	107			100			(2		)	(7		)

Business Combinations

We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature.


▪	PP&E – We applied an income approach using market-based discounted cash flows. We used the pricing included in the existing PPAs, which was determined to reflect current market rates in the Mexican renewable energy market.

▪


▪	Debt – Using an income approach, we valued debt by discounting future debt payments by a market yield commensurate with the remaining term of the loans.


▪	Derivatives – Using an income approach, we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data.

For substantially all other assets and liabilities, we determined that historical carrying value approximates fair value due to their short-term nature.

Environmental Costs

Investments in Noncontrolling Interests

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

We are required by applicable U.S. GAAP to:


▪	recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position;


▪	measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and


▪	recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of Sempra Energy and its consolidated subsidiaries.

Net Assets and Liabilities

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

We selected individual bonds from a universe of Bloomberg AA-rated bonds that:


▪	have an outstanding issue of at least $50 million;


▪	are non-callable (or callable with make-whole provisions);


▪	exclude collateralized bonds; and


▪	exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded.

This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics:


▪	The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio.


▪	Recent events have caused significant price volatility to which rating agencies have not reacted.


▪	Lack of liquidity is causing price quotes to vary significantly from broker to broker.

We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP.

Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.

Fair Value of Pension and Other Postretirement Benefit Plan Assets

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Share-based Compensation

SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS

Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS

Derivative Financial Instruments

INTEREST RATE DERIVATIVES

HEDGE ACCOUNTING

ENERGY DERIVATIVES

▪


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

FOREIGN CURRENCY DERIVATIVES

Earnings Per Share

Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

Concentration of Credit Risk

CONCENTRATION OF CREDIT RISK

Segment Reporting

We have six separately managed reportable segments, as follows:


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


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


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

▪


▪	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S.

▪

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT, NEW ACCOUNTING STANDARDS (Policies)

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

New Accounting Standards

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.


▪	Issue 1 – debt prepayment or debt extinguishment costs


▪	Issue 3 – contingent consideration payments made after a business combination


▪	Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies)

Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities – other	$	63		$	(1	)	$	62		$	66		$	—		$	66
Changes in other assets	56			(7		)	49			(162		)	(7		)	(169		)
Net cash provided by operating activities	2,319			(8		)	2,311			2,905			(7		)	2,898

Cash flows from investing activities:
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired	(1,582		)	1,582			—			(200		)	200			—
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired	—			(1,504		)	(1,504		)	—			(198		)	(198		)
Increases in restricted cash	(139		)	139			—			(100		)	100			—
Decreases in restricted cash	175			(175		)	—			93			(93		)	—
Other	—			9			9			1			8			9
Net cash used in investing activities	(4,886		)	51			(4,835		)	(2,885		)	17			(2,868		)

Cash flows from financing activities:
Other	(10		)	(11		)	(21		)	(17		)	(3		)	(20		)
Net cash provided by (used in) financing activities	2,513			(11		)	2,502			(173		)	(3		)	(176		)

Effect of exchange rate changes on cash and cash equivalents	—			—			—			(14		)	14			—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—			(3		)	(3		)	—			(14		)	(14		)

Decrease in cash and cash equivalents	(54		)	54			—			(167		)	167			—
Decrease in cash, cash equivalents, and restricted cash	—			(25		)	(25		)	—			(160		)	(160		)

Cash and cash equivalents, January 1	403			(403		)	—			570			(570		)	—
Cash, cash equivalents and restricted cash, January 1	—			450			450			—			610			610
Cash and cash equivalents, December 31	349			(349		)	—			403			(403		)	—
Cash, cash equivalents and restricted cash, December 31	—			425			425			—			450			450
SDG&E Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Changes in other assets	$	(16	)	$	(4	)	$	(20	)	$	(122	)	$	(3	)	$	(125	)
Net cash provided by operating activities	1,327			(4		)	1,323			1,664			(3		)	1,661

Cash flows from investing activities:
Increases in restricted cash	(49		)	49			—			(39		)	39			—
Decreases in restricted cash	60			(60		)	—			35			(35		)	—
Other	—			6			6			—			5			5
Net cash used in investing activities	(1,319		)	(5		)	(1,324		)	(1,086		)	9			(1,077		)

Cash flows from financing activities:
Other⁽¹⁾	(4		)	(2		)	(6		)	(2		)	(2		)	(4		)
Net cash used in financing activities	(20		)	(2		)	(22		)	(566		)	(2		)	(568		)

(Decrease) increase in cash and cash equivalents	(12		)	12			—			12			(12		)	—
(Decrease) increase in cash, cash equivalents, and restricted cash	—			(23		)	(23		)	—			16			16

Cash and cash equivalents, January 1	20			(20		)	—			8			(8		)	—
Cash, cash equivalents and restricted cash, January 1	—			43			43			—			27			27
Cash and cash equivalents, December 31	8			(8		)	—			20			(20		)	—
Cash, cash equivalents and restricted cash, December 31	—			20			20			—			43			43

⁽¹⁾ Previously labeled “Debt issuance costs.”

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017				2016
	As reported		Recast		As reported		Recast
Sempra Energy Consolidated Statements of Operations:
Operation and maintenance	$	3,117	$	3,096	$	2,970	$	2,976
Other income, net	254		233		132		138
SDG&E Consolidated Statements of Operations:
Operation and maintenance	$	1,020	$	1,024	$	1,048	$	1,062
Operating income	713		709		990		976
Other income, net	66		70		50		64
SoCalGas Statements of Operations:



Operation and maintenance	$	1,479	$	1,474	$	1,385	$	1,391
Operating income	622		627		557		551
Other income, net	36		31		32		38

NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on Sempra Energy Parent’s financial condition, results of operations, cash flows or disclosures.

ASU 2016-02, “Leases” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-01 allows entities to elect a transition practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP.


▪	Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below)


▪	Issue 6 – distributions received from equity method investments



IMPACT FROM ADOPTION OF ASU 2016-15
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Statements of Cash Flows:
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(178	)	$	175		$	(3	)	$	(255	)	$	350		$	95

Cash flows from investing activities:
Dividends received from subsidiaries⁽¹⁾	175			(175		)	—			350			(350		)	—
Net cash provided by (used in) investing activities	627			(175		)	452			(155		)	(350		)	(505		)


⁽¹⁾	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017						2016
	As reported			Recast			As reported			Recast
Sempra Energy Condensed Statements of Operations:
Operation and maintenance	$	(87	)	$	(80	)	$	(81	)	$	(76	)
Other income (expense), net	107			100			(2		)	(7		)

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA (Tables)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Prior Period Adjustments

These reclassifications and related disclosures had no effect on our financial position as of December 31, 2016 and are intended to provide additional clarity into the financial position of Sempra Energy, SDG&E and SoCalGas. The following tables summarize the balance sheet line items affected by these reclassifications:



SEMPRA ENERGY CONSOLIDATED – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Regulatory assets	$	—	$	348
Greenhouse gas allowances	—		40
Regulatory balancing accounts – undercollected	259		—
Other	271		142
Other assets:
Greenhouse gas allowances	—		295
Sundry	815		520
Current liabilities:
Regulatory liabilities	—		122
Greenhouse gas obligations	—		40
Regulatory balancing accounts – overcollected	122		—
Other	557		517
Deferred credits and other liabilities:
Regulatory liabilities	—		2,876
Greenhouse gas obligations	—		171
Regulatory liabilities arising from removal obligations	2,697		—
Deferred credits and other	1,523		1,173



SDG&E – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Regulatory assets	$	81	$	340
Greenhouse gas allowances	—		16
Regulatory balancing accounts – net undercollected	259		—
Other	19		3
Other assets:
Regulatory assets	—		2,012
Greenhouse gas allowances	—		182
Deferred taxes recoverable in rates	1,014		—
Other regulatory assets	998		—
Sundry	358		176
Current liabilities:
Greenhouse gas obligations	—		16
Other	82		66
Deferred credits and other liabilities:
Regulatory liabilities	—		1,725
Greenhouse gas obligations	—		72
Regulatory liabilities arising from removal obligations	1,725		—
Deferred credits and other	421		349



SOCALGAS – BALANCE SHEET RECLASSIFICATIONS AT DECEMBER 31, 2016
(Dollars in millions)
	As previously presented		As currently presented
Current assets:
Greenhouse gas allowances	$	—	$	24
Other	63		39
Other assets:
Regulatory assets	—		1,331
Greenhouse gas allowances	—		109
Regulatory assets arising from pension obligations	742		—
Other regulatory assets	589		—
Sundry	399		290
Current liabilities:
Regulatory liabilities	—		122
Greenhouse gas obligations	—		24
Regulatory balancing accounts – net overcollected	122		—
Other	195		171
Deferred credits and other liabilities:
Regulatory liabilities	—		1,151
Greenhouse gas obligations	—		96
Regulatory liabilities arising from removal obligations	972		—
Deferred credits and other	521		246

Schedule of Cash, Cash Equivalents and Restricted Cash



RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
	At December 31,
	2017		2016
Sempra Energy Consolidated:
Cash and cash equivalents	$	288	$	349
Restricted cash, current	62		66
Restricted cash, noncurrent	14		10
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$	364	$	425
SDG&E:
Cash and cash equivalents	$	12	$	8
Restricted cash, current	6		11
Restricted cash, noncurrent	11		1
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$	29	$	20

Schedule Of Receivables Collection Allowances



COLLECTION ALLOWANCES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated:
Allowances for collection of receivables at January 1	$	35	$	32	$	34



Provisions for uncollectible accounts	16			23			20
Write-offs of uncollectible accounts	(18		)	(20		)	(22		)
Allowances for collection of receivables at December 31	$	33		$	35		$	32
SDG&E:
Allowances for collection of receivables at January 1	$	8		$	9		$	7
Provisions for uncollectible accounts	8			6			7
Write-offs of uncollectible accounts	(7		)	(7		)	(5		)
Allowances for collection of receivables at December 31	$	9		$	8		$	9
SoCalGas:
Allowances for collection of receivables at January 1	$	21		$	17		$	17
Provisions for uncollectible accounts	4			14			11
Write-offs of uncollectible accounts	(9		)	(10		)	(11		)
Allowances for collection of receivables at December 31	$	16		$	21		$	17

Schedule of inventory

The components of inventories by segment are as follows:



INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	Natural gas				LNG				Materials and supplies				Total
	2017		2016		2017		2016		2017		2016		2017		2016
SDG&E	$	4	$	2	$	—	$	—	$	101	$	78	$	105	$	80
SoCalGas⁽¹⁾	75		11		—		—		49		47		124		58
Sempra South American Utilities	—		—		—		—		30		27		30		27
Sempra Mexico	—		—		7		6		2		1		9		7
Sempra Renewables	—		—		—		—		5		4		5		4
Sempra LNG & Midstream	30		79		4		3		—		—		34		82
Sempra Energy Consolidated	$	109	$	92	$	11	$	9	$	187	$	157	$	307	$	258


⁽¹⁾	At December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas storage facility leak, which we discuss in Note 15.

Schedule of Property, Plant and Equipment



PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
	PP&E at December 31,				Depreciation rates for years ended December 31,
	2017		2016		2017		2016			2015
SDG&E:
Natural gas operations	$	2,186	$	1,897	2.40	%	2.40	%		2.52	%
Electric distribution	6,975		6,497		3.92		3.86			3.79
Electric transmission⁽¹⁾	5,626		5,152		2.71		2.66			2.62
Electric generation⁽²⁾	2,435		1,932		4.05		4.00			3.89
Other electric⁽³⁾	1,114		1,059		5.54		5.66			5.73
Construction work in progress⁽¹⁾	1,451		1,307		NA		NA			NA
Total SDG&E	19,787		17,844
SoCalGas:
Natural gas operations⁽⁴⁾	15,759		14,428		3.63		3.64			3.83
Other non-utility	32		34		5.28		6.55			3.95
Construction work in progress	981		882		NA		NA			NA
Total SoCalGas	16,772		15,344

					Estimated				Weighted-average
Other operating units and parent⁽⁵⁾:					useful lives				useful life
Land and land rights	416		381		22 to 55 years⁽⁶⁾				33
Machinery and equipment:
Utility electric distribution operations	1,751		1,519		12 to 60 years				52
Generating plants	2,242		1,874		2 to 100 years				31
LNG terminals	1,133		1,129		43 years				43
Pipelines and storage	4,408		3,242		3 to 55 years				43
Other	269		235		1 to 50 years				13
Construction work in progress	691		1,488		NA				NA
Other⁽⁷⁾	639		568		1 to 80 years				33
	11,549		10,436
Total Sempra Energy Consolidated	$	48,108	$	43,624

⁽¹⁾


⁽²⁾	Includes capital lease assets of $757 million and $258 million at December 31, 2017 and 2016, respectively.


⁽³⁾	Includes capital lease assets of $22 million and $21 million at December 31, 2017 and 2016, respectively.


⁽⁴⁾	Includes capital lease assets of $34 million and $32 million at December 31, 2017 and 2016, respectively.


⁽⁵⁾	Includes $145 million and $128 million at December 31, 2017 and 2016, respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas.


⁽⁶⁾	Estimated useful lives are for land rights.


⁽⁷⁾	Includes capital lease assets of $136 million at both December 31, 2017 and 2016, related to a build-to-suit lease.

Accumulated depreciation on our Consolidated Balance Sheets is as follows:



ACCUMULATED DEPRECIATION
(Dollars in millions)
	December 31,
	2017		2016
SDG&E:
Accumulated depreciation:
Electric⁽¹⁾	$	4,193	$	3,873
Natural gas	756		721
Total SDG&E	4,949		4,594
SoCalGas:
Accumulated depreciation of natural gas utility plant in service⁽²⁾	5,352		5,079
Accumulated depreciation – other non-utility	14		13
Total SoCalGas	5,366		5,092
Other operating units and parent and other:
Accumulated depreciation – other⁽³⁾	972		755
Accumulated depreciation of utility electric distribution operations	318		252
	1,290		1,007
Total Sempra Energy Consolidated	$	11,605	$	10,693


⁽¹⁾	Includes accumulated depreciation for capital lease assets of $47 million and $39 million at December 31, 2017 and 2016, respectively. Includes $241 million at December 31, 2017 related to SDG&E’s 92-percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.


⁽²⁾	Includes accumulated depreciation for capital lease assets of $33 million and $31 million at December 31, 2017 and 2016, respectively.


⁽³⁾	Includes $39 million and $33 million at December 31, 2017 and 2016, respectively, of accumulated depreciation for utility plant at Ecogas.

Depreciation expense on our Consolidated Statements of Operations is as follows:



DEPRECIATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,422	$	1,236	$	1,178
SDG&E	621		583		544
SoCalGas	514		474		459

Schedule Of Capitalized Financing Costs

Interest capitalized and AFUDC are as follows:



CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	256	$	236	$	201
SDG&E	85		62		51
SoCalGas	60		55		49

Schedule Of Goodwill

Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows:



GOODWILL
(Dollars in millions)
	Sempra South American Utilities		Sempra Mexico			Sempra LNG & Midstream			Total
Balance at December 31, 2015	$	722	$	25		$	72		$	819
Acquisition of businesses	—		1,590			—			1,590
Sale of business	—		—			(72		)	(72		)
Foreign currency translation⁽¹⁾	27		—			—			27
Balance at December 31, 2016	749		1,615			—			2,364
Acquisition of business – measurement period adjustment	—		(13		)	—			(13		)
Foreign currency translation⁽¹⁾	46		—			—			46
Balance at December 31, 2017	$	795	$	1,602		$	—		$	2,397


⁽¹⁾	We record the offset of this fluctuation to Other Comprehensive Income (Loss).

Schedule Of Other Intangible Assets

Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:



OTHER INTANGIBLE ASSETS
(Dollars in millions)
	Amortization period (years)	December 31,
	Amortization period (years)	2017		2016
Development rights	50	$	322	$	322
Renewable energy transmission and consumption permit	19	154		154



Storage rights	46	138			138
O&M agreement	23	66			—
Other	10 years to indefinite	18			18
		698			632
Less accumulated amortization:
Development rights		(60		)	(53		)
Renewable energy transmission and consumption permit		(8		)	—
Storage rights		(28		)	(25		)
Other		(6		)	(6		)
		(102		)	(84		)
		$	596		$	548

Schedule Of Variable Interest Entities



AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	December 31,
	2017		2016
Cash and cash equivalents	$	4	$	6
Restricted cash	6		11
Inventories	4		3
Other	1		2
Total current assets	15		22
Restricted cash	11		1
Property, plant and equipment, net	321		354
Total assets	$	347	$	377

Current portion of long-term debt	$	10	$	10
Fixed-price contracts and other derivatives	10		13
Other	5		5
Total current liabilities	25		28
Long-term debt	284		293
Fixed-price contracts and other derivatives	3		12
Deferred credits and other	7		7
Noncontrolling interest	28		37
Total liabilities and equity	$	347	$	377



	Years ended December 31,
	2017			2016			2015
Operating expenses
Cost of electric fuel and purchased power	$	(79	)	$	(79	)	$	(83	)
Operation and maintenance	17			29			19
Depreciation and amortization	28			35			26
Total operating expenses	(34		)	(15		)	(38		)
Operating income	34			15			38
Other income	2			—			—
Interest expense	(22		)	(20		)	(19		)
Income (loss) before income taxes/Net Income (loss)	14			(5		)	19
(Earnings) losses attributable to noncontrolling interest	(14		)	5			(19		)
Earnings attributable to common shares	$	—		$	—		$	—



AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
	December 31,
	2017		2016
Cash and cash equivalents	$	23	$	88
Accounts receivable – trade, net	5		3
Inventories	1		—
Other	1		—
Total current assets	30		91
Sundry	2		—
Property, plant and equipment, net	1,412		926
Total assets	1,444		1,017

Accounts payable	42		68
Other	1		7
Total current liabilities	43		75
Asset retirement obligations	40		27
Deferred income taxes	10		—
Deferred credits and other	1		—
Total deferred credits and other liabilities	94		102

Other noncontrolling interests	631		468
Net assets less other noncontrolling interests	$	719	$	447



	Years ended December 31,
	2017			2016
REVENUES
Energy-related businesses	$	61		$	2
EXPENSES
Operation and maintenance	(9		)	(1		)
Depreciation and amortization	(32		)	—
Income before income taxes	20			1
Income tax expense	(4		)	—
Net income	16			1
Losses attributable to noncontrolling interests⁽¹⁾	23			4
Earnings	$	39		$	5

⁽¹⁾Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.

Schedule Of Asset Retirement Obligations

The changes in asset retirement obligations are as follows:



CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra Energy Consolidated						SDG&E						SoCalGas
	2017			2016			2017			2016			2017			2016
Balance as of January 1⁽¹⁾	$	2,553		$	2,255		$	830		$	828		$	1,659		$	1,383
Accretion expense	109			101			39			38			66			61
Liabilities incurred and acquired	34			35			17			—			—			—
Deconsolidation and reclassification⁽²⁾	—			(16		)	—			—			—			—
Payments	(63		)	(47		)	(61		)	(46		)	(2		)	—
Revisions⁽³⁾	244			225			14			10			230			215
Balance at December 31⁽¹⁾	$	2,877		$	2,553		$	839		$	830		$	1,953		$	1,659


⁽¹⁾	Current portions of the obligations for Sempra Energy Consolidated and SoCalGas are included in Other Current Liabilities on the Consolidated Balance Sheets.


⁽²⁾	Deconsolidated $12 million due to the September 2016 sale of EnergySouth and reclassified $4 million to Liabilities Held for Sale, as we discuss in Note 3.


⁽³⁾	In 2017, revised estimates were primarily related to underground natural gas storage facilities and wells at SoCalGas. In 2016, revised estimates were related to changes in the cost of removal rates primarily for natural gas assets based on updated cost studies approved in the 2016 GRC FD.

Schedule Of Changes In Accumulated Other Comprehensive Income By Component

The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests, for the years ended December 31:



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT⁽¹⁾
(Dollars in millions)
	Foreign currency translation adjustments			Financial instruments				Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
Sempra Energy Consolidated:
Balance as of December 31, 2014	$	(322	)		$	(90	)	$	(85	)	$	(497	)

OCI before reclassifications	(260		)		(57		)	(10		)	(327		)
Amounts reclassified from AOCI	—				10			8			18
Net OCI	(260		)		(47		)	(2		)	(309		)
Balance as of December 31, 2015	(582		)		(137		)	(87		)	(806		)

OCI before reclassifications	42				(7		)	(15		)	20
Amounts reclassified from AOCI⁽²⁾	13				19			6			38
Net OCI	55				12			(9		)	58
Balance as of December 31, 2016	(527		)		(125		)	(96		)	(748		)

OCI before reclassifications	107				(4		)	—			103
Amounts reclassified from AOCI	—				7			12			19
Net OCI	107				3			12			122
Balance as of December 31, 2017	$	(420	)		$	(122	)	$	(84	)	$	(626	)
SDG&E:
Balance as of December 31, 2014								$	(12	)	$	(12	)

OCI before reclassifications								3			3
Amounts reclassified from AOCI								1			1
Net OCI								4			4
Balance as of December 31, 2015								(8		)	(8		)

OCI before reclassifications								(1		)	(1		)
Amounts reclassified from AOCI								1			1
Net OCI								—			—
Balance as of December 31, 2016								(8		)	(8		)

OCI before reclassifications								(1		)	(1		)
Amounts reclassified from AOCI								1			1
Net OCI								—			—
Balance as of December 31, 2017								$	(8	)	$	(8	)
SoCalGas:
Balance as of December 31, 2014					$	(14	)	$	(4	)	$	(18	)

OCI before reclassifications					—			(1		)	(1		)
Net OCI					—			(1		)	(1		)
Balance as of December 31, 2015					(14		)	(5		)	(19		)

OCI before reclassifications					—			(4		)	(4		)
Amounts reclassified from AOCI					1			—			1
Net OCI					1			(4		)	(3		)
Balance as of December 31, 2016					(13		)	(9		)	(22		)

Amounts reclassified from AOCI					—			1			1
Net OCI					—			1			1
Balance as of December 31, 2017					$	(13	)	$	(8	)	$	(21	)


⁽¹⁾	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.


⁽²⁾	Total AOCI includes $20 million associated with the October 2016 sale of noncontrolling interests, discussed below in “Sale of Noncontrolling Interests – Sempra Mexico – Follow-On Offerings,” which does not impact the Consolidated Statement of Comprehensive Income.

Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)									Affected line item on Consolidated Statements of Operations
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments⁽¹⁾	$	(4	)	$	17		$	18		Interest Expense
Interest rate instruments	8			10			12			Equity Earnings, Before Income Tax
Interest rate and foreign exchange instruments	—			7			—			Remeasurement of Equity Method Investment
Interest rate and foreign exchange instruments	12			5			13			Equity Earnings, Net of Income Tax
Foreign exchange instruments	(2		)	—			—			Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	9			(6		)	(14		)	Revenues: Energy-Related Businesses
Total before income tax	23			33			29
	(6		)	(6		)	(4		)	Income Tax Expense
Net of income tax	17			27			25
	(10		)	(15		)	(15		)	Earnings Attributable to Noncontrolling Interests
	$	7		$	12		$	10
Pension and other postretirement benefits:
Amortization of actuarial loss⁽²⁾	$	18		$	10		$	14
Amortization of prior service cost⁽²⁾	1			1			—
Total before income tax	19			11			14
	(7		)	(5		)	(6		)	Income Tax Expense
Net of income tax	$	12		$	6		$	8

Total reclassifications for the period, net of tax	$	19		$	18		$	18
SDG&E:
Financial instruments:
Interest rate instruments⁽¹⁾	$	13		$	12		$	12		Interest Expense
	(13		)	(12		)	(12		)	(Earnings) Losses Attributable to Noncontrolling Interest
	$	—		$	—		$	—
Pension and other postretirement benefits:
Amortization of actuarial loss⁽²⁾	$	1		$	1		$	1

Total reclassifications for the period, net of tax	$	1		$	1		$	1
SoCalGas:
Financial instruments:
Interest rate instruments	$	—		$	1		$	1		Interest Expense
	—			—			(1		)	Income Tax Expense
Net of income tax	$	—		$	1		$	—
Pension and other postretirement benefits:
Amortization of prior service cost⁽²⁾	$	1		$	—		$	—

Total reclassifications for the period, net of tax	$	1		$	1		$	—


⁽¹⁾	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.


⁽²⁾	Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).

Schedule Of Noncontrolling Interests



OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
	Percent ownership held by others				Equity held by noncontrolling interests
	December 31,				December 31,
	2017		2016		2017		2016
SDG&E:
Otay Mesa VIE	100	%	100	%	$	28	$	37
Sempra South American Utilities:
Chilquinta Energía subsidiaries⁽¹⁾	22.9 - 43.4		23.1 - 43.4		24		22
Luz del Sur	16.4		16.4		189		173
Tecsur	9.8		9.8		4		4
Sempra Mexico:
IEnova⁽²⁾	33.6		33.6		1,532		1,524
Sempra Renewables:
Tax equity arrangements – wind⁽³⁾	NA		NA		181		92
Tax equity arrangements – solar⁽³⁾	NA		NA		450		376
Sempra LNG & Midstream:
Bay Gas	9.1		9.1		28		27
Liberty Gas Storage, LLC	23.3		23.3		14		14
Southern Gas Transmission Company⁽⁴⁾	—		49.0		—		1
Total Sempra Energy					$	2,450	$	2,270


⁽¹⁾	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.


⁽²⁾	IEnova has a subsidiary with a 10-percent noncontrolling interest held by others. The equity held by noncontrolling interests is negligible at December 31, 2017 and 2016.


⁽³⁾	Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.


⁽⁴⁾	We sold our assets in Southern Gas Transmission Company in August 2017.

Schedule Of Utilities Revenues



TOTAL UTILITIES REVENUES AT SEMPRA ENERGY CONSOLIDATED⁽¹⁾
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Electric revenues	$	5,415	$	5,211	$	5,158
Natural gas revenues	4,361		4,050		4,096
Total	$	9,776	$	9,261	$	9,254


⁽¹⁾	Excludes intercompany revenues.

Schedule of Related Party Transactions

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:



AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$	37		$	26

Sempra South American Utilities⁽¹⁾:
Eletrans – 4% Note⁽²⁾	$	103		$	96
Other related party receivables	1			1
Sempra Mexico⁽¹⁾:
IMG – Note due March 15, 2022⁽³⁾	487			—
DEN – Notes due November 14, 2018⁽⁴⁾	—			90
Energía Sierra Juárez – Note⁽⁵⁾	7			14
Total due from unconsolidated affiliates – noncurrent	$	598		$	201

Total due to various unconsolidated affiliates – current	$	(7	)	$	(11	)

Sempra Mexico⁽¹⁾:
Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021⁽⁶⁾	$	(35	)	$	—
SDG&E:
Sempra Energy⁽⁷⁾	$	—		$	3
Various affiliates	—			1
Total due from unconsolidated affiliates – current	$	—		$	4

Sempra Energy	$	(30	)	$	—
SoCalGas	(4		)	(8		)
Various affiliates	(6		)	(7		)
Total due to unconsolidated affiliates – current	$	(40	)	$	(15	)

Income taxes due from Sempra Energy⁽⁸⁾	$	27		$	159
SoCalGas:
Total due from unconsolidated affiliates – current – SDG&E	$	4		$	8

Total due to unconsolidated affiliates – current – Sempra Energy	$	(35	)	$	(28	)

Income taxes due from Sempra Energy⁽⁸⁾	$	10		$	5


⁽¹⁾	Amounts include principal balances plus accumulated interest outstanding.


⁽²⁾	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, comprising joint ventures of Chilquinta Energía.


⁽³⁾	Mexican peso-denominated revolving line of credit for up to $14.0 billion Mexican pesos or approximately $718 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (9.87 percent at December 31, 2017), to finance construction of the natural gas marine pipeline.


⁽⁴⁾	Four U.S. dollar-denominated loans, at a variable interest rate based on the 30-day LIBOR plus 450 bps (5.27 percent at December 31, 2016), to finance the Los Ramones Norte pipeline project. In November 2017, IEnova acquired the remaining 50-percent interest in DEN and DEN became a wholly owned, consolidated subsidiary of IEnova.


⁽⁵⁾	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps (7.94 percent at December 31, 2017) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.


⁽⁶⁾	U.S. dollar-denominated loan, at a variable interest rate based on 6-month LIBOR plus 290 bps (4.74 percent at December 31, 2017).


⁽⁷⁾	At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent.


⁽⁸⁾	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.

Revenues and cost of sales from unconsolidated affiliates are as follows:



REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Revenues:
Sempra Energy Consolidated	$	43	$	25	$	26
SDG&E	8		7		10
SoCalGas	74		76		75
Cost of Sales:
Sempra Energy Consolidated	$	47	$	72	$	107
SDG&E	71		64		49

Schedule Of Other Income (Expense)

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



OTHER INCOME, NET
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	168		$	116		$	107
Investment gains⁽¹⁾	56			23			3
Gains (losses) on interest rate and foreign exchange instruments, net	47			(32		)	(4		)
Foreign currency transaction losses⁽²⁾	(35		)	(1		)	(7		)
Sale of other investments	3			5			11
Electrical infrastructure relocation income	3			10			7
Interest on regulatory balancing accounts, net	3			4			3
Sundry, net	9			7			6
Total	$	254		$	132		$	126
SDG&E:
Allowance for equity funds used during construction	$	63		$	46		$	37
Interest on regulatory balancing accounts, net	3			3			3
Sundry, net	—			1			(4		)
Total	$	66		$	50		$	36
SoCalGas:
Allowance for equity funds used during construction	$	44		$	40		$	36
Interest on regulatory balancing accounts, net	—			1			—
Sundry, net	(8		)	(9		)	(6		)
Total	$	36		$	32		$	30


⁽¹⁾	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Consolidated Statements of Operations.


⁽²⁾	Includes $35 million loss from translation of Mexican peso-denominated loan to IMG JV to U.S. dollars.

NEW ACCOUNTING STANDARDS NEW ACCOUNTING STANDARDS (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncement, Early Adoption

Upon adoption of ASU 2016-15 and ASU 2016-18, the Sempra Energy and SDG&E Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities – other	$	63		$	(1	)	$	62		$	66		$	—		$	66
Changes in other assets	56			(7		)	49			(162		)	(7		)	(169		)
Net cash provided by operating activities	2,319			(8		)	2,311			2,905			(7		)	2,898

Cash flows from investing activities:
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired	(1,582		)	1,582			—			(200		)	200			—
Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired	—			(1,504		)	(1,504		)	—			(198		)	(198		)
Increases in restricted cash	(139		)	139			—			(100		)	100			—
Decreases in restricted cash	175			(175		)	—			93			(93		)	—
Other	—			9			9			1			8			9
Net cash used in investing activities	(4,886		)	51			(4,835		)	(2,885		)	17			(2,868		)

Cash flows from financing activities:
Other	(10		)	(11		)	(21		)	(17		)	(3		)	(20		)
Net cash provided by (used in) financing activities	2,513			(11		)	2,502			(173		)	(3		)	(176		)

Effect of exchange rate changes on cash and cash equivalents	—			—			—			(14		)	14			—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—			(3		)	(3		)	—			(14		)	(14		)

Decrease in cash and cash equivalents	(54		)	54			—			(167		)	167			—
Decrease in cash, cash equivalents, and restricted cash	—			(25		)	(25		)	—			(160		)	(160		)

Cash and cash equivalents, January 1	403			(403		)	—			570			(570		)	—
Cash, cash equivalents and restricted cash, January 1	—			450			450			—			610			610
Cash and cash equivalents, December 31	349			(349		)	—			403			(403		)	—
Cash, cash equivalents and restricted cash, December 31	—			425			425			—			450			450
SDG&E Consolidated Statements of Cash Flows:
Cash flows from operating activities:
Changes in other assets	$	(16	)	$	(4	)	$	(20	)	$	(122	)	$	(3	)	$	(125	)
Net cash provided by operating activities	1,327			(4		)	1,323			1,664			(3		)	1,661

Cash flows from investing activities:
Increases in restricted cash	(49		)	49			—			(39		)	39			—
Decreases in restricted cash	60			(60		)	—			35			(35		)	—
Other	—			6			6			—			5			5
Net cash used in investing activities	(1,319		)	(5		)	(1,324		)	(1,086		)	9			(1,077		)

Cash flows from financing activities:
Other⁽¹⁾	(4		)	(2		)	(6		)	(2		)	(2		)	(4		)
Net cash used in financing activities	(20		)	(2		)	(22		)	(566		)	(2		)	(568		)

(Decrease) increase in cash and cash equivalents	(12		)	12			—			12			(12		)	—
(Decrease) increase in cash, cash equivalents, and restricted cash	—			(23		)	(23		)	—			16			16

Cash and cash equivalents, January 1	20			(20		)	—			8			(8		)	—
Cash, cash equivalents and restricted cash, January 1	—			43			43			—			27			27
Cash and cash equivalents, December 31	8			(8		)	—			20			(20		)	—
Cash, cash equivalents and restricted cash, December 31	—			20			20			—			43			43

⁽¹⁾ Previously labeled “Debt issuance costs.”

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017				2016
	As reported		Recast		As reported		Recast
Sempra Energy Consolidated Statements of Operations:
Operation and maintenance	$	3,117	$	3,096	$	2,970	$	2,976
Other income, net	254		233		132		138
SDG&E Consolidated Statements of Operations:
Operation and maintenance	$	1,020	$	1,024	$	1,048	$	1,062
Operating income	713		709		990		976
Other income, net	66		70		50		64
SoCalGas Statements of Operations:



Operation and maintenance	$	1,479	$	1,474	$	1,385	$	1,391
Operating income	622		627		557		551
Other income, net	36		31		32		38



IMPACT FROM ADOPTION OF ASU 2016-15
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Statements of Cash Flows:
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(178	)	$	175		$	(3	)	$	(255	)	$	350		$	95

Cash flows from investing activities:
Dividends received from subsidiaries⁽¹⁾	175			(175		)	—			350			(350		)	—
Net cash provided by (used in) investing activities	627			(175		)	452			(155		)	(350		)	(505		)


⁽¹⁾	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017						2016
	As reported			Recast			As reported			Recast
Sempra Energy Condensed Statements of Operations:
Operation and maintenance	$	(87	)	$	(80	)	$	(81	)	$	(76	)
Other income (expense), net	107			100			(2		)	(7		)

ACQUISTION AND DIVESTITURE ACTIVITY (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Schedule of Business Acquisitions Table



PURCHASE PRICE ALLOCATIONS
(Dollars in millions)
	IEnova Pipelines			Ventika
	At September 26, 2016⁽¹⁾			At December 14, 2016⁽²⁾
Fair value of business combination:
Cash consideration (fair value of total consideration)	$	1,144		$	310
Fair value of equity interest in IEnova Pipelines immediately prior to acquisition	1,144			—
Total fair value of business combination	$	2,288		$	310

Recognized amounts of identifiable assets acquired and liabilities assumed:
Cash and cash equivalents	$	66		$	—
Restricted cash	—			68
Accounts receivable	39			14
Other current assets	6			1
Other intangible assets	—			154
Deferred income taxes	—			36
Regulatory assets	33			—
Property, plant and equipment	1,248			673
Other noncurrent assets	1			3
Short-term debt	—			(125		)
Accounts payable	(11		)	(1		)
Due to unconsolidated affiliates	(3		)	—
Current portion of long-term debt	(49		)	(7		)
Fixed-price contracts and other derivatives, current	(6		)	(4		)
Other current liabilities	(20		)	(8		)
Long-term debt	(315		)	(478		)
Asset retirement obligations	(5		)	(2		)
Deferred income taxes	(127		)	(120		)
Fixed-price contracts and other derivatives, noncurrent	(19		)	(10		)
Other noncurrent liabilities	(11		)	—
Total identifiable net assets	827			194
Goodwill	1,461			116
Total fair value of business combination	$	2,288		$	310

⁽¹⁾


⁽²⁾	During the fourth quarter of 2017, we received additional information regarding Ventika’s deferred income taxes as of the acquisition date, primarily related to net operating loss carryforwards. As a result, we recorded a measurement period adjustment that resulted in a decrease to goodwill and an increase in deferred income tax assets of $13 million.

Schedule of Proforma Information Table



UNAUDITED PRO FORMA INFORMATION – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Years ended December 31,
	2016		2015
Revenues	$	10,463	$	10,473
Net income	1,145		1,938
Earnings	1,058		1,641

Schedule Of Assets Held for Sale and Deconsolidation of Subsidiaries Table

At December 31, 2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows:



ASSETS HELD FOR SALE AT DECEMBER 31, 2017
(Dollars in millions)
	TdM
Inventories	$	10
Other current assets	59
Property, plant and equipment, net	56
Other noncurrent assets	2
Total assets held for sale	$	127

Accounts payable	$	5
Other current liabilities	38
Asset retirement obligations	5
Other noncurrent liabilities	1
Total liabilities held for sale	$	49

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=65878427&loc=SL51721533-107759

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721665-107760

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=d3e1474-107760

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=d3e1361-107760

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721683-107760

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 360
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-URI http://asc.fasb.org/extlink&oid=84176398&loc=SL51724579-110230

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721675-107760

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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721663-107760

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=84176398&loc=d3e2941-110230

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721673-107760

Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721659-107760

Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721671-107760

Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 205
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-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721677-107760

+ Details

INVESTMENTS IN UNCONSOLIDATED ENTITIES (Tables)

12 Months Ended

Dec. 31, 2017

Schedule Of Equity Method And Other Investments

We provide the carrying value of our investments and earnings (losses) on these investments below:



EQUITY METHOD AND OTHER INVESTMENT BALANCES
(Dollars in millions)
	December 31,
	2017		2016
Sempra South American Utilities:
Eletrans⁽¹⁾	$	16	$	(8	)
Sempra Mexico:
DEN	—		42
Energía Sierra Juárez⁽²⁾	39		38
IMG⁽³⁾	221		100
TAG⁽⁴⁾	364		—
Sempra Renewables:
Wind:
Auwahi Wind	42		41
Broken Bow 2 Wind	32		35
Cedar Creek 2 Wind	72		75
Flat Ridge 2 Wind	255		271
Fowler Ridge 2 Wind	44		43
Mehoopany Wind	89		92
Solar:
California solar partnership	107		113
Copper Mountain Solar 2	35		33
Copper Mountain Solar 3	44		42
Mesquite Solar 1	81		86
Other	12		13
Sempra LNG & Midstream:
Cameron LNG JV⁽⁵⁾	997		997
Parent and other:
RBS Sempra Commodities	67		67
Total equity method investments	2,517		2,080
Other	10		17
Total	$	2,527	$	2,097


⁽¹⁾	Reflects losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the CLF relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018.


⁽²⁾	The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014.


⁽³⁾	The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees, which we discuss below.


⁽⁴⁾	The carrying value of our equity method investment is $130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.


⁽⁵⁾	The carrying value of our equity method investment is $237 million and $190 million higher than the underlying equity in the net assets of the investee at December 31, 2017 and 2016, respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations.



EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Earnings (losses) recorded before income tax:
Sempra Renewables:
Wind:
Auwahi Wind	$	5		$	4		$	4
Broken Bow 2 Wind	(2		)	(2		)	(2		)
Cedar Creek 2 Wind	(2		)	(2		)	(6		)
Flat Ridge 2 Wind	(13		)	(7		)	(12		)
Fowler Ridge 2 Wind	4			4			4
Mehoopany Wind	(1		)	—			(1		)
Solar:
California solar partnership	7			7			6
Copper Mountain Solar 2	5			6			7
Copper Mountain Solar 3	8			8			8
Mesquite Solar 1	18			17			16
Other	—			(1		)	—
Sempra LNG & Midstream:
Cameron LNG JV	5			(2		)	5
Rockies Express Pipeline	—			(26		)	79
Parent and other:
RBS Sempra Commodities	—			—			(4		)
	$	34		$	6		$	104
Earnings (losses) recorded net of income tax⁽¹⁾:
Sempra South American Utilities:
Eletrans	$	4		$	3		$	(4	)
Sempra Mexico:
DEN	(13		)	5			—
Energía Sierra Juárez	—			6			6
IEnova Pipelines	—			64			83
IMG	45			—			—
TAG	6			—			—
	$	42		$	78		$	85


⁽¹⁾	As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our ETR.

Schedule of Summarized Financial Information



SUMMARIZED FINANCIAL INFORMATION
(Dollars in millions)
	Years ended December 31,
	2017⁽¹⁾			2016⁽²⁾			2015
Gross revenues	$	846		$	1,079		$	1,533
Operating expense	(590		)	(726		)	(845		)
Income from operations	256			353			688
Interest expense	(217		)	(127		)	(312		)
Net income/Earnings⁽³⁾	116			252			440



	At December 31,
	2017⁽¹⁾		2016⁽²⁾
Current assets	$	974	$	704
Noncurrent assets	14,087		9,970
Current liabilities	797		629
Noncurrent liabilities	9,809		6,627


⁽¹⁾	On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50-percent interest in DEN, increasing its ownership percentage to 100 percent. At December 31, 2017, DEN is no longer an equity method investment.


⁽²⁾	On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in IEnova Pipelines, increasing its ownership percentage to 100 percent, and on May 9, 2016, Sempra LNG & Midstream sold its 25-percent interest in Rockies Express. At December 31, 2016, IEnova Pipelines and Rockies Express are no longer equity method investments.


⁽³⁾	Except for our investments in South America and Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities



PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
		At December 31, 2017
		Total facility			Commercial paper outstanding⁽¹⁾			Available unused credit
Sempra Energy⁽²⁾		$	1,000		$	—		$	1,000
Sempra Global⁽³⁾		2,335			(931		)	1,404
California Utilities⁽⁴⁾:
	SDG&E	750			(253		)	497
	SoCalGas	750			(116		)	634
	Less: subject to a combined limit of $1 billion for both utilities	(500		)	—			(500		)
		1,000			(369		)	631
Total		$	4,335		$	(1,300	)	$	3,035


⁽¹⁾	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.


⁽²⁾	The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017.


⁽³⁾	Sempra Energy guarantees Sempra Global’s obligations under the credit facility.


⁽⁴⁾	The facility also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at December 31, 2017.



CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar equivalent in millions)
			At December 31, 2017
		Denominated in	Total facility		Amount outstanding				Available unused credit
Sempra South American Utilities⁽¹⁾:
	Peru⁽²⁾	Peruvian sol	$	465	$	(169	)	⁽³⁾	$	296
	Chile	Chilean peso	115		—				115
Sempra Mexico:
	IEnova⁽⁴⁾	U.S. dollar	1,170		(137		)		1,033
Total			$	1,750	$	(306	)		$	1,444

⁽¹⁾ The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021.

⁽²⁾ The Peruvian facilities require a debt to equity ratio of no more than 170 percent, with which we were in compliance at December 31, 2017.

⁽³⁾ Includes bank guarantees of $18 million.

⁽⁴⁾ Five-year revolver expiring in August 2020 with a syndicate of eight lenders.

Schedule Of Long-term Debt

The following tables show the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016
SDG&E
First mortgage bonds (collateralized by plant assets):
Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017	$	—		$	140
1.65% July 1, 2018⁽¹⁾	161			161
3% August 15, 2021	350			350
1.914% payable 2015 through February 2022	161			197
3.6% September 1, 2023	450			450
2.5% May 15, 2026	500			500
6% June 1, 2026	250			250
5.875% January and February 2034⁽¹⁾	176			176
5.35% May 15, 2035	250			250
6.125% September 15, 2037	250			250
4% May 1, 2039⁽¹⁾	75			75
6% June 1, 2039	300			300
5.35% May 15, 2040	250			250
4.5% August 15, 2040	500			500
3.95% November 15, 2041	250			250
4.3% April 1, 2042	250			250
3.75% June 1, 2047	400			—
	4,573			4,349
Other long-term debt:
OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007),
payable 2013 through April 2019 (collateralized by OMEC plant assets)	295			305
Capital lease obligations:
Purchased-power contracts	731			239
Other	1			1
	1,027			545
	5,600			4,894
Current portion of long-term debt	(220		)	(191		)
Unamortized discount on long-term debt	(11		)	(11		)
Unamortized debt issuance costs	(34		)	(34		)
Total SDG&E	5,335			4,658

SoCalGas
First mortgage bonds (collateralized by plant assets):
5.45% April 15, 2018	250			250
1.55% June 15, 2018	250			250
3.15% September 15, 2024	500			500
3.2% June 15, 2025	350			350
2.6% June 15, 2026	500			500
5.75% November 15, 2035	250			250
5.125% November 15, 2040	300			300
3.75% September 15, 2042	350			350
4.45% March 15, 2044	250			250
	3,000			3,000
Other long-term debt (uncollateralized):
1.875% Notes payable 2016 through May 2026⁽¹⁾	4			4
5.67% Notes January 18, 2028	5			5
Capital lease obligations	1			—
	10			9
	3,010			3,009
Current portion of long-term debt	(501		)	—
Unamortized discount on long-term debt	(7		)	(7		)
Unamortized debt issuance costs	(17		)	(20		)
Total SoCalGas	2,485			2,982



LONG-TERM DEBT (CONTINUED)
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy
Other long-term debt (uncollateralized):
2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease⁽²⁾	138			137
Sempra South American Utilities
Other long-term debt (uncollateralized):
Chilquinta Energía – 4.25% Series B Bonds October 30, 2030	205			185
Luz del Sur
Bank loans 5.18% to 6.7% payable 2016 through December 2018	53			75
Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029	415			346
Other bonds at 3.77% to 4.61% payable 2020 through May 2022	6			7
Capital lease obligations	6			6
Sempra Mexico
Other long-term debt (uncollateralized unless otherwise noted):
Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency
swaps effective 2013)	66			63
6.3% Notes February 2, 2023 (4.12% after cross-currency swap)	198			189
Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014),
payable 2016 through December 2026, collateralized by plant assets	314			352
3.75% Notes January 14, 2028	300			—
Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates
(weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable
rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets	468			481
4.875% Notes January 14, 2048	540			—
Sempra Renewables
Other long-term debt (collateralized by project assets):
Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028
except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012⁽¹⁾	77			84
Sempra LNG & Midstream
Other long-term debt (uncollateralized unless otherwise noted):
Notes at 2.87% to 3.51% October 1, 2026⁽¹⁾	20			20
8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee	—			6
	9,405			7,548
Current portion of long-term debt	(706		)	(722		)
Unamortized discount on long-term debt	(13		)	(10		)
Unamortized premium on long-term debt	4			4
Unamortized debt issuance costs	(65		)	(31		)
Total other Sempra Energy	8,625			6,789
Total Sempra Energy Consolidated	$	16,445		$	14,429


⁽¹⁾	Callable long-term debt not subject to make-whole provisions.


⁽²⁾	We discuss this lease in Note 15.

On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses):



NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount		Maturity	Interest payments
Floating Rate⁽¹⁾ Notes due 2019	$	500	July 15, 2019	Quarterly
Floating Rate⁽²⁾ Notes due 2021	700		January 15, 2021	Quarterly
2.400% Senior Notes due 2020	500		February 1, 2020	Semi-annually
2.900% Senior Notes due 2023	500		February 1, 2023	Semi-annually
3.400% Senior Notes due 2028	1,000		February 1, 2028	Semi-annually
3.800% Senior Notes due 2038	1,000		February 1, 2038	Semi-annually
4.000% Senior Notes due 2048	800		February 1, 2048	Semi-annually


⁽¹⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points.


⁽²⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points.

The following table shows the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016

2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease	138			137
	6,737			5,734
Current portion of long-term debt	(500		)	(600		)
Unamortized discount on long-term debt	(13		)	(10		)



Unamortized debt issuance costs	(26		)	(24		)
Total long-term debt	$	6,198		$	5,100

Schedule of Maturities of Long-term Debt



MATURITIES OF LONG-TERM DEBT⁽¹⁾
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra Energy		Total Sempra Energy Consolidated
2018	$	207	$	500	$	705	$	1,412
2019	321		—		1,098		1,419
2020	36		—		997		1,033
2021	385		—		961		1,346
2022	18		—		629		647
Thereafter	3,901		2,509		4,872		11,282
Total	$	4,868	$	3,009	$	9,262	$	17,139


⁽¹⁾	Excludes capital lease obligations, build-to-suit lease, market value adjustments for interest rate swaps, discounts, premiums and debt issuance costs.

Schedule Of Callable Long Term Debt

At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2017 is callable subject to premiums:



CALLABLE LONG-TERM DEBT
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra Energy		Total Sempra Energy Consolidated
Not subject to make-whole provisions	$	412	$	4	$	97	$	513
Subject to make-whole provisions	4,161		3,005		7,058		14,224

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

Reconciliation of net U.S. statutory federal income tax rates to the ETRs is as follows:



RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES

	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Effects of the TCJA	55		—		—
Utility depreciation	6		4		5
Foreign exchange and inflation effects⁽¹⁾	3		(2	)	(2	)
State income taxes, net of federal income tax benefit	1		1		1
Utility repairs expenditures	(6	)	(4	)	(5	)
Tax credits	(4	)	(3	)	(4	)
Self-developed software expenditures	(4	)	(3	)	(3	)
Non-U.S. earnings taxed at lower statutory income tax rates⁽²⁾	(3	)	(3	)	(2	)
Allowance for equity funds used during construction	(3	)	(2	)	(2	)
Resolution of prior years’ income tax items	(2	)	—		(3	)
Share-based compensation	—		(2	)	—
Other, net	3		—		—
Effective income tax rate	81	%	21	%	20	%
SDG&E:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	7		5		4
Effects of the TCJA	5		—		—
State income taxes, net of federal income tax benefit	3		5		5



Repairs expenditures	(8	)	(4	)	(4	)
Self-developed software expenditures	(6	)	(3	)	(3	)
Allowance for equity funds used during construction	(4	)	(2	)	(2	)
Resolution of prior years’ income tax items	(4	)	(1	)	(2	)
Share-based compensation	—		(1	)	—
Other, net	(1	)	(1	)	(1	)
Effective income tax rate	27	%	33	%	32	%
SoCalGas:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	9		9		8
State income taxes, net of federal income tax benefit	3		2		4
Repairs expenditures	(8	)	(9	)	(10	)
Self-developed software expenditures	(5	)	(6	)	(6	)
Allowance for equity funds used during construction	(3	)	(2	)	(2	)
Resolution of prior years’ income tax items	(2	)	2		(3	)
Share-based compensation	—		(1	)	—
Other, net	—		(1	)	(1	)
Effective income tax rate	29	%	29	%	25	%

⁽¹⁾


⁽²⁾	Related to operations in Mexico, Chile and Peru.

Schedule of Impact of Changes in Legislation



EFFECTS OF THE TAX CUTS AND JOBS ACT OF 2017
(Dollars in millions)
	Sempra Energy Consolidated			SDG&E			SoCalGas
Consolidated Balance Sheets:
Decrease in net deferred income tax liabilities due
to remeasurement	$	(2,220	)	$	(1,400	)	$	(972	)
Increase in net regulatory liabilities from remeasurement of
deferred income tax assets and liabilities	$	2,402		$	1,428		$	974

Consolidated Statements of Operations:
Income tax expense related to remeasurement of deferred
income tax assets and liabilities	$	182		$	28		$	2
Income tax expense related to deemed repatriation	328			—			—
U.S. state and non-U.S. withholding tax expense related to
expected future repatriation of foreign earnings	360			—			—
Total increase in income tax expense	$	870		$	28		$	2

Schedule Of Geographic Components Of Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries

The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy Consolidated are as follows:



GEOGRAPHIC COMPONENTS
(Dollars in millions)
	Pretax book income
	Years ended December 31,
	2017		2016		2015
U.S.	$	878	$	773	$	1,189
Non-U.S.	707		1,057		515
Total	$	1,585	$	1,830	$	1,704

Schedule Of Components Of Income Tax Expense

The components of income tax expense are as follows:



INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Current:
U.S. federal	$	—		$	—		$	3
U.S. state	—			1			(24		)
Non-U.S.	116			171			123
Total	116			172			102
Deferred:
U.S. federal	536			78			242
U.S. state	297			9			34
Non-U.S.	327			135			(32		)
Total	1,160			222			244
Deferred investment tax credits	—			(5		)	(5		)
Total income tax expense	$	1,276		$	389		$	341
SDG&E:
Current:
U.S. federal	$	100		$	—		$	12
U.S. state	65			22			77
Total	165			22			89
Deferred:
U.S. federal	29			223			233
U.S. state	(41		)	38			(35		)
Total	(12		)	261			198
Deferred investment tax credits	2			(3		)	(3		)
Total income tax expense	$	155		$	280		$	284
SoCalGas:
Current:
U.S. federal	$	—		$	—		$	(1	)
U.S. state	23			40			12
Total	23			40			11
Deferred:
U.S. federal	144			123			122
U.S. state	(5		)	(18		)	7
Total	139			105			129
Deferred investment tax credits	(2		)	(2		)	(2		)
Total income tax expense	$	160		$	143		$	138

Schedule Of Components Of Deferred Tax Assets And Liabilities

We show the components of deferred income taxes, which reflect the effects of the TCJA, at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below:



DEFERRED INCOME TAXES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	December 31,
	2017		2016
Deferred income tax liabilities:
Differences in financial and tax bases of fixed assets, investments and other assets⁽¹⁾	$	4,233	$	6,111
U.S. state and non-U.S. withholding tax on repatriation of foreign earnings	360		—
Regulatory balancing accounts	376		783
Property taxes	37		63
Other deferred income tax liabilities	117		143
Total deferred income tax liabilities	5,123		7,100
Deferred income tax assets:
Tax credits	1,066		431
Net operating losses	968		2,304
Compensation-related items	199		252
Postretirement benefits	251		434
Other deferred income tax assets	115		87
Accrued expenses not yet deductible	60		112
Deferred income tax assets before valuation allowances	2,659		3,620
Less: valuation allowances	133		31
Total deferred income tax assets	2,526		3,589
Net deferred income tax liability⁽²⁾	$	2,597	$	3,511


⁽¹⁾	In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.


⁽²⁾	At December 31, 2017 and 2016, includes $170 million and $234 million, respectively, recorded as a noncurrent asset and $2,767 million and $3,745 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.



DEFERRED INCOME TAXES – SDG&E AND SOCALGAS
(Dollars in millions)
	SDG&E				SoCalGas
	December 31,				December 31,
	2017		2016		2017		2016
Deferred income tax liabilities:
Differences in financial and tax bases of
utility plant and other assets	$	1,472	$	2,549	$	987	$	1,699
Regulatory balancing accounts	113		379		271		411
Property taxes	26		42		12		21
Other	10		10		1		4
Total deferred income tax liabilities	1,621		2,980		1,271		2,135
Deferred income tax assets:
Net operating losses	—		—		58		83
Tax credits	7		27		15		17
Postretirement benefits	43		98		152		244
Compensation-related items	5		8		25		32
State income taxes	14		—		7		19
Accrued expenses not yet deductible	3		7		12		20
Other	19		11		7		11
Total deferred income tax assets	91		151		276		426
Net deferred income tax liability	$	1,530	$	2,829	$	995	$	1,709

Summary of Tax Credit Carryforwards

The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017.



NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS
(Dollars in millions)
	Unused amount at December 31, 2017		Year expiration begins
Sempra Energy Consolidated:
U.S. federal:
NOLs⁽¹⁾	$	3,145	2031
General business tax credits⁽¹⁾	389		2032
Foreign tax credits⁽²⁾	631		2024
U.S. state⁽²⁾:
NOLs	2,295		2019
General business tax credits	51		2018
Non-U.S.⁽²⁾
NOLs	607		2018
SoCalGas:
U.S. federal⁽¹⁾:
NOLs	$	334	2032
General business tax credits	12		2031


⁽¹⁾	We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.


⁽²⁾	We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.

Summary of Operating Loss Carryforwards

The following table summarizes our unused NOLs and tax credit carryforwards at December 31, 2017.



NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS
(Dollars in millions)
	Unused amount at December 31, 2017		Year expiration begins
Sempra Energy Consolidated:
U.S. federal:
NOLs⁽¹⁾	$	3,145	2031
General business tax credits⁽¹⁾	389		2032
Foreign tax credits⁽²⁾	631		2024
U.S. state⁽²⁾:
NOLs	2,295		2019
General business tax credits	51		2018
Non-U.S.⁽²⁾
NOLs	607		2018
SoCalGas:
U.S. federal⁽¹⁾:
NOLs	$	334	2032
General business tax credits	12		2031


⁽¹⁾	We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.


⁽²⁾	We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.

Summary of Income Tax Contingencies

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:



RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2017			2016			2015
Sempra Energy Consolidated:
Balance at January 1	$	90		$	87		$	117
Increase in prior period tax positions	22			2			10
Decrease in prior period tax positions	(15		)	(2		)	—
Increase in current period tax positions	4			6			8
Settlements with taxing authorities	(12		)	(3		)	(48		)
Balance at December 31	$	89		$	90		$	87
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(77	)	$	(87	)	$	(83	)
increase the effective tax rate⁽¹⁾	20			36			32
SDG&E:
Balance at January 1	$	22		$	20		$	14
Increase in prior period tax positions	9			—			5
Decrease in prior period tax positions	(11		)	—			—
Increase in current period tax positions	—			2			2
Settlements with taxing authorities	(10		)	—			(1		)
Balance at December 31	$	10		$	22		$	20
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(7	)	$	(19	)	$	(16	)
increase the effective tax rate⁽¹⁾	1			13			11
SoCalGas:
Balance at January 1	$	29		$	27		$	19
Increase in prior period tax positions	3			—			2
Decrease in prior period tax positions	—			(2		)	—
Increase in current period tax positions	4			4			6
Settlements with taxing authorities	(1		)	—			—
Balance at December 31	$	35		$	29		$	27
Of December 31 balance, amounts related to tax positions that
if recognized in future years would
decrease the effective tax rate⁽¹⁾	$	(26	)	$	(29	)	$	(27	)
increase the effective tax rate⁽¹⁾	20			24			21


⁽¹⁾	Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible

It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:



POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
	At December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Expiration of statutes of limitations on tax assessments	$	—		$	(2	)	$	(2	)
Potential resolution of audit issues with various
U.S. federal, state and local and non-U.S. taxing authorities	(8		)	(36		)	(32		)
	$	(8	)	$	(38	)	$	(34	)
SDG&E:
Expiration of statutes of limitations on tax assessments	$	—		$	(1	)	$	(1	)
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities	(6		)	(10		)	(8		)
	$	(6	)	$	(11	)	$	(9	)
SoCalGas:
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities	$	(2	)	$	(25	)	$	(22	)

EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Schedule Of Defined Benefit Plans, Change In Benefit Obligation And Fair Value Of Plan Assets



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	3,679		$	3,649		$	922		$	963
Service cost	117			107			21			20
Interest cost	151			160			39			42
Contributions from plan participants	—			—			20			20
Actuarial loss (gain)	286			116			6			(81		)
Benefit payments	(182		)	(217		)	(63		)	(61		)
Divestiture of EnergySouth	—			(61		)	—			(6		)
Plan amendments	1			—			—			—
Special termination benefits	—			—			18			26
Curtailments	(1		)	—			—			—
Settlements	(194		)	(75		)	—			(1		)
Net obligation at December 31	3,857			3,679			963			922

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	2,459			2,484			1,057			1,003
Actual return on plan assets	421			207			185			94
Employer contributions	155			104			10			6
Contributions from plan participants	—			—			20			20
Benefit payments	(182		)	(217		)	(63		)	(61		)
Divestiture of EnergySouth	—			(44		)	—			(4		)
Settlements	(194		)	(75		)	—			(1		)
Fair value of plan assets at December 31	2,659			2,459			1,209			1,057
Funded status at December 31	$	(1,198	)	$	(1,220	)	$	246		$	135
Net recorded (liability) asset at December 31	$	(1,198	)	$	(1,220	)	$	246		$	135



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	935		$	965		$	190		$	165
Service cost	29			29			5			5
Interest cost	38			41			8			7
Contributions from plan participants	—			—			7			7
Actuarial loss (gain)	50			7			(9		)	6
Benefit payments	(83		)	(25		)	(16		)	(14		)
Special termination benefits	—			—			—			14



Settlements	—			(75		)	—			—
Transfer of liability from (to) other plans	2			(7		)	—			—
Net obligation at December 31	971			935			185			190

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	714			752			169			161
Actual return on plan assets	120			59			30			13
Employer contributions	22			3			5			2
Contributions from plan participants	—			—			7			7
Benefit payments	(83		)	(25		)	(16		)	(14		)
Settlements	—			(75		)	—			—
Transfer of assets from other plans	3			—			—			—
Fair value of plan assets at December 31	776			714			195			169
Funded status at December 31	$	(195	)	$	(221	)	$	10		$	(21	)
Net recorded (liability) asset at December 31	$	(195	)	$	(221	)	$	10		$	(21	)



PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	2,343		$	2,255		$	691		$	752
Service cost	76			67			14			14
Interest cost	98			101			29			32
Contributions from plan participants	—			—			13			13
Actuarial loss (gain)	216			77			16			(86		)
Benefit payments	(73		)	(158		)	(44		)	(45		)
Special termination benefits	—			—			18			11
Settlements	(175		)	—			—			—
Transfer of liability from other plans	1			1			—			—
Net obligation at December 31	2,486			2,343			737			691

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	1,579			1,537			870			822
Actual return on plan assets	269			128			151			79
Employer contributions	93			72			3			1
Contributions from plan participants	—			—			13			13
Benefit payments	(73		)	(158		)	(44		)	(45		)
Settlements	(175		)	—			—			—
Transfer of assets from other plans	1			—			—			—
Fair value of plan assets at December 31	1,694			1,579			993			870
Funded status at December 31	$	(792	)	$	(764	)	$	256		$	179
Net recorded (liability) asset at December 31	$	(792	)	$	(764	)	$	256		$	179

Schedule Of Defined Benefit Plans, Amounts Recognized In Balance Sheet

The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31:



PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017			2016
Sempra Energy Consolidated:
Noncurrent assets	$	—		$	—		$	266		$	179
Current liabilities	(69		)	(56		)	(1		)	—
Noncurrent liabilities	(1,129		)	(1,164		)	(19		)	(44		)
Net recorded (liability) asset	$	(1,198	)	$	(1,220	)	$	246		$	135
SDG&E:
Noncurrent assets	$	—		$	—		$	10		$	—
Current liabilities	(13		)	(10		)	—			—
Noncurrent liabilities	(182		)	(211		)	—			(21		)
Net recorded (liability) asset	$	(195	)	$	(221	)	$	10		$	(21	)
SoCalGas:
Noncurrent assets	$	—		$	—		$	256		$	179
Current liabilities	(3		)	(2		)	—			—
Noncurrent liabilities	(789		)	(762		)	—			—
Net recorded (liability) asset	$	(792	)	$	(764	)	$	256		$	179

Schedule Of Defined Benefit Plans, Amounts In Accumulated Other Comprehensive Income

Amounts recorded in AOCI at December 31, 2017 and 2016, net of income tax effects and amounts recorded as regulatory assets, are as follows:



AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2017			2016			2017		2016
Sempra Energy Consolidated:
Net actuarial (loss) gain	$	(84	)	$	(95	)	$	4	$	3
Prior service cost	(4		)	(4		)	—		—
Total	$	(88	)	$	(99	)	$	4	$	3
SDG&E:
Net actuarial loss	$	(8	)	$	(8	)
SoCalGas:
Net actuarial loss	$	(6	)	$	(6	)
Prior service cost	(2		)	(3		)
Total	$	(8	)	$	(9	)

Schedule Of Defined Benefit Plans, Accumulated Benefit Obligation

The accumulated benefit obligation for defined benefit pension plans at December 31, 2017 and 2016 was as follows:



ACCUMULATED BENEFIT OBLIGATION
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	2017		2016		2017		2016		2017		2016
Accumulated benefit obligation	$	3,551	$	3,465	$	930	$	904	$	2,241	$	2,167

Schedule Of Defined Benefit Plans, Pension Plans With Benefit Obligations In Excess Of Plan Assets

The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:



OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	2017		2016
Sempra Energy Consolidated:
Projected benefit obligation	$	3,623	$	3,431
Accumulated benefit obligation	3,334		3,227
Fair value of plan assets	2,659		2,459
SDG&E:
Projected benefit obligation	$	939	$	902
Accumulated benefit obligation	900		874
Fair value of plan assets	776		714
SoCalGas:
Projected benefit obligation	$	2,462	$	2,320
Accumulated benefit obligation	2,220		2,148
Fair value of plan assets	1,694		1,579

Schedule of Net Benefit Costs

The following three tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI

SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Pension benefits

Other postretirement benefits



	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	117		$	107		$	114		$	21		$	20		$	26
Interest cost	151			160			154			39			42			44
Expected return on assets	(161		)	(166		)	(173		)	(66		)	(69		)	(68		)
Amortization of:
Prior service cost (credit)	11			11			11			1			—			(4		)
Actuarial loss (gain)	36			30			38			(4		)	(1		)	—
Settlement and curtailment charges	38			16			4			—			—			—
Special termination benefits	—			—			—			18			26			—
Regulatory adjustment	(42		)	(57		)	(110		)	—			(11		)	12
Total net periodic benefit cost	150			101			38			9			7			10

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss (gain)	—			26			17			(2		)	(2		)	(4		)
Prior service cost	1			—			4			—			—			—
Amortization of actuarial loss	(18		)	(10		)	(14		)	—			—			—
Amortization of prior service cost	(1		)	(1		)	—			—			—			—
Total recognized in OCI	(18		)	15			7			(2		)	(2		)	(4		)
Total recognized in net periodic benefit cost and OCI	$	132		$	116		$	45		$	7		$	5		$	6



NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	29		$	29		$	29		$	5		$	5		$	7
Interest cost	38			41			39			8			7			8
Expected return on assets	(47		)	(49		)	(54		)	(11		)	(12		)	(11		)
Amortization of:
Prior service cost	1			1			8			3			3			3
Actuarial loss (gain)	9			10			2			—			(1		)	—
Settlement charge	—			16			—			—			—			—
Special termination benefits	—			—			—			—			14			—
Regulatory adjustment	(8		)	(45		)	(20		)	—			(14		)	—
Total net periodic benefit cost	22			3			4			5			2			7

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss (gain)	2			1			(6		)	—			—			—
Amortization of actuarial loss	(1		)	(1		)	(1		)	—			—			—
Total recognized in OCI	1			—			(7		)	—			—			—
Total recognized in net periodic benefit cost and OCI	$	23		$	3		$	(3	)	$	5		$	2		$	7



NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2017			2016			2015			2017			2016			2015
NET PERIODIC BENEFIT COST
Service cost	$	76		$	67		$	74		$	14		$	14		$	17
Interest cost	98			101			98			29			32			34
Expected return on assets	(103		)	(103		)	(106		)	(53		)	(56		)	(56		)
Amortization of:



Prior service cost (credit)	9			9			9			(3		)	(4		)	(7		)
Actuarial loss (gain)	19			11			21			(3		)	—			—
Settlement charge	30			—			—			—			—			—
Special termination benefits	—			—			—			18			11			—
Regulatory adjustment	(34		)	(12		)	(90		)	—			3			12
Total net periodic benefit cost	95			73			6			2			—			—

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss	—			4			—			—			—			—
Prior service cost	—			2			2			—			—			—
Amortization of prior service cost	(1		)	—			—			—			—			—
Total recognized in OCI	(1		)	6			2			—			—			—
Total recognized in net periodic benefit cost and OCI	$	94		$	79		$	8		$	2		$	—		$	—

Schedule of Assumptions Used

The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:



WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION
AT DECEMBER 31
	Pension benefits				Other postretirement benefits
	2017		2016		2017		2016
Sempra Energy Consolidated:
Discount rate	3.65	%	4.08	%	3.70	%	4.19	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SDG&E:
Discount rate	3.64	%	4.08	%	3.65	%	4.15	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SoCalGas:
Discount rate	3.65	%	4.10	%	3.70	%	4.20	%
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00



WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
YEARS ENDED DECEMBER 31
	Pension benefits						Other postretirement benefits
	2017		2016		2015		2017		2016		2015
Sempra Energy Consolidated:
Discount rate	4.08	%	4.46	%	4.09	%	4.19	%	4.49	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.47		6.98		6.98
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SDG&E:
Discount rate	4.08	%	4.35	%	4.00	%	4.15	%	4.50	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.91		6.90		6.91
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00
SoCalGas:
Discount rate	4.10	%	4.50	%	4.15	%	4.20	%	4.50	%	4.15	%
Expected return on plan assets	7.00		7.00		7.00		6.37		7.00		7.00
Rate of compensation increase	2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00		2.00-10.00

Schedule of Health Care Cost Trend Rates



ASSUMED HEALTH CARE COST TREND RATES
AT DECEMBER 31
	Other postretirement benefit plans⁽¹⁾
	Pre-65 retirees						Retirees aged 65 years and older
	2017		2016		2015		2017		2016		2015
Health care cost trend rate assumed for next year	7.00	%	8.00	%	8.10	%	5.00	%	5.50	%	5.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	5.00	%	5.00	%	5.00	%	4.50	%	4.50	%	4.50	%
Year the rate reaches the ultimate trend	2022		2022		2022		2022		2022		2022

⁽¹⁾

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

A one-percent change in assumed health care cost trend rates would have had the following effects in 2017:



EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES
(Dollars in millions)
	Sempra Energy Consolidated					SDG&E					SoCalGas
	1%		1%			1%		1%			1%		1%
	increase		decrease			increase		decrease			increase		decrease
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$	5	$	(4	)	$	1	$	—		$	4	$	(3	)
Effect on the health care component of the
accumulated other postretirement
benefit obligations	53		(44		)	3		(2		)	48		(40		)

Schedule Of Defined Benefit Plans, Fair Value Of Plan Assets By Level In Fair Value Hierarchy

The fair values of our pension plan assets by asset category are as follows:



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Equity securities:
Domestic	$	946	$	—	$	946
International	538		—		538
Registered investment companies	102		—		102
Fixed income securities:
Domestic government bonds	242		27		269
International government bonds	—		12		12
Domestic corporate bonds	—		338		338
International corporate bonds	—		64		64
Registered investment companies	—		6		6
Other	—		1		1
Total investment assets in the fair value hierarchy	$	1,828	$	448	2,276
Investments measured at NAV:
Common/collective trusts					384
Private equity funds					4
Total investment assets⁽¹⁾					$	2,664
SDG&E’s proportionate share of investment assets					$	777
SoCalGas’ proportionate share of investment assets					$	1,697

	Fair value at December 31, 2016
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Equity securities:
Domestic	$	884	$	—	$	884
International	522		—		522
Registered investment companies	127		—		127
Fixed income securities:
Domestic government bonds	214		32		246
International government bonds	—		9		9
Domestic corporate bonds	—		346		346
International corporate bonds	—		94		94
Registered investment companies	—		14		14
Total investment assets in the fair value hierarchy	$	1,747	$	495	2,242
Investments measured at NAV:
Common/collective trusts					223
Private equity funds					4
Total investment assets⁽²⁾					$	2,469
SDG&E’s proportionate share of investment assets					$	717
SoCalGas’ proportionate share of investment assets					$	1,585


⁽¹⁾	Excludes cash and cash equivalents of $13 million and accounts payable of $18 million.


⁽²⁾	Excludes cash and cash equivalents of $14 million and accounts payable of $24 million.

The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SoCalGas’ PBOP plans and SDG&E’s PBOP plan trusts are as follows:



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1		Level 2		Total
SDG&E:
Equity securities:
Domestic	$	46	$	—	$	46
International	26		—		26
Registered investment companies	52		—		52
Fixed income securities:
Domestic government bonds	12		1		13
International government bonds	—		1		1
Domestic corporate bonds	—		17		17
International corporate bonds	—		3		3
Registered investment companies	—		17		17
Total investment assets in the fair value hierarchy	136		39		175
Investments measured at NAV – Common/collective trusts					20
Total investment assets⁽¹⁾					195

SoCalGas:
Equity securities:
Domestic	78		—		78
International	44		—		44
Registered investment companies	41		—		41
Fixed income securities:
Domestic government bonds	125		13		138
International government bonds	—		7		7
Domestic corporate bonds	—		164		164
International corporate bonds	—		28		28
Registered investment companies	—		85		85
Total investment assets in the fair value hierarchy	288		297		585
Investments measured at NAV – Common/collective trusts					406
Total investment assets⁽²⁾					991

Other Sempra Energy:
Equity securities:
Domestic	7		—		7
International	5		—		5
Registered investment companies	1		—		1
Fixed income securities:
Domestic government bonds	1		1		2
Domestic corporate bonds	—		2		2
International corporate bonds	—		1		1
Total investment assets in the fair value hierarchy	14		4		18
Investments measured at NAV – Common/collective trusts					2
Private equity funds					1
Total other Sempra Energy investment assets					21

Total Sempra Energy Consolidated investment assets in the fair value hierarchy	$	438	$	340
Total Sempra Energy Consolidated investment assets⁽³⁾					$	1,207


⁽¹⁾	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.


⁽²⁾	Excludes cash and cash equivalents of $4 million and accounts payable of $2 million held in SoCalGas PBOP plan trusts.


⁽³⁾	Excludes cash and cash equivalents of $5 million and accounts payable of $3 million at Sempra Energy Consolidated.



FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2016
	Level 1		Level 2		Total
SDG&E:
Equity securities:
Domestic	$	41	$	—	$	41
International	24		—		24
Registered investment companies	46		—		46
Fixed income securities:
Domestic government bonds	10		1		11
Domestic corporate bonds	—		16		16
International corporate bonds	—		3		3
Registered investment companies	—		17		17
Total investment assets in the fair value hierarchy	121		37		158
Investments measured at NAV – Common/collective trusts					11
Total investment assets⁽¹⁾					169

SoCalGas:
Equity securities:
Domestic	130		—		130
International	77		—		77
Registered investment companies	46		—		46
Fixed income securities:
Domestic government bonds	52		8		60
International government bonds	—		2		2
Domestic corporate bonds	—		94		94
International corporate bonds	—		28		28
Registered investment companies	—		47		47
Total investment assets in the fair value hierarchy	305		179		484
Investments measured at NAV – Common/collective trusts					386
Total investment assets⁽²⁾					870

Other Sempra Energy:
Equity securities:
Domestic	6		—		6
International	3		—		3
Fixed income securities:
Domestic government bonds	1		—		1
International government bonds	—		1		1
Domestic corporate bonds	—		2		2
International corporate bonds	—		1		1
Registered investment companies	—		1		1
Total investment assets in the fair value hierarchy	10		5		15
Investments measured at NAV – Common/collective trusts					3
Total other Sempra Energy investment assets					18

Total Sempra Energy Consolidated investment assets in the fair value hierarchy	$	436	$	221
Total Sempra Energy Consolidated investment assets⁽³⁾					$	1,057


⁽¹⁾	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.


⁽²⁾	Excludes cash and cash equivalents of $4 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts.


⁽³⁾	Excludes cash and cash equivalents of $5 million and accounts payable of $5 million at Sempra Energy Consolidated.

Schedule Of Defined Benefit Plans, Estimated Future Employer Contributions In Next Fiscal Year

We expect to contribute the following amounts to our pension and PBOP plans in 2018:



EXPECTED CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Pension plans	$	226	$	48	$	113
Other postretirement benefit plans	9		3		2

Schedule of Expected Benefit Payments

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.



EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	Pension benefits		Other postretirement benefits		Pension benefits		Other postretirement benefits		Pension benefits		Other postretirement benefits
2018	$	351	$	52	$	90	$	10	$	192	$	38
2019	304		52		76		10		188		39
2020	294		54		74		10		179		40
2021	285		53		71		11		173		40
2022	273		53		68		11		172		40
2023-2027	1,217		262		314		52		782		197

Schedule Of Defined Benefit Plans Contributions



EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	2017		2016		2015
Sempra Energy Consolidated	$	41	$	42	$	43
SDG&E	14		15		17
SoCalGas	22		22		21

SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Schedule Of Share-based Compensation Expense

Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:



SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Sempra Energy Consolidated:
Share-based compensation expense, before income taxes	$	78		$	46		$	48
Income tax benefit	(31		)	(18		)	(19		)
	$	47		$	28		$	29

Capitalized share-based compensation cost	$	9		$	7		$	6
Excess income tax benefit	$	—		$	(34	)	$	—
SDG&E:
Share-based compensation expense, before income taxes	$	13		$	7		$	8
Income tax benefit	(5		)	(3		)	(3		)
	$	8		$	4		$	5

Capitalized share-based compensation cost	$	5		$	4		$	4
Excess income tax benefit	$	—		$	(7	)	$	—
SoCalGas:
Share-based compensation expense, before income taxes	$	17		$	8		$	10
Income tax benefit	(7		)	(3		)	(4		)
	$	10		$	5		$	6



Capitalized share-based compensation cost	$	4	$	3		$	2
Excess income tax benefit	$	—	$	(4	)	$	—

Schedule Of Non-qualified Stock Options

The following table shows a summary of non-qualified stock options at December 31, 2017 and activity for the year then ended:



NON-QUALIFIED STOCK OPTIONS

	Common shares under option		Weighted- average exercise price		Weighted- average remaining contractual term (in years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2017	360,255		$	52.46
Exercised	(164,454	)	$	55.04
Outstanding at December 31, 2017	195,801		$	50.30	1.5	$	11

Vested at December 31, 2017	195,801		$	50.30	1.5	$	11
Exercisable at December 31, 2017	195,801		$	50.30	1.5	$	11

Schedule Of Restricted Stock Awards And Units Valuation Assumptions

Below are key assumptions for awards granted in 2017, 2016 and 2015 for Sempra Energy:



KEY ASSUMPTIONS FOR AWARDS GRANTED

	Years ended December 31,
	2017		2016		2015
Risk-free rate of return	1.5	%	1.3	%	1.1	%
Stock price volatility	17		16		14

Schedule Of Restricted Stock Units

We provide below a summary of Sempra Energy’s RSUs as of December 31, 2017 and the activity during the year.



RESTRICTED STOCK UNITS

	Performance-based restricted stock units				Service-based restricted stock units
	Units		Weighted- average grant-date fair value		Units		Weighted- average grant-date fair value
Nonvested at January 1, 2017	1,954,322		$	88.58	305,736		$	94.68
Granted	424,760		$	110.54	93,619		$	101.88
Vested	(637,577	)	$	57.42	(108,880	)	$	79.61
Forfeited	(39,888	)	$	103.17	(4,580	)	$	97.84
Nonvested at December 31, 2017⁽¹⁾	1,701,617		$	105.84	285,895		$	98.81
Expected to vest at December 31, 2017	1,670,885		$	105.38	282,106		$	98.65

⁽¹⁾

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Volumes Table

We summarize net energy derivative volumes at December 31, 2017 and 2016 as follows:



NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
		December 31,
Commodity	Unit of measure	2017	2016
California Utilities:
SDG&E:
Natural gas	MMBtu	39	48
Electricity	MWh	3	4
Congestion revenue rights	MWh	59	48
SoCalGas – natural gas	MMBtu	—	1

Energy-Related Businesses:
Sempra LNG & Midstream – natural gas	MMBtu	3	31
Sempra Mexico – natural gas	MMBtu	4	—

Notional Amounts Of Interest Rate Derivatives Table

At December 31, 2017 and 2016, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:



FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	December 31, 2017			December 31, 2016
	Notional amount		Maturities	Notional amount		Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$	408	2018-2023	$	408	2017-2023
Other foreign currency derivatives⁽¹⁾	345		2018-2019	86		2017-2018


⁽¹⁾	In the first quarter of 2018, we entered into foreign currency derivatives with notional amounts totaling $650 million that expire between December 2018 and January 2019.

At December 31, 2017 and 2016, the net notional amounts of our interest rate derivatives, excluding joint ventures, were:



INTEREST RATE DERIVATIVES
(Dollars in millions)
	December 31, 2017			December 31, 2016
	Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges⁽¹⁾	$	861	2018-2032	$	924	2017-2032
SDG&E:
Cash flow hedge⁽¹⁾	295		2018-2019	305		2017-2019


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

Derivative Instruments on the Consolidated Balance Sheet Table

The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets at December 31, 2017 and 2016, including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions.



DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017
	Current assets: Fixed-price contracts and other derivatives⁽¹⁾			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives⁽²⁾			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments⁽³⁾	$	5		$	2		$	(51	)	$	(165	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	—			—			(1		)	—
Commodity contracts not subject to rate recovery	81			8			(72		)	(6		)
Associated offsetting commodity contracts	(67		)	(5		)	67			5
Commodity contracts subject to rate recovery	28			101			(65		)	(120		)
Associated offsetting commodity contracts	—			(1		)	—			1
Associated offsetting cash collateral	—			—			19			4
Net amounts presented on the balance sheet	47			105			(103		)	(281		)
Additional cash collateral for commodity contracts not subject to rate recovery	2			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	17			—			—			—
Total⁽⁴⁾	$	66		$	105		$	(103	)	$	(281	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments⁽³⁾	$	—		$	—		$	(10	)	$	(3	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	26			101			(63		)	(120		)
Associated offsetting commodity contracts	—			(1		)	—			1
Associated offsetting cash collateral	—			—			19			4
Net amounts presented on the balance sheet	26			100			(54		)	(118		)
Additional cash collateral for commodity contracts subject to rate recovery	16			—			—			—
Total⁽⁴⁾	$	42		$	100		$	(54	)	$	(118	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	2		$	—		$	(2	)	$	—
Net amounts presented on the balance sheet	2			—			(2		)	—
Additional cash collateral for commodity contracts subject to rate recovery	1			—			—			—
Total	$	3		$	—		$	(2	)	$	—


⁽¹⁾	Included in Current Assets: Other for SoCalGas.


⁽²⁾	Included in Current Liabilities: Other for SoCalGas.


⁽³⁾	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.


⁽⁴⁾	Normal purchase contracts previously measured at fair value are excluded.



DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2016
	Current assets: Fixed-price contracts and other derivatives⁽¹⁾			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives⁽²⁾			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments⁽³⁾	$	7		$	2		$	(24	)	$	(228	)
Commodity contracts not subject to rate recovery	—			—			(14		)	—
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	248			36			(254		)	(28		)
Associated offsetting commodity contracts	(242		)	(27		)	242			27
Associated offsetting cash collateral	—			(1		)	16			1
Commodity contracts subject to rate recovery	37			73			(57		)	(150		)
Associated offsetting commodity contracts	(9		)	(1		)	9			1
Associated offsetting cash collateral	—			—			5			13
Net amounts presented on the balance sheet	41			82			(77		)	(364		)
Additional cash collateral for commodity contracts not subject to rate recovery	10			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	32			—			—			—
Total⁽⁴⁾	$	83		$	82		$	(77	)	$	(364	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments⁽³⁾	$	—		$	—		$	(13	)	$	(12	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	33			73			(51		)	(150		)
Associated offsetting commodity contracts	(6		)	(1		)	6			1
Associated offsetting cash collateral	—			—			3			13
Net amounts presented on the balance sheet	27			72			(55		)	(148		)
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	30			—			—			—
Total⁽⁴⁾	$	58		$	72		$	(55	)	$	(148	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	4		$	—		$	(6	)	$	—
Associated offsetting commodity contracts	(3		)	—			3			—
Associated offsetting cash collateral	—			—			2			—
Net amounts presented on the balance sheet	1			—			(1		)	—
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	2			—			—			—
Total	$	4		$	—		$	(1	)	$	—


⁽¹⁾	Included in Current Assets: Other for SoCalGas.


⁽²⁾	Included in Current Liabilities: Other for SoCalGas.


⁽³⁾	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.


⁽⁴⁾	Normal purchase contracts previously measured at fair value are excluded.

Fair Value Hedge Impact on the Consolidated Statement of Operations Table

effects of derivative instruments designated as fair value hedges on the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015. There were no fair value hedges outstanding during the year ended December 31, 2017.



FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2016			2015
Sempra Energy Consolidated:
Interest rate instruments	Interest Expense	$	3		$	6
Interest rate instruments	Other Income, Net	(2		)	(5		)
Total⁽¹⁾		$	1		$	1


⁽¹⁾	There was no hedge ineffectiveness in 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.

Cash Flow Hedge Impact on the Consolidated Statements Of Operations Table



CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss) recognized in OCI										Pretax gain (loss) reclassified from AOCI into earnings
	Years ended December 31,										Years ended December 31,
	2017			2016			2015			Location	2017			2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments⁽¹⁾	$	19		$	(8	)	$	(18	)	Interest Expense	$	4		$	(17	)	$	(18	)
Interest rate instruments	(25		)	(9		)	(80		)	Equity Earnings, Before Income Tax	(8		)	(10		)	(12		)
Interest rate and foreign exchange instruments	—			—			—			Remeasurement of Equity Method Investment	—			(7		)	—
Interest rate and foreign exchange instruments	(9		)	5			(20		)	Equity Earnings, Net of Income Tax	(12		)	(5		)	(13		)
Foreign exchange instruments	4			4			—			Revenues: Energy- Related Businesses	2			—			—
Commodity contracts not subject to rate recovery	3			(13		)	12			Revenues: Energy- Related Businesses	(9		)	6			14
Total⁽²⁾	$	(8	)	$	(21	)	$	(106	)		$	(23	)	$	(33	)	$	(29	)
SDG&E:
Interest rate instruments⁽¹⁾⁽³⁾	$	(2	)	$	(2	)	$	(6	)	Interest Expense	$	(13	)	$	(12	)	$	(12	)
SoCalGas:
Interest rate instruments	$	—		$	—		$	—		Interest Expense	$	—		$	(1	)	$	(1	)


⁽¹⁾	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.


⁽²⁾	There was $5 million, $4 million and $2 million of losses from ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015, respectively.


⁽³⁾	There was negligible hedge ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015.

Undesignated Derivative Impact on the Consolidated Statements of Operations

The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2017			2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments	Other Income, Net	$	49		$	(32	)	$	(4	)
Foreign exchange instruments	Equity Earnings, Net of Income Tax	1			3			(4		)
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	16			(18		)	42
Commodity contracts not subject to rate recovery	Operation and Maintenance	—			1			(1		)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	54			(53		)	(126		)
Commodity contracts subject to rate recovery	Cost of Natural Gas	(2		)	(4		)	1
Total		$	118		$	(103	)	$	(92	)
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	54		$	(53	)	$	(126	)
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—		$	1		$	(1	)
Commodity contracts subject to rate recovery	Cost of Natural Gas	(2		)	(4		)	1
Total		$	(2	)	$	(3	)	$	—

Recurring Fair Value Measures Table

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]



RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491		$	5	$	—	$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45			9		—		54
Municipal bonds	—			250		—		250
Other securities	—			217		—		217
Total debt securities	45			476		—		521
Total nuclear decommissioning trusts⁽¹⁾	536			481		—		1,017
Interest rate and foreign exchange instruments	—			7		—		7
Commodity contracts not subject to rate recovery	5			12		—		17
Effect of netting and allocation of collateral⁽²⁾	2			—		—		2
Commodity contracts subject to rate recovery	—			2		126		128
Effect of netting and allocation of collateral⁽²⁾	12			—		5		17
Total	$	555		$	502	$	131	$	1,188

Liabilities:
Interest rate and foreign exchange instruments	$	—		$	217	$	—	$	217
Commodity contracts not subject to rate recovery	—			6		—		6
Commodity contracts subject to rate recovery	23			7		154		184
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	230	$	154	$	384

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508		$	—	$	—	$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36			16		—		52
Municipal bonds	—			206		—		206
Other securities	—			141		—		141
Total debt securities	36			363		—		399
Total nuclear decommissioning trusts⁽¹⁾	544			363		—		907
Interest rate and foreign exchange instruments	—			9		—		9
Commodity contracts not subject to rate recovery	—			15		—		15
Effect of netting and allocation of collateral⁽²⁾	2			7		—		9
Commodity contracts subject to rate recovery	1			3		96		100
Effect of netting and allocation of collateral⁽²⁾	27			—		5		32
Total	$	574		$	397	$	101	$	1,072

Liabilities:
Interest rate and foreign exchange instruments	$	—		$	252	$	—	$	252
Commodity contracts not subject to rate recovery	16			11		—		27
Effect of netting and allocation of collateral⁽²⁾	(17		)	—		—		(17		)
Commodity contracts subject to rate recovery	19			8		170		197
Effect of netting and allocation of collateral⁽²⁾	(18		)	—		—		(18		)
Total	$	—		$	271	$	170	$	441


⁽¹⁾	Excludes cash balances and cash equivalents.


⁽²⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491		$	5	$	—	$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45			9		—		54
Municipal bonds	—			250		—		250
Other securities	—			217		—		217
Total debt securities	45			476		—		521
Total nuclear decommissioning trusts⁽¹⁾	536			481		—		1,017
Commodity contracts subject to rate recovery	—			—		126		126
Effect of netting and allocation of collateral⁽²⁾	11			—		5		16
Total	$	547		$	481	$	131	$	1,159

Liabilities:
Interest rate instruments	$	—		$	13	$	—	$	13
Commodity contracts subject to rate recovery	23			5		154		182
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	18	$	154	$	172

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508		$	—	$	—	$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36			16		—		52
Municipal bonds	—			206		—		206
Other securities	—			141		—		141
Total debt securities	36			363		—		399
Total nuclear decommissioning trusts⁽¹⁾	544			363		—		907
Commodity contracts not subject to rate recovery	—			—		—		—
Effect of netting and allocation of collateral⁽²⁾	1			—		—		1
Commodity contracts subject to rate recovery	1			2		96		99
Effect of netting and allocation of collateral⁽²⁾	25			—		5		30
Total	$	571		$	365	$	101	$	1,037

Liabilities:
Interest rate instruments	$	—		$	25	$	—	$	25
Commodity contracts subject to rate recovery	17			7		170		194
Effect of netting and allocation of collateral⁽²⁾	(16		)	—		—		(16		)
Total	$	1		$	32	$	170	$	203


⁽¹⁾	Excludes cash balances and cash equivalents.


⁽²⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at December 31, 2017
	Level 1			Level 2		Level 3			Total
Assets:
Commodity contracts subject to rate recovery	$	—		$	2	$	—		$	2
Effect of netting and allocation of collateral⁽¹⁾	1			—		—			1
Total	$	1		$	2	$	—		$	3
Liabilities:
Commodity contracts subject to rate recovery	$	—		$	2	$	—		$	2
Total	$	—		$	2	$	—		$	2

	Fair value at December 31, 2016
	Level 1			Level 2		Level 3			Total
Assets:
Commodity contracts not subject to rate recovery	$	—		$	—	$	—		$	—
Effect of netting and allocation of collateral⁽¹⁾	1			—		—			1
Commodity contracts subject to rate recovery	—			1		—			1
Effect of netting and allocation of collateral⁽¹⁾	2			—		—			2
Total	$	3		$	1	$	—		$	4
Liabilities:
Commodity contracts subject to rate recovery	$	2		$	1	$	—		$	3
Effect of netting and allocation of collateral⁽¹⁾	(2		)	—		—		—	(2		)
Total	$	—		$	1	$	—		$	1


⁽¹⁾	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Recurring Fair Value Measures Level 3 Rollforward Table



LEVEL 3 RECONCILIATIONS⁽¹⁾
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Balance at January 1	$	(74	)	$	19		$	107
Realized and unrealized gains (losses)	34			(120		)	(134		)
Allocated transmission instruments	6			8			12
Settlements	6			19			34
Balance at December 31	$	(28	)	$	(74	)	$	19
Change in unrealized gains (losses) relating to
instruments still held at December 31	$	30		$	(101	)	$	(27	)

⁽¹⁾ Excludes the effect of contractual ability to settle contracts under master netting agreements.

Schedule of Auction Price Inputs

For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, are in the following ranges:



CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS

Settlement year		Price per MWh
2018	$	(7.25	)	to	$	11.99
2017		(11.88	)	to		6.93
2016		(23.81	)	to		10.23

Fair Value of Financial Instruments Table

The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets at December 31, 2017 and 2016:



FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	December 31, 2017
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates⁽¹⁾	$	604	$	—	$	528	$	96	$	624
Long-term amounts due to unconsolidated affiliates	35		—		32		—		32
Total long-term debt⁽²⁾⁽³⁾	17,138		817		17,134		458		18,409
SDG&E:
Total long-term debt⁽³⁾⁽⁴⁾	$	4,868	$	—	$	5,073	$	295	$	5,368
SoCalGas:
Total long-term debt⁽⁵⁾	$	3,009	$	—	$	3,192	$	—	$	3,192

	December 31, 2016
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates⁽¹⁾	$	184	$	—	$	91	$	84	$	175
Total long-term debt⁽²⁾⁽³⁾	15,068		—		15,455		492		15,947
SDG&E:
Total long-term debt⁽³⁾⁽⁴⁾	$	4,654	$	—	$	4,727	$	305	$	5,032
SoCalGas:
Total long-term debt⁽⁵⁾	$	3,009	$	—	$	3,131	$	—	$	3,131


⁽¹⁾	Excluding accumulated interest outstanding of $29 million and $17 million at December 31, 2017 and 2016, respectively, and excluding foreign currency translation of $35 million on a Mexican peso-denominated loan at December 31, 2017.


⁽²⁾	Before reductions for unamortized discount (net of premium) and debt issuance costs of $143 million and $109 million at December 31, 2017


⁽³⁾	Level 3 instruments include $295 million and $305 million at December 31, 2017 and 2016, respectively, related to Otay Mesa VIE.


⁽⁴⁾	Before reductions for unamortized discount and debt issuance costs of $45 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $732 million and $240 million at December 31, 2017 and 2016, respectively.


⁽⁵⁾	Before reductions for unamortized discount and debt issuance costs of $24 million and $27 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $1 million at December 31, 2017.

Fair Value Measurements, Nonrecurring Table

The following table summarizes significant inputs impacting our non-recurring fair value measures:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Estimated

fair

value

Valuation technique

Fair

value

hierarchy

% of

fair value

measurement

Inputs used to

develop

measurement

Range of

inputs

Investment in IEnova Pipelines

1,144

⁽¹⁾

Market approach

Level 2

100%

Equity sale price

100%

TdM

145

⁽²⁾

Market approach

Level 2

100%

Purchase price offers

100%

TdM

⁽³⁾

Market approach

Level 2

100%

Purchase price offer

100%

Investment in
Rockies Express

440

⁽⁴⁾

Market approach

Level 2

100%

Equity sale price

100%


⁽¹⁾	At measurement date of September 26, 2016, immediately prior to acquiring a 100-percent ownership interest in IEnova Pipelines.


⁽²⁾	At measurement date of September 29, 2016.


⁽³⁾	At measurement date of June 30, 2017. At December 31, 2017, TdM has a carrying value of $78 million, reflecting subsequent business activity, and is classified as held for sale.


⁽⁴⁾	At measurement date of March 29, 2016. On May 9, 2016, Sempra LNG & Midstream sold its equity interest in Rockies Express.

PREFERRED STOCK (Tables)

12 Months Ended

Dec. 31, 2017

Schedule Of Preferred Stock

At December 31, 2017 and 2016, SoCalGas has the following preferred stock outstanding:



PREFERRED STOCK OUTSTANDING
(Dollars in millions, except per share amounts)
	December 31,
	2017			2016
$25 par value, authorized 1,000,000 shares:
6% Series, 79,011 shares outstanding	$	3		$	3
6% Series A, 783,032 shares outstanding	19			19
SoCalGas - Total preferred stock	22			22
Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises	(2		)	(2		)
Sempra Energy - Total preferred stock of subsidiary	$	20		$	20

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Schedule Of Earnings Per Share Computations



EARNINGS PER SHARE COMPUTATIONS AND DIVIDENDS DECLARED
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2017		2016		2015
Numerator:
Earnings/Income attributable to common shares	$	256	$	1,370	$	1,349

Denominator:
Weighted-average common shares outstanding for basic EPS⁽¹⁾	251,545		250,217		248,249
Dilutive effect of stock options, RSAs and RSUs⁽²⁾	755		938		2,674
Weighted-average common shares outstanding for diluted EPS	252,300		251,155		250,923

EPS:
Basic	$	1.02	$	5.48	$	5.43
Diluted	$	1.01	$	5.46	$	5.37

Dividends declared per share of common stock⁽³⁾	$	3.29	$	3.02	$	2.80


⁽¹⁾	Includes average fully vested RSUs held in our Deferred Compensation Plan of 609 in 2017, 568 in 2016 and 491 in 2015. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.


⁽²⁾	Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8, dilutive RSUs may vary widely from period-to-period.


⁽³⁾	Our board of directors has the discretion to determine the payment and amount of future dividends.

Schedule Of Common Stock Activity

The following table provides common stock activity for the years ended December 31, 2017, 2016 and 2015.



COMMON STOCK ACTIVITY

	Years ended December 31,
	2017		2016		2015
Common shares outstanding, January 1	250,152,514		248,298,080		246,330,884
RSUs vesting⁽¹⁾	362,022		1,363,555		1,499,062
Stock options exercised	164,454		167,742		227,815
Savings plan issuance	567,428		653,607		652,631
Common stock investment plan⁽²⁾	254,047		266,056		249,665
Issuance of RSUs held in our Deferred Compensation Plan	7,811		—		—
Shares repurchased⁽³⁾	(149,299	)	(596,526	)	(661,977	)
Common shares outstanding, December 31	251,358,977		250,152,514		248,298,080


⁽¹⁾	Includes dividend equivalents.


⁽²⁾	Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.


⁽³⁾	From time to time, we purchase shares of our common stock or units from long-term incentive plan participants who elect to sell to us a sufficient number of vested RSAs or RSUs to meet minimum statutory tax withholding requirements.

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Nuclear Decommissioning Trusts

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies⁽¹⁾	$	54	$	—	$	—		$	54
Municipal bonds⁽¹⁾	245		7		(2		)	250
Other securities⁽²⁾	215		3		(1		)	217
Total debt securities	514		10		(3		)	521
Equity securities	171		326		(1		)	496
Cash and cash equivalents	16		—		—			16
Total	$	701	$	336	$	(4	)	$	1,033
At December 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	$	52	$	—	$	—		$	52
Municipal bonds	203		4		(1		)	206
Other securities	141		2		(2		)	141
Total debt securities	396		6		(3		)	399
Equity securities	143		366		(1		)	508
Cash and cash equivalents	119		—		—			119
Total	$	658	$	372	$	(4	)	$	1,026


⁽¹⁾	Maturity dates are 2018-2048.


⁽²⁾	Maturity dates are 2018-2064.

Schedule of Securities Sold

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



SALES OF SECURITIES
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
Proceeds from sales⁽¹⁾	$	1,314		$	1,134		$	577
Gross realized gains	157			111			29
Gross realized losses	(14		)	(29		)	(15		)


⁽¹⁾	Excludes securities that are held to maturity.

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

+ References + Details

REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Regulatory Assets [Table Text Block]

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.



REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2017			2016
SDG&E:
Fixed-price contracts and other derivatives	$	96		$	141
Costs related to SONGS plant closure⁽¹⁾	—			183
Costs related to wildfire litigation	—			353
Deferred income taxes (refundable) recoverable in rates	(281		)	1,014
Pension and other postretirement benefit plan obligations	153			210
Removal obligations	(1,846		)	(1,725		)
Unamortized loss on reacquired debt	9			12
Environmental costs	29			48
Legacy meters⁽¹⁾	—			16
Sunrise Powerlink fire mitigation	119			118
Regulatory balancing accounts⁽²⁾
Commodity – electric	82			35
Gas transportation	22			61
Safety and reliability	48			20
Public purpose programs	(70		)	(106		)
Other balancing accounts	233			249
Other regulatory liabilities	(70		)	(2		)
Total SDG&E	(1,476		)	627
SoCalGas:
Pension and other postretirement benefit plan obligations	513			563
Employee benefit costs	45			45
Removal obligations	(924		)	(972		)
Deferred income taxes (refundable) recoverable in rates	(437		)	417
Unamortized loss on reacquired debt	8			10
Environmental costs	22			22
Workers’ compensation	12			10
Regulatory balancing accounts⁽²⁾
Commodity – gas, including transportation	151			207
Safety and reliability	266			230
Public purpose programs	(274		)	(270		)
Other balancing accounts	(114		)	(204		)
Other regulatory (liabilities) assets	(64		)	8
Total SoCalGas	(796		)	66
Sempra Mexico:
Deferred income taxes recoverable in rates	83			71
Total Sempra Energy Consolidated	$	(2,189	)	$	764


⁽¹⁾	Regulatory assets earning a rate of return.


⁽²⁾	At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively.

Schedule of Regulatory Liabilities [Table Text Block]

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.



REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2017			2016
SDG&E:
Fixed-price contracts and other derivatives	$	96		$	141
Costs related to SONGS plant closure⁽¹⁾	—			183
Costs related to wildfire litigation	—			353
Deferred income taxes (refundable) recoverable in rates	(281		)	1,014
Pension and other postretirement benefit plan obligations	153			210
Removal obligations	(1,846		)	(1,725		)
Unamortized loss on reacquired debt	9			12
Environmental costs	29			48
Legacy meters⁽¹⁾	—			16
Sunrise Powerlink fire mitigation	119			118
Regulatory balancing accounts⁽²⁾
Commodity – electric	82			35
Gas transportation	22			61
Safety and reliability	48			20
Public purpose programs	(70		)	(106		)
Other balancing accounts	233			249
Other regulatory liabilities	(70		)	(2		)
Total SDG&E	(1,476		)	627
SoCalGas:
Pension and other postretirement benefit plan obligations	513			563
Employee benefit costs	45			45
Removal obligations	(924		)	(972		)
Deferred income taxes (refundable) recoverable in rates	(437		)	417
Unamortized loss on reacquired debt	8			10
Environmental costs	22			22
Workers’ compensation	12			10
Regulatory balancing accounts⁽²⁾
Commodity – gas, including transportation	151			207
Safety and reliability	266			230
Public purpose programs	(274		)	(270		)
Other balancing accounts	(114		)	(204		)
Other regulatory (liabilities) assets	(64		)	8
Total SoCalGas	(796		)	66
Sempra Mexico:
Deferred income taxes recoverable in rates	83			71
Total Sempra Energy Consolidated	$	(2,189	)	$	764


⁽¹⁾	Regulatory assets earning a rate of return.


⁽²⁾	At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively.

Schedule Of Approved Increase Decrease To Annual Revenue Requirement

Following is a summary of the 2016 earnings impacts from the 2016 GRC FD:



EARNINGS IMPACTS IN 2016 FROM THE 2016 GRC FD
(Dollars in millions)
	SoCalGas						SDG&E
	Pretax earnings (charge)			After-tax earnings (charge)			Pretax earnings (charge)			After-tax earnings (charge)
Adjustments to revenue related to tax
repairs deductions:
2015 memorandum account balance	$	(72	)	$	(43	)	$	(37	)	$	(22	)
True-up of 2012-2014 estimates to actuals	(11		)	(6		)	(15		)	(9		)
Total	$	(83	)	$	(49	)	$	(52	)	$	(31	)

Schedule Of CPUC Cost of Capital Authorized



AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC

SDG&E							SoCalGas
Authorized weighting		Return on rate base		Weighted return on rate base			Authorized weighting		Return on rate base		Weighted return on rate base
45.25	%	4.59	%	2.08	%	Long-Term Debt	45.60	%	4.33	%	1.97	%
2.75		6.22		0.17		Preferred Stock	2.40		6.00		0.14
52.00		10.20		5.30		Common Equity	52.00		10.05		5.23
100.00	%			7.55	%		100.00	%			7.34	%

As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below:



IMPACT OF THE EMBEDDED COST OF DEBT

	SDG&E						SoCalGas
	Cost of debt			Return on rate base			Cost of debt			Return on rate base
Current	5.00		%	7.79		%	5.77		%	8.02		%
Authorized, effective January 1, 2018	4.59		%	7.55		%	4.33		%	7.34		%
Differences	(41	)	bps	(24	)	bps	(144	)	bps	(68	)	bps

Schedule Of FERC Cost Of Capital Table

SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows:



SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC

	Weighting		Return on rate base		Weighted return on rate base
Long-Term Debt	43.44	%	4.21	%	1.83	%
Common Equity	56.56		10.05		5.68
	100.00	%			7.51	%

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule Of Estimated Future Payments Under Natural Gas Contracts

At December 31, 2017, the future estimated payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:



FUTURE ESTIMATED PAYMENTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Storage and transportation		Natural gas⁽¹⁾		Total⁽¹⁾
2018	$	231	$	61	$	292
2019	146		—		146
2020	48		—		48
2021	46		1		47
2022	44		1		45
Thereafter	127		—		127
Total estimated payments	$	642	$	63	$	705


⁽¹⁾	Excludes amounts related to the LNG purchase agreement discussed below.



FUTURE ESTIMATED PAYMENTS – SOCALGAS
(Dollars in millions)
	Transportation		Natural gas		Total
2018	$	108	$	—	$	108
2019	59		—		59
2020	29		—		29
2021	27		1		28
2022	27		1		28
Thereafter	81		—		81
Total estimated payments	$	331	$	2	$	333

Schedule Of Payments Under Natural Gas Contracts



PAYMENTS UNDER NATURAL GAS CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,429	$	1,169	$	1,200
SoCalGas	1,213		966		975

Schedule Of L N G Commitment Amounts

At December 31, 2017, the following LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered:



LNG COMMITMENT AMOUNTS
(Dollars in millions)
2018	$	302
2019	383
2020	391
2021	403
2022	411
Thereafter	2,935
Total	$	4,825

Schedule Of Estimated Future Payments Under Purchased Power Contracts

At December 31, 2017, the future estimated payments under long-term purchased-power contracts are as follows:



FUTURE ESTIMATED PAYMENTS – PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E
2018	$	702	$	577
2019	690		571
2020	631		510
2021	633		510
2022	598		496
Thereafter	5,726		5,457
Total estimated payments⁽¹⁾⁽²⁾	$	8,980	$	8,121


⁽¹⁾	Excludes purchase agreements accounted for as capital leases and amounts related to Otay Mesa VIE, as it is consolidated by Sempra Energy and SDG&E.


⁽²⁾	Includes $5.4 billion of expected payments under purchase agreements accounted for as operating leases at SDG&E, comprising renewable energy PPAs for which there are no future minimum operating lease payments.

Schedule Of Payments Under Purchased Power Contracts

Total payments under purchased-power contracts were as follows:



PAYMENTS UNDER PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	1,694	$	1,667	$	1,573
SDG&E	781		752		715

Schedule Of Operating Leases Rent Expense

Rent expense for operating leases was as follows:



RENT EXPENSE – OPERATING LEASES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated	$	109	$	77	$	78
SDG&E	28		28		27
SoCalGas	43		38		39

Schedule Of Operating Leases Future Minimum Payments Due

At December 31, 2017, the rental commitments payable in future years under all noncancelable operating leases, including estimated payments, are as follows:



FUTURE RENTAL PAYMENTS – OPERATING LEASES
(Dollars in millions)
	2018		2019		2020		2021		2022		Thereafter		Total
Sempra Energy Consolidated:
Future minimum lease payments	$	85	$	57	$	51	$	48	$	42	$	300	$	583
Future estimated rental payments	13		12		12		12		13		46		108
Total future rental commitments	$	98	$	69	$	63	$	60	$	55	$	346	$	691
SDG&E:
Future minimum lease payments	$	22	$	21	$	20	$	19	$	18	$	54	$	154
Future estimated rental payments	2		2		2		2		2		3		13
Total future rental commitments	$	24	$	23	$	22	$	21	$	20	$	57	$	167
SoCalGas:
Future minimum lease payments	$	29	$	25	$	20	$	19	$	13	$	36	$	142
Future estimated rental payments	11		10		10		10		11		43		95
Total future rental commitments	$	40	$	35	$	30	$	29	$	24	$	79	$	237

Schedule Of Capital Leases Future Minimum Payments Present Value Of Net Minimum Payments

At December 31, 2017, the future minimum lease payments and present value of the net minimum lease payments under these capital leases for both Sempra Energy Consolidated and SDG&E are as follows:



FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENTS
(Dollars in millions)
2018	$	192
2019	210
2020	210
2021	210
2022	210
Thereafter	3,299
Total minimum lease payments⁽¹⁾	4,331
Less: estimated executory costs	(502		)
Less: interest⁽²⁾	(2,548		)
Present value of net minimum lease payments⁽³⁾	$	1,281


⁽¹⁾	This amount will be recorded over the lives of the leases as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.


⁽²⁾	Amount necessary to reduce net minimum lease payments to present value at the inception of the leases.

⁽³⁾

Schedule Of Environmental Remediation Costs Capitalized In Period

The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:



CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2017		2016		2015
Sempra Energy Consolidated⁽¹⁾	$	92	$	53	$	64
SDG&E	46		17		24
SoCalGas	45		35		39


⁽¹⁾	In cases of non-wholly owned affiliates, includes only our share.

Schedule Of Environmental Remediation Costs, Status Of Remediation Sites

The table below shows the status at December 31, 2017 of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:



STATUS OF ENVIRONMENTAL SITES

	# Sites complete⁽¹⁾	# Sites in process
SDG&E:
Manufactured-gas sites	3	—
Third-party waste-disposal sites	2	1
SoCalGas:
Manufactured-gas sites	39	3
Third-party waste-disposal sites	5	2


⁽¹⁾	There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

Schedule of Environmental Loss Contingencies by Site

The following table shows our accrued liabilities for environmental matters at December 31, 2017:



ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
	Manufactured- gas sites		Waste disposal sites (PRP)⁽¹⁾		Other hazardous waste sites		Total⁽²⁾
SDG&E⁽³⁾	$	—	$	2	$	2	$	4
SoCalGas⁽⁴⁾	22		1		1		24
Other	—		1		—		1
Total Sempra Energy	$	22	$	4	$	3	$	29


⁽¹⁾	Sites for which we have been identified as a PRP.


⁽²⁾	Includes $9 million, $1 million and $8 million classified as current liabilities, and $20 million, $3 million and $16 million classified as noncurrent liabilities on Sempra Energy’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.


⁽³⁾	Does not include SDG&E’s liability for SONGS marine environment mitigation.


⁽⁴⁾	Does not include SoCalGas’ liability for environmental matters for the natural gas leak at the Aliso Canyon natural gas storage facility. We discuss matters related to the leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

Schedule Of Build To Suit Lease Future Minimum Payments Due

At December 31, 2017, the future minimum lease payments on the lease are as follows:



FUTURE MINIMUM PAYMENTS – BUILD-TO-SUIT LEASE
(Dollars in millions)
2018	$	10
2019	10
2020	11
2021	11
2022	11
Thereafter	234
Total minimum lease payments	$	287

SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2017			2016			2015
REVENUES
SDG&E	$	4,476		$	4,253		$	4,219
SoCalGas	3,785			3,471			3,489
Sempra South American Utilities	1,567			1,556			1,544
Sempra Mexico	1,196			725			669
Sempra Renewables	94			34			36
Sempra LNG & Midstream	540			508			653
Adjustments and eliminations	(1		)	—			(2		)
Intersegment revenues⁽¹⁾	(450		)	(364		)	(377		)
Total	$	11,207		$	10,183		$	10,231
INTEREST EXPENSE
SDG&E	$	203		$	195		$	204
SoCalGas	102			97			84
Sempra South American Utilities	38			38			32
Sempra Mexico	97			13			23
Sempra Renewables	15			4			3
Sempra LNG & Midstream	39			43			72
All other	284			282			263
Intercompany eliminations	(119		)	(119		)	(120		)
Total	$	659		$	553		$	561
INTEREST INCOME
SoCalGas	$	1		$	1		$	4
Sempra South American Utilities	28			21			19
Sempra Mexico	23			6			7



Sempra Renewables	7			5			4
Sempra LNG & Midstream	56			71			75
Intercompany eliminations	(69		)	(78		)	(80		)
Total	$	46		$	26		$	29
DEPRECIATION AND AMORTIZATION
SDG&E	$	670		$	646		$	604
SoCalGas	515			476			461
Sempra South American Utilities	54			49			50
Sempra Mexico	156			77			70
Sempra Renewables	38			6			6
Sempra LNG & Midstream	42			47			49
All other	15			11			10
Total	$	1,490		$	1,312		$	1,250
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	155		$	280		$	284
SoCalGas	160			143			138
Sempra South American Utilities	80			80			67
Sempra Mexico	227			188			11
Sempra Renewables	(226		)	(38		)	(49		)
Sempra LNG & Midstream	(119		)	(80		)	28
All other	999			(184		)	(138		)
Total	$	1,276		$	389		$	341



SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Years ended December 31 or at December 31,
	2017			2016			2015
EARNINGS (LOSSES)
SDG&E	$	407		$	570		$	587
SoCalGas⁽²⁾	396			349			419
Sempra South American Utilities	186			156			175
Sempra Mexico	169			463			213
Sempra Renewables	252			55			63
Sempra LNG & Midstream	150			(107		)	44
All other	(1,304		)	(116		)	(152		)
Total	$	256		$	1,370		$	1,349
ASSETS
SDG&E	$	17,844		$	17,719		$	16,515
SoCalGas	14,159			13,424			12,104
Sempra South American Utilities	4,060			3,591			3,235
Sempra Mexico	8,554			7,542			3,783
Sempra Renewables	2,898			3,644			1,441
Sempra LNG & Midstream	4,872			5,564			5,566
All other	915			475			734
Intersegment receivables	(2,848		)	(4,173		)	(2,228		)
Total	$	50,454		$	47,786		$	41,150
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E	$	1,555		$	1,399		$	1,133
SoCalGas	1,367			1,319			1,352
Sempra South American Utilities	244			194			154
Sempra Mexico	248			330			302
Sempra Renewables	497			835			81
Sempra LNG & Midstream	20			117			87
All other	18			20			47
Total	$	3,949		$	4,214		$	3,156
GEOGRAPHIC INFORMATION
Long-lived assets⁽³⁾:
United States	$	31,487		$	28,351		$	26,132
Mexico	5,363			4,814			3,160
South America	2,180			1,863			1,652
Total	$	39,030		$	35,028		$	30,944
Revenues⁽⁴⁾:
United States	$	8,547		$	8,004		$	8,119
South America	1,567			1,556			1,544
Mexico	1,093			623			568
Total	$	11,207		$	10,183		$	10,231


⁽¹⁾	Revenues for reportable segments include intersegment revenues of $7 million, $74 million, $103 million and $266 million for 2017, $6 million, $76 million, $102 million and $180 million for 2016, and $9 million, $75 million, $101 million and $192 million for 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.


⁽²⁾	After preferred dividends.


⁽³⁾	Includes net PP&E and investments.


⁽⁴⁾	Amounts are based on where the revenue originated, after intercompany eliminations.

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Data [Abstract]

Schedule Of Quarterly Financial Data Table



SDG&E
(Dollars in millions)
	Quarters ended
	March 31			June 30			September 30			December 31
2017:
Operating revenues	$	1,057		$	1,058		$	1,236		$	1,125
Operating expenses	779			817			1,290			877
Operating income (loss)	$	278		$	241		$	(54	)	$	248

Net income (loss)	$	157		$	153		$	(19	)	$	130
(Earnings) losses attributable to noncontrolling interest	(2		)	(4		)	(9		)	1
Earnings (losses) attributable to common shares	$	155		$	149		$	(28	)	$	131
2016:
Operating revenues	$	991		$	992		$	1,209		$	1,061
Operating expenses	755			822			886			800
Operating income	$	236		$	170		$	323		$	261

Net income	$	137		$	87		$	194		$	147
(Earnings) losses attributable to noncontrolling interest	(1		)	13			(11		)	4
Earnings attributable to common shares	$	136		$	100		$	183		$	151



SOCALGAS
(Dollars in millions)
	Quarters ended
	March 31		June 30			September 30		December 31
2017:
Operating revenues	$	1,241	$	770		$	684	$	1,090
Operating expenses	926		675			674		888
Operating income	$	315	$	95		$	10	$	202

Net income	$	203	$	59		$	7	$	128
Dividends on preferred stock	—		(1		)	—		—
Earnings attributable to common shares	$	203	$	58		$	7	$	128
2016:
Operating revenues	$	1,033	$	617		$	686	$	1,135
Operating expenses	739		628			648		899
Operating income (loss)	$	294	$	(11	)	$	38	$	236

Net income	$	199	$	—		$	—	$	151
Dividends on preferred stock	—		(1		)	—		—
Earnings (losses) attributable to common shares	$	199	$	(1	)	$	—	$	151

We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below:



SEMPRA ENERGY
(In millions, except per share amounts)
	Quarters ended
	March 31		June 30		September 30		December 31
2017:
Revenues	$	3,031	$	2,533	$	2,679	$	2,964
Expenses and other income	$	2,276	$	2,118	$	2,664	$	2,564

Net income (loss)	$	452	$	248	$	102	$	(451	)
Earnings (losses) attributable to Sempra Energy	$	441	$	259	$	57	$	(501	)

Basic per-share amounts⁽¹⁾:
Net income (loss)	$	1.80	$	0.99	$	0.41	$	(1.80	)
Earnings (losses) attributable to Sempra Energy	$	1.76	$	1.03	$	0.23	$	(1.99	)
Weighted-average common shares outstanding	251.1		251.4		251.7		251.9

Diluted per-share amounts⁽¹⁾⁽²⁾:
Net income (loss)	$	1.79	$	0.98	$	0.41	$	(1.80	)
Earnings (losses) attributable to Sempra Energy	$	1.75	$	1.03	$	0.22	$	(1.99	)
Weighted-average common shares outstanding	252.2		252.8		253.4		251.9
2016:
Revenues	$	2,622	$	2,156	$	2,535	$	2,870
Expenses and other income	$	2,167	$	2,268	$	1,553	$	2,365

Net income	$	364	$	27	$	719	$	409
Earnings attributable to Sempra Energy	$	353	$	16	$	622	$	379

Basic per-share amounts⁽¹⁾:
Net income	$	1.46	$	0.11	$	2.87	$	1.63
Earnings attributable to Sempra Energy	$	1.41	$	0.06	$	2.48	$	1.51
Weighted-average common shares outstanding	249.7		250.1		250.4		250.6

Diluted per-share amounts⁽¹⁾:
Net income	$	1.45	$	0.11	$	2.85	$	1.62
Earnings attributable to Sempra Energy	$	1.40	$	0.06	$	2.46	$	1.51
Weighted-average common shares outstanding	251.5		252.0		252.4		251.6


⁽¹⁾	Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year.


⁽²⁾	In the quarter ended December 31, 2017, the total weighted-average number of potentially dilutive securities was 0.8 million. However, these securities were not included in the computation of U.S. GAAP losses per common share since to do so would have decreased the loss per share.

SUBSEQUENT EVENTS (Tables)

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Schedule of Conversion Rates of Convertible Debt Issued

The following table illustrates the conversion rate per share of the mandatory convertible preferred stock, subject to certain anti-dilution adjustments:



CONVERSION RATES

Applicable market value per share of our common stock		Conversion rate (number of shares of our common stock to be received upon conversion of each share of mandatory convertible preferred stock)

Greater than $131.075 (which is the threshold appreciation price)		0.7629 shares (approximately equal to $100.00 divided by the threshold appreciation price)
Equal to or less than $131.075 but greater than or equal to $107.00		Between 0.7629 and 0.9345 shares, determined by dividing $100.00 by the applicable market value of our common stock
Less than $107.00 (which is the initial price)		0.9345 shares (approximately equal to $100.00 divided by the initial price)

Schedule of Debt Issued

The following tables show the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016
SDG&E
First mortgage bonds (collateralized by plant assets):
Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017	$	—		$	140
1.65% July 1, 2018⁽¹⁾	161			161
3% August 15, 2021	350			350
1.914% payable 2015 through February 2022	161			197
3.6% September 1, 2023	450			450
2.5% May 15, 2026	500			500
6% June 1, 2026	250			250
5.875% January and February 2034⁽¹⁾	176			176
5.35% May 15, 2035	250			250
6.125% September 15, 2037	250			250
4% May 1, 2039⁽¹⁾	75			75
6% June 1, 2039	300			300
5.35% May 15, 2040	250			250
4.5% August 15, 2040	500			500
3.95% November 15, 2041	250			250
4.3% April 1, 2042	250			250
3.75% June 1, 2047	400			—
	4,573			4,349
Other long-term debt:
OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007),
payable 2013 through April 2019 (collateralized by OMEC plant assets)	295			305
Capital lease obligations:
Purchased-power contracts	731			239
Other	1			1
	1,027			545
	5,600			4,894
Current portion of long-term debt	(220		)	(191		)
Unamortized discount on long-term debt	(11		)	(11		)
Unamortized debt issuance costs	(34		)	(34		)
Total SDG&E	5,335			4,658

SoCalGas
First mortgage bonds (collateralized by plant assets):
5.45% April 15, 2018	250			250
1.55% June 15, 2018	250			250
3.15% September 15, 2024	500			500
3.2% June 15, 2025	350			350
2.6% June 15, 2026	500			500
5.75% November 15, 2035	250			250
5.125% November 15, 2040	300			300
3.75% September 15, 2042	350			350
4.45% March 15, 2044	250			250
	3,000			3,000
Other long-term debt (uncollateralized):
1.875% Notes payable 2016 through May 2026⁽¹⁾	4			4
5.67% Notes January 18, 2028	5			5
Capital lease obligations	1			—
	10			9
	3,010			3,009
Current portion of long-term debt	(501		)	—
Unamortized discount on long-term debt	(7		)	(7		)
Unamortized debt issuance costs	(17		)	(20		)
Total SoCalGas	2,485			2,982



LONG-TERM DEBT (CONTINUED)
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy
Other long-term debt (uncollateralized):
2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease⁽²⁾	138			137
Sempra South American Utilities
Other long-term debt (uncollateralized):
Chilquinta Energía – 4.25% Series B Bonds October 30, 2030	205			185
Luz del Sur
Bank loans 5.18% to 6.7% payable 2016 through December 2018	53			75
Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029	415			346
Other bonds at 3.77% to 4.61% payable 2020 through May 2022	6			7
Capital lease obligations	6			6
Sempra Mexico
Other long-term debt (uncollateralized unless otherwise noted):
Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency
swaps effective 2013)	66			63
6.3% Notes February 2, 2023 (4.12% after cross-currency swap)	198			189
Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014),
payable 2016 through December 2026, collateralized by plant assets	314			352
3.75% Notes January 14, 2028	300			—
Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates
(weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable
rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets	468			481
4.875% Notes January 14, 2048	540			—
Sempra Renewables
Other long-term debt (collateralized by project assets):
Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028
except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012⁽¹⁾	77			84
Sempra LNG & Midstream
Other long-term debt (uncollateralized unless otherwise noted):
Notes at 2.87% to 3.51% October 1, 2026⁽¹⁾	20			20
8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee	—			6
	9,405			7,548
Current portion of long-term debt	(706		)	(722		)
Unamortized discount on long-term debt	(13		)	(10		)
Unamortized premium on long-term debt	4			4
Unamortized debt issuance costs	(65		)	(31		)
Total other Sempra Energy	8,625			6,789
Total Sempra Energy Consolidated	$	16,445		$	14,429


⁽¹⁾	Callable long-term debt not subject to make-whole provisions.


⁽²⁾	We discuss this lease in Note 15.

On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses):



NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount		Maturity	Interest payments
Floating Rate⁽¹⁾ Notes due 2019	$	500	July 15, 2019	Quarterly
Floating Rate⁽²⁾ Notes due 2021	700		January 15, 2021	Quarterly
2.400% Senior Notes due 2020	500		February 1, 2020	Semi-annually
2.900% Senior Notes due 2023	500		February 1, 2023	Semi-annually
3.400% Senior Notes due 2028	1,000		February 1, 2028	Semi-annually
3.800% Senior Notes due 2038	1,000		February 1, 2038	Semi-annually
4.000% Senior Notes due 2048	800		February 1, 2048	Semi-annually


⁽¹⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points.


⁽²⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points.

The following table shows the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016

2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease	138			137
	6,737			5,734
Current portion of long-term debt	(500		)	(600		)
Unamortized discount on long-term debt	(13		)	(10		)



Unamortized debt issuance costs	(26		)	(24		)
Total long-term debt	$	6,198		$	5,100

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT (Tables)

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule of Condensed Statements of Operations



SEMPRA ENERGY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Years ended December 31,
	2017			2016			2015
Interest expense	$	(293	)	$	(277	)	$	(261	)
Operation and maintenance	(87		)	(81		)	(66		)
Other income (expense), net	107			(2		)	7
Income tax benefit	33			181			150
Loss before equity in earnings of subsidiaries	(240		)	(179		)	(170		)
Equity in earnings of subsidiaries, net of income taxes	496			1,549			1,519
Net income/earnings	$	256		$	1,370		$	1,349
Basic earnings per common share	$	1.02		$	5.48		$	5.43
Weighted-average number of shares outstanding (thousands)	251,545			250,217			248,249
Diluted earnings per common share	$	1.01		$	5.46		$	5.37
Weighted-average number of shares outstanding (thousands)	252,300			251,155			250,923

Schedule Of Condensed Statements Of Comprehensive Income



SEMPRA ENERGY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31,
	Pretax amount			Income tax benefit (expense)			Net-of-tax amount
2017:
Net income	$	223		$	33		$	256
Other comprehensive income (loss):
Foreign currency translation adjustments	107			—			107
Financial instruments	2			1			3
Pension and other postretirement benefits	20			(8		)	12
Total other comprehensive income	129			(7		)	122
Comprehensive income	$	352		$	26		$	378
2016:
Net income	$	1,189		$	181		$	1,370
Other comprehensive income (loss):
Foreign currency translation adjustments	42			—			42
Financial instruments	(6		)	11			5
Pension and other postretirement benefits	(13		)	4			(9		)
Total other comprehensive income	23			15			38
Comprehensive income	$	1,212		$	196		$	1,408
2015:
Net income	$	1,199		$	150		$	1,349
Other comprehensive income (loss):
Foreign currency translation adjustments	(260		)	—			(260		)
Financial instruments	(80		)	33			(47		)
Pension and other postretirement benefits	(3		)	1			(2		)
Total other comprehensive loss	(343		)	34			(309		)
Comprehensive income	$	856		$	184		$	1,040

Schedule Of Condensed Balance Sheets



SEMPRA ENERGY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017		December 31, 2016
Assets:
Cash and cash equivalents	$	104	$	12
Due from affiliates	83		73
Income taxes receivable	272		—
Other current assets	6		2
Total current assets	465		87

Investments in subsidiaries	17,924		17,329
Due from affiliates	2		—
Deferred income taxes	1,802		2,570
Other assets	656		592
Total assets	$	20,849	$	20,578

Liabilities and shareholders’ equity:
Current portion of long-term debt	$	500	$	600
Due to affiliates	280		359
Income taxes payable	—		153
Other current liabilities	396		374
Total current liabilities	1,176		1,486

Long-term debt	6,198		5,100
Due to affiliates	300		517
Other long-term liabilities	505		524

Commitments and contingencies (Note 4)

Shareholders’ equity	12,670		12,951
Total liabilities and shareholders’ equity	$	20,849	$	20,578

Schedule of Condensed Statements of Cash Flows



SEMPRA ENERGY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2017			2016⁽¹⁾			2015⁽¹⁾

Net cash provided by (used in) operating activities	$	89		$	(3	)	$	95

Expenditures for property, plant and equipment	(11		)	(5		)	(43		)
Purchase of trust assets	—			—			(5		)
Decrease (increase) in loans to affiliates, net	—			457			(457		)
Expenditures for Merger-related transaction costs	(12		)	—			—
Net cash (used in) provided by investing activities	(23		)	452			(505		)

Common stock dividends paid	(755		)	(686		)	(628		)
Issuances of common stock	47			51			52
Repurchases of common stock	(15		)	(56		)	(74		)
Issuances of long-term debt	1,595			499			1,248
Payments on long-term debt	(600		)	(750		)	—
(Decrease) increase in loans from affiliates, net	(239		)	504			(230		)
Tax benefit related to share-based compensation	—			—			52
Other	(7		)	(3		)	(9		)
Net cash provided by (used in) financing activities	26			(441		)	411

Increase in cash and cash equivalents	92			8			1
Cash and cash equivalents, January 1	12			4			3
Cash and cash equivalents, December 31	$	104		$	12		$	4

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued Merger-related transaction costs	$	31		$	—		$	—
Financing of build-to-suit property	—			—			61
Common dividends issued in stock	53			53			55
Dividends declared but not paid	207			189			174


⁽¹⁾	As adjusted for the retrospective adoption of ASU 2016-15, which we discuss in Note 2.

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017				2016
	As reported		Recast		As reported		Recast
Sempra Energy Consolidated Statements of Operations:
Operation and maintenance	$	3,117	$	3,096	$	2,970	$	2,976
Other income, net	254		233		132		138
SDG&E Consolidated Statements of Operations:
Operation and maintenance	$	1,020	$	1,024	$	1,048	$	1,062
Operating income	713		709		990		976
Other income, net	66		70		50		64
SoCalGas Statements of Operations:



Operation and maintenance	$	1,479	$	1,474	$	1,385	$	1,391
Operating income	622		627		557		551
Other income, net	36		31		32		38



IMPACT FROM ADOPTION OF ASU 2016-15
(Dollars in millions)
	Years ended December 31,
	2016									2015
	As previously reported			Effect of adoption			As adjusted			As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Statements of Cash Flows:
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(178	)	$	175		$	(3	)	$	(255	)	$	350		$	95

Cash flows from investing activities:
Dividends received from subsidiaries⁽¹⁾	175			(175		)	—			350			(350		)	—
Net cash provided by (used in) investing activities	627			(175		)	452			(155		)	(350		)	(505		)


⁽¹⁾	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

In 2018, we expect the adoption of ASU 2017-07 to have the following impact on our Condensed Statements of Operations for the years ended December 31, 2017 and 2016:



EXPECTED IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Years ended December 31,
	2017						2016
	As reported			Recast			As reported			Recast
Sempra Energy Condensed Statements of Operations:
Operation and maintenance	$	(87	)	$	(80	)	$	(81	)	$	(76	)
Other income (expense), net	107			100			(2		)	(7		)

Schedule Of Long-term Debt

The following tables show the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016
SDG&E
First mortgage bonds (collateralized by plant assets):
Bonds at variable rates (1.151% at December 31, 2016) March 9, 2017	$	—		$	140
1.65% July 1, 2018⁽¹⁾	161			161
3% August 15, 2021	350			350
1.914% payable 2015 through February 2022	161			197
3.6% September 1, 2023	450			450
2.5% May 15, 2026	500			500
6% June 1, 2026	250			250
5.875% January and February 2034⁽¹⁾	176			176
5.35% May 15, 2035	250			250
6.125% September 15, 2037	250			250
4% May 1, 2039⁽¹⁾	75			75
6% June 1, 2039	300			300
5.35% May 15, 2040	250			250
4.5% August 15, 2040	500			500
3.95% November 15, 2041	250			250
4.3% April 1, 2042	250			250
3.75% June 1, 2047	400			—
	4,573			4,349
Other long-term debt:
OMEC LLC variable-rate loan (5.2925% after floating-to-fixed rate swaps effective 2007),
payable 2013 through April 2019 (collateralized by OMEC plant assets)	295			305
Capital lease obligations:
Purchased-power contracts	731			239
Other	1			1
	1,027			545
	5,600			4,894
Current portion of long-term debt	(220		)	(191		)
Unamortized discount on long-term debt	(11		)	(11		)
Unamortized debt issuance costs	(34		)	(34		)
Total SDG&E	5,335			4,658

SoCalGas
First mortgage bonds (collateralized by plant assets):
5.45% April 15, 2018	250			250
1.55% June 15, 2018	250			250
3.15% September 15, 2024	500			500
3.2% June 15, 2025	350			350
2.6% June 15, 2026	500			500
5.75% November 15, 2035	250			250
5.125% November 15, 2040	300			300
3.75% September 15, 2042	350			350
4.45% March 15, 2044	250			250
	3,000			3,000
Other long-term debt (uncollateralized):
1.875% Notes payable 2016 through May 2026⁽¹⁾	4			4
5.67% Notes January 18, 2028	5			5
Capital lease obligations	1			—
	10			9
	3,010			3,009
Current portion of long-term debt	(501		)	—
Unamortized discount on long-term debt	(7		)	(7		)
Unamortized debt issuance costs	(17		)	(20		)
Total SoCalGas	2,485			2,982



LONG-TERM DEBT (CONTINUED)
(Dollars in millions)
	December 31,
	2017			2016
Sempra Energy
Other long-term debt (uncollateralized):
2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease⁽²⁾	138			137
Sempra South American Utilities
Other long-term debt (uncollateralized):
Chilquinta Energía – 4.25% Series B Bonds October 30, 2030	205			185
Luz del Sur
Bank loans 5.18% to 6.7% payable 2016 through December 2018	53			75
Corporate bonds at 4.75% to 8.75% payable 2014 through September 2029	415			346
Other bonds at 3.77% to 4.61% payable 2020 through May 2022	6			7
Capital lease obligations	6			6
Sempra Mexico
Other long-term debt (uncollateralized unless otherwise noted):
Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency
swaps effective 2013)	66			63
6.3% Notes February 2, 2023 (4.12% after cross-currency swap)	198			189
Notes at variable rates (4.63% after floating-to-fixed rate swaps effective 2014),
payable 2016 through December 2026, collateralized by plant assets	314			352
3.75% Notes January 14, 2028	300			—
Bank loans including $251 at a weighted-average fixed rate of 6.67%, $178 at variable rates
(weighted-average rate of 6.29% after floating-to-fixed rate swaps effective 2014) and $39 at variable
rates (4.62% at December 31, 2017), payable 2016 through March 2032, collateralized by plant assets	468			481
4.875% Notes January 14, 2048	540			—
Sempra Renewables
Other long-term debt (collateralized by project assets):
Loan at variable rates (3.325% at December 31, 2017) payable 2012 through December 2028
except for $59 at 3.668% after floating-to-fixed rate swaps effective June 2012⁽¹⁾	77			84
Sempra LNG & Midstream
Other long-term debt (uncollateralized unless otherwise noted):
Notes at 2.87% to 3.51% October 1, 2026⁽¹⁾	20			20
8.45% Notes payable 2012 through December 2017, collateralized by parent guarantee	—			6
	9,405			7,548
Current portion of long-term debt	(706		)	(722		)
Unamortized discount on long-term debt	(13		)	(10		)
Unamortized premium on long-term debt	4			4
Unamortized debt issuance costs	(65		)	(31		)
Total other Sempra Energy	8,625			6,789
Total Sempra Energy Consolidated	$	16,445		$	14,429


⁽¹⁾	Callable long-term debt not subject to make-whole provisions.


⁽²⁾	We discuss this lease in Note 15.

On January 12, 2018, we issued the following debt securities and received net proceeds of $4.9 billion (after deducting the underwriting discount, but before deducting expenses):



NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount		Maturity	Interest payments
Floating Rate⁽¹⁾ Notes due 2019	$	500	July 15, 2019	Quarterly
Floating Rate⁽²⁾ Notes due 2021	700		January 15, 2021	Quarterly
2.400% Senior Notes due 2020	500		February 1, 2020	Semi-annually
2.900% Senior Notes due 2023	500		February 1, 2023	Semi-annually
3.400% Senior Notes due 2028	1,000		February 1, 2028	Semi-annually
3.800% Senior Notes due 2038	1,000		February 1, 2038	Semi-annually
4.000% Senior Notes due 2048	800		February 1, 2048	Semi-annually


⁽¹⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points.


⁽²⁾	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points.

The following table shows the detail and maturities of long-term debt outstanding:



LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2017			2016

2.3% Notes April 1, 2017	$	—		$	600
6.15% Notes June 15, 2018	500			500
9.8% Notes February 15, 2019	500			500
1.625% Notes October 7, 2019	500			500
2.4% Notes March 15, 2020	500			500
2.85% Notes November 15, 2020	400			400
Notes at variable rates (2.038% at December 31, 2017) March 15, 2021	850			—
2.875% Notes October 1, 2022	500			500
4.05% Notes December 1, 2023	500			500
3.55% Notes June 15, 2024	500			500
3.75% Notes November 15, 2025	350			350
3.25% Notes June 15, 2027	750			—
6% Notes October 15, 2039	750			750
Fair value adjustments for interest rate swaps, net	(1		)	(3		)
Build-to-suit lease	138			137
	6,737			5,734
Current portion of long-term debt	(500		)	(600		)
Unamortized discount on long-term debt	(13		)	(10		)



Unamortized debt issuance costs	(26		)	(24		)
Total long-term debt	$	6,198		$	5,100

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - PRINCIPLES OF CONSOLIDATION (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

$ 325

$ 348

^[1]

299

^[1]

136

142

^[1]

1,517

3,414

^[1]

295

^[1]

792

520

^[1]

109

122

^[1]

299

^[1]

Deferred Credits and Other Liabilities [Abstract]

545

517

^[1]

3,922

2,876

^[1]

Regulatory liabilities arising from removal obligations

171

^[1]

As previously reported [Member]

1,136

1,173

^[1]

259

271

815

122

Deferred Credits and Other Liabilities [Abstract]

557

Regulatory liabilities arising from removal obligations

2,697

1,523

316

340

^[1]

116

^[1]

^[1]

451

2,012

^[1]

Deferred taxes recoverable in rates

182

^[1]

328

176

^[1]

^[1]

116

^[1]

Deferred Credits and Other Liabilities [Abstract]

^[1]

2,225

1,725

^[1]

Regulatory liabilities arising from removal obligations

^[1]

San Diego Gas and Electric Company [Member] | As previously reported [Member]

334

349

^[1]

259

Deferred taxes recoverable in rates

1,014

998

358

Deferred Credits and Other Liabilities [Abstract]

Regulatory liabilities arising from removal obligations

1,725

421

^[1]

179

^[1]

^[1]

983

1,331

^[1]

Regulatory assets arising from pension obligations

109

^[1]

364

290

^[1]

122

^[1]

179

^[1]

Deferred Credits and Other Liabilities [Abstract]

205

171

^[1]

1,697

1,151

^[1]

Regulatory liabilities arising from removal obligations

^[1]

Southern California Gas Company [Member] | As previously reported [Member]

$ 253

246

^[1]

Regulatory assets arising from pension obligations

742

589

399

122

Deferred Credits and Other Liabilities [Abstract]

195

Regulatory liabilities arising from removal obligations

972

$ 521

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - CASH, CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[2]

Dec. 31, 2014

^[2]

$ 76

Restricted cash, noncurrent

288

349

^[1]

Restricted cash, current

^[1]

^[1]

Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows

364

425

^[2]

$ 450

$ 610

SDG&E [Member]

Restricted cash, noncurrent

^[1]

Restricted cash, current

^[1]

^[1]

Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows

$ 29

$ 20

^[2]

$ 43

$ 27

[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.
[2]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - INVENTORIES (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2017

$ 92

$ 109

157

187

258

^[1]

307

SDG&E [Member]

101

105

SoCalGas [Member]

LIFO liquidation

Sempra South American Utilities [Member]

124

$ 82

$ 34

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 48,108

$ 43,624

^[1]

Depreciation

1,422

1,236

$ 1,178

11,605

10,693

^[1]

19,787

17,844

^[1]

Depreciation

621

583

544

4,949

4,594

^[1]

16,772

15,344

^[1]

Depreciation

514

474

$ 459

Natural gas operations [Member] | San Diego Gas and Electric Company [Member]

5,366

5,092

^[1]

$ 2,186

$ 1,897

2.40%

2.52%

Natural gas operations [Member] | Southern California Gas Company [Member]

$ 756

$ 721

$ 15,759

$ 14,428

3.63%

3.64%

3.83%

$ 34

$ 32

Accumulated depreciation of capital leased assets

5,352

5,079

Electric distribution [Member] | San Diego Gas and Electric Company [Member]

$ 6,975

$ 6,497

3.92%

3.86%

3.79%

Accumulated depreciation of capital leased assets

$ 4,193

$ 3,873

Electric transmission [Member] | San Diego Gas and Electric Company [Member]

$ 5,626

$ 5,152

Electric generation [Member] | San Diego Gas and Electric Company [Member]

2.71%

2.66%

2.62%

$ 2,435

$ 1,932

4.05%

4.00%

3.89%

Other electric [Member] | San Diego Gas and Electric Company [Member]

$ 757

$ 258

$ 1,114

$ 1,059

5.54%

5.66%

5.73%

Other non-utility [Member] | Southern California Gas Company [Member]

$ 22

$ 21

$ 32

$ 34

5.28%

6.55%

3.95%

Other non-utility [Member] | Other Operating Units and Parent [Member]

$ 14

$ 13

Construction work in progress [Member] | San Diego Gas and Electric Company [Member]

972

755

Construction work in progress [Member] | Southern California Gas Company [Member]

1,451

1,307

Land and land rights [Member] | Other Operating Units and Parent [Member]

981

882

Land and land rights [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 416

381

Land and land rights [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

22 years

Land and land rights [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

55 years

Utility electric distribution operations [Member] | Other Operating Units and Parent [Member]

33 years

$ 1,751

1,519

Utility electric distribution operations [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 318

252

Utility electric distribution operations [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

12 years

Utility electric distribution operations [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

60 years

Generating plants [Member] | Other Operating Units and Parent [Member]

52 years

Generating plants [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 2,242

1,874

Generating plants [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

2 years

Generating plants [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

100 years

LNG terminals [Member] | Other Operating Units and Parent [Member]

31 years

LNG terminals [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 1,133

1,129

LNG terminals [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

43 years

LNG terminals [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

43 years

Pipelines and storage [Member] | Other Operating Units and Parent [Member]

43 years

Pipelines and storage [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 4,408

3,242

Pipelines and storage [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

3 years

Pipelines and storage [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

55 years

Other [Member] | Other Operating Units and Parent [Member]

43 years

Other [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 269

235

Other [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

1 year

Other [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

50 years

Construction work in progress [Member] | Other Operating Units and Parent [Member]

13 years

Other [Member] | Other Operating Units and Parent [Member]

$ 691

1,488

639

568

Other [Member] | Minimum [Member] | Other Operating Units and Parent [Member]

$ 136

136

Other [Member] | Maximum [Member] | Other Operating Units and Parent [Member]

1 year

Other [Member] | Weighted Average [Member] | Other Operating Units and Parent [Member]

80 years

Plant, pipeline and other distribution assets of ecogas [Member]

33 years

Plant, pipeline and other distribution assets of ecogas [Member] | Other Operating Units and Parent [Member]

$ 39

Total Other Operating Units And Parent [Member] | Other Operating Units and Parent [Member]

145

128

11,549

10,436

Southwest Powerlink (SWPL) transmission line [Member] | Electric transmission [Member] | San Diego Gas and Electric Company [Member]

1,290

$ 1,007

$ 440

Ownership interest

92.00%

Southwest Powerlink (SWPL) transmission line [Member] | Construction work in progress [Member] | San Diego Gas and Electric Company [Member]

$ 241

$ 29

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

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - GOODWILL (Details) - USD ($)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

$ 2,364,000,000

^[1]

$ 819,000,000

1,590,000,000

Acquisition of business – measurement period adjustment

(72,000,000)

(13,000,000)

46,000,000

27,000,000

Sempra South American Utilities [Member]

2,397,000,000

2,364,000,000

^[1]

749,000,000

722,000,000

Acquisition of business – measurement period adjustment

46,000,000

27,000,000

795,000,000

749,000,000

1,615,000,000

25,000,000

1,590,000,000

Acquisition of business – measurement period adjustment

(13,000,000)

1,602,000,000

1,615,000,000

72,000,000

Acquisition of business – measurement period adjustment

(72,000,000)

$ 0

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

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - VARIABLE INTEREST ENTITIES (Details)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

$ 2,517

$ 2,080

$ 2,517

$ 2,080

288

349

^[1]

288

349

^[1]

^[1]

307

258

^[1]

307

258

^[1]

136

142

^[1]

136

142

^[1]

3,341

3,110

^[1]

3,341

3,110

^[1]

792

520

^[1]

792

520

^[1]

^[1]

36,503

32,931

^[1]

36,503

32,931

^[1]

50,454

47,786

^[1]

50,454

47,786

^[1]

$ 41,150

1,427

913

^[1]

1,427

913

^[1]

109

^[1]

109

^[1]

545

517

^[1]

545

517

^[1]

6,635

5,927

^[1]

6,635

5,927

^[1]

2,732

2,431

^[1]

2,732

2,431

^[1]

2,767

3,745

^[1]

2,767

3,745

^[1]

16,445

14,429

^[1]

16,445

14,429

^[1]

316

405

^[1]

316

405

^[1]

2,450

2,270

^[1]

2,450

2,270

^[1]

Net assets less other noncontrolling interests

50,454

47,786

^[1]

50,454

47,786

^[1]

12,670

12,951

^[1]

12,670

12,951

^[1]

Energy-related businesses

1,431

922

977

(3,117)

(2,970)

(2,886)

(1,490)

(1,312)

^[2]

(1,250)

^[2]

1,585

1,830

1,704

254

132

126

(659)

(553)

(561)

Income tax expense

(1,276)

(389)

(341)

(Earnings) losses attributable to noncontrolling interest

351

1,519

^[2]

1,448

^[2]

(94)

(148)

(98)

(501)

$ 57

$ 259

$ 441

379

$ 622

$ 16

$ 353

256

1,370

1,349

Variable Interest Entity [Line Items]

4,573

4,349

4,573

4,349

^[1]

^[1]

105

^[1]

105

^[1]

^[1]

1,100

1,072

^[1]

1,100

1,072

^[1]

328

176

^[1]

328

176

^[1]

^[1]

14,838

13,250

^[1]

14,838

13,250

^[1]

17,844

17,719

^[1]

17,844

17,719

^[1]

220

191

^[1]

220

191

^[1]

^[1]

^[1]

1,622

1,168

^[1]

1,622

1,168

^[1]

762

751

^[1]

762

751

^[1]

1,530

2,829

^[1]

1,530

2,829

^[1]

5,335

4,658

^[1]

5,335

4,658

^[1]

153

189

^[1]

153

189

^[1]

^[1]

Net assets less other noncontrolling interests

17,844

17,719

^[1]

17,844

17,719

^[1]

5,598

5,641

^[1]

5,598

5,641

^[1]

576

845

890

713

990

1,058

(203)

(195)

(204)

Income tax expense

(155)

(280)

(284)

(Earnings) losses attributable to noncontrolling interest

421

565

^[2]

606

^[2]

$ (14)

(19)

San Diego Gas and Electric Company [Member] | Otay Mesa VIE [Member]

Variable Interest Entity [Line Items]

605

Put option

280

$ 280

Equity of Variable interest entity

321

354

321

354

347

377

347

377

284

293

284

293

347

377

347

377

Cost of electric fuel and purchased power

(79)

(83)

(17)

(29)

(19)

(28)

(35)

(26)

Total operating expenses

(34)

(15)

(38)

(22)

(20)

(19)

(Earnings) losses attributable to noncontrolling interest

(5)

(14)

(19)

$ 0

Sempra Renewables [Member] | Noncontrolling Tax Equity Investors [Member]

1,412

926

1,412

926

1,444

1,017

1,444

1,017

Total liabilities

102

Net assets less other noncontrolling interests

631

468

631

468

719

447

719

447

Energy-related businesses

(9)

(1)

(32)

Income tax expense

(4)

(Earnings) losses attributable to noncontrolling interest

(23)

(4)

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

Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member] | San Diego Gas and Electric Company [Member] | Otay Mesa VIE [Member]

997

Variable Interest Entity [Line Items]

Accumulated Other Comprehensive Income (Loss) [Line Items]

$ 295

$ 305

$ 295

$ 305

[1]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.
[2]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 12,951

$ 18

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

12,670

12,951

^[1]

Sale of noncontrolling interests, net of offering costs

196

1,701

Accumulated Other Comprehensive Income (Loss) [Line Items]

^[1]

5,641

5,598

5,641

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

^[1]

3,510

Foreign currency translation adjustments [Member]

3,907

3,510

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

(527)

(582)

(322)

107

(260)

107

(260)

Financial instruments [Member]

(420)

(527)

(582)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(125)

(137)

(90)

(4)

(7)

(57)

(47)

Financial instruments [Member] | Southern California Gas Company [Member]

(122)

(125)

(137)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(13)

(14)

Pension and other postretirement benefits [Member]

(13)

(14)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(96)

(87)

(85)

(15)

(10)

(9)

(2)

Pension and other postretirement benefits [Member] | San Diego Gas and Electric Company [Member]

(84)

(96)

(87)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(8)

(12)

(1)

Pension and other postretirement benefits [Member] | Southern California Gas Company [Member]

(8)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(9)

(5)

(4)

(4)

(1)

(4)

(1)

Accumulated other comprehensive income (loss) [Member]

(8)

(9)

(5)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(748)

(806)

(497)

103

(327)

122

(309)

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

(626)

(748)

(806)

Sale of noncontrolling interests, net of offering costs

Accumulated other comprehensive income (loss) [Member] | San Diego Gas and Electric Company [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

(8)

(12)

(1)

Accumulated other comprehensive income (loss) [Member] | Southern California Gas Company [Member]

(8)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(22)

(19)

(18)

(4)

(1)

(3)

(1)

$ (21)

$ (22)

$ (19)

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

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - NONCONTROLLING INTERESTS (Details) $ / shares in Units, $ in Millions, $ in Millions			1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 13, 2016 USD ($) $ / shares $ / $ shares	Oct. 13, 2016 MXN ($) shares	Dec. 31, 2016 USD ($) facility	Dec. 31, 2017 USD ($) company facility	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Oct. 19, 2016	Oct. 18, 2016
Noncontrolling Interest [Line Items]
Impact of issuance on equity					$ 196	$ 1,701
IEnova [Member]
Noncontrolling Interest [Line Items]
Price of shares issued (in pesos per share) \| $ / shares	$ 80.00
Additional shares purchased \| shares	83,125,000
Cash consideration (fair value of total consideration)	$ 351
Shares issued \| shares	380,000,000	380,000,000
Proceeds from sale of shares	$ 1,570	$ 29,860
Exchange rate (in pesos) \| $ / $	18.96
Ownership interest							66.40%	81.10%
IEnova [Member] \| Bridge Loan [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	$ 1,150
IEnova [Member] \| Related Party Debt [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	100
IEnova [Member] \| Revolving Credit Facility [Member]
Noncontrolling Interest [Line Items]
Repayments of debt	250
Ventika [Member] \| IEnova [Member]
Noncontrolling Interest [Line Items]
Cash consideration (fair value of total consideration)	$ 50
Shareholders' equity [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						281
Shareholders' equity [Member] \| IEnova [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						281
Non-controlling interests [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity					$ 196	1,420
Non-controlling interests [Member] \| IEnova [Member]
Noncontrolling Interest [Line Items]
Impact of issuance on equity						$ 948
Sempra Renewables [Member] \| Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of Tax Equity Limited Liability Companies Formed \| company				2
Proceeds from sale of noncontrolling interests			$ 474
Solar Power Projects [Member] \| Sempra Renewables [Member] \| Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of facilities acquired \| facility			3	4
Proceeds from sale of noncontrolling interests				$ 104
Wind Generation Projects [Member] \| Sempra Renewables [Member] \| Noncontrolling Tax Equity Investors [Member]
Noncontrolling Interest [Line Items]
Number of facilities acquired \| facility				1
Proceeds from sale of noncontrolling interests				$ 92

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

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

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

SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA - TRANSACTIONS WITH AFFILIATES (Details)
$ in Millions, $ in Billions

12 Months Ended

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2017

MXN ($)

Nov. 15, 2017

$ 37

$ 26

^[1]

Due to unconsolidated affiliates, noncurrent

598

201

^[1]

(35)

^[1]

Joint venture with PEMEX [Member]

$ (7)

$ (11)

^[1]

ESJ joint venture [Member]

5.27%

TAG Pipeline Norte [Member]

7.94%

LIBOR [Member] | Joint venture with PEMEX [Member]

4.74%

LIBOR [Member] | ESJ joint venture [Member]

450.00%

LIBOR [Member] | TAG Pipeline Norte [Member]

637.50%

Sempra South American Utilities [Member] | Eletrans [Member]

290.00%

Sempra South American Utilities [Member] | Other related parties [Member]

$ 103

$ 96

Sempra Mexico [Member] | IMG [Member]

Committed lines of credit, maximum borrowing capacity

718

$ 14.0

Sempra Mexico [Member] | Joint venture with PEMEX [Member]

487

Sempra Mexico [Member] | ESJ joint venture [Member]

Sempra Mexico [Member] | TAG Pipeline Norte [Member]

Due to unconsolidated affiliates, noncurrent

$ (35)

Sempra Mexico [Member] | Interbank Equilibrium Rate [Member] | IMG [Member]

220.00%

9.87%

Committed lines of credit, maximum borrowing capacity

$ 750

^[1]

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

(40)

(15)

^[1]

Income taxes due from (to) Sempra Energy

(30)

$ 159

Loan to unconsolidated affiliate, principal

0.68%

$ 31

San Diego Gas and Electric Company [Member] | Due to/from Various Affiliates [Member]

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

(6)

(7)

(4)

(8)

Committed lines of credit, maximum borrowing capacity

750

^[1]

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

(35)

(28)

^[1]

Income taxes due from (to) Sempra Energy

(35)

(28)

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

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

$ 4

$ 8

50.00%

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

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

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

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

NEW ACCOUNTING STANDARDS (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 149

$ 62

^[1]

$ 66

^[1]

(214)

^[1]

(169)

^[1]

3,625

2,311

^[1]

2,898

^[1]

Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired

(270)

(1,504)

^[1]

(198)

^[1]

(2)

^[1]

(4,700)

(4,835)

^[1]

(2,868)

^[1]

Net Cash Provided by (Used in) Financing Activities

(43)

(21)

^[1]

(20)

^[1]

1,007

2,502

^[1]

(176)

^[1]

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(3)

^[1]

(14)

^[1]

(Decrease) increase in cash, cash equivalents and restricted cash

(61)

(25)

^[1]

(160)

^[1]

^[2]

349

Cash, cash equivalents and restricted cash, January 1

288

349

^[2]

^[1]

425

450

610

Cash, cash equivalents and restricted cash, December 31

364

425

^[1]

450

^[1]

3,117

2,970

2,886

New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

254

132

126

(169)

2,311

2,898

Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired

Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired

(1,504)

(198)

(4,835)

(2,868)

Net Cash Provided by (Used in) Financing Activities

(21)

(20)

2,502

(176)

Effect of Exchange Rate on Cash and Cash Equivalents

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(3)

(14)

(Decrease) increase in cash, cash equivalents and restricted cash

(25)

(160)

Cash, cash equivalents and restricted cash, January 1

425

450

610

Cash, cash equivalents and restricted cash, December 31

425

450

As previously reported [Member] | Accounting Standards Update 2017-07 [Member]

3,117

2,970

As previously reported [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

254

132

(162)

2,319

2,905

Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired

(1,582)

(200)

Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired

(139)

(100)

175

(4,886)

(2,885)

Net Cash Provided by (Used in) Financing Activities

(10)

(17)

2,513

(173)

Effect of Exchange Rate on Cash and Cash Equivalents

(14)

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(Decrease) increase in cash, cash equivalents and restricted cash

(54)

(167)

349

403

570

Cash, cash equivalents and restricted cash, January 1

349

403

Cash, cash equivalents and restricted cash, December 31

Effect of adoption [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

(1)

(7)

(8)

(7)

Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired

1,582

200

Expenditures for investments and acquisitions, net of cash, cash equivalents and restricted cash acquired

(1,504)

(198)

139

100

(175)

(93)

Net Cash Provided by (Used in) Financing Activities

(11)

(3)

(11)

(3)

Effect of Exchange Rate on Cash and Cash Equivalents

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(3)

(14)

(Decrease) increase in cash, cash equivalents and restricted cash

167

(25)

(160)

(349)

(403)

(570)

Cash, cash equivalents and restricted cash, January 1

(349)

(403)

425

450

610

Cash, cash equivalents and restricted cash, December 31

425

450

Recast [Member] | Accounting Standards Update 2017-07 [Member]

3,096

2,976

233

138

(22)

(35)

^[1]

(16)

^[1]

(108)

(20)

^[1]

(125)

^[1]

1,547

1,323

^[1]

1,661

^[1]

^[1]

(1,515)

(1,324)

^[1]

(1,077)

^[1]

Net Cash Provided by (Used in) Financing Activities

(23)

(22)

^[1]

(568)

^[1]

^[2]

Cash, cash equivalents and restricted cash, January 1

^[2]

^[1]

Cash, cash equivalents and restricted cash, December 31

^[1]

1,020

1,048

1,017

713

990

1,058

San Diego Gas and Electric Company [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

(20)

(125)

1,323

1,661

(1,324)

(1,077)

Net Cash Provided by (Used in) Financing Activities

(6)

(4)

(22)

(568)

(Decrease) increase in cash, cash equivalents and restricted cash

(23)

Cash, cash equivalents and restricted cash, January 1

Cash, cash equivalents and restricted cash, December 31

San Diego Gas and Electric Company [Member] | As previously reported [Member] | Accounting Standards Update 2017-07 [Member]

1,020

1,048

713

990

San Diego Gas and Electric Company [Member] | As previously reported [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

(16)

(122)

1,327

1,664

(49)

(39)

(1,319)

(1,086)

Net Cash Provided by (Used in) Financing Activities

(4)

(2)

(20)

(566)

(Decrease) increase in cash, cash equivalents and restricted cash

(12)

Cash, cash equivalents and restricted cash, January 1

Cash, cash equivalents and restricted cash, December 31

San Diego Gas and Electric Company [Member] | Effect of adoption [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-15 and 2016-18 [Member]

(4)

(3)

(4)

(3)

(60)

(35)

(5)

Net Cash Provided by (Used in) Financing Activities

(2)

(2)

(Decrease) increase in cash, cash equivalents and restricted cash

(12)

(23)

(8)

(20)

(8)

Cash, cash equivalents and restricted cash, January 1

(8)

(20)

Cash, cash equivalents and restricted cash, December 31

San Diego Gas and Electric Company [Member] | Recast [Member] | Accounting Standards Update 2017-07 [Member]

1,024

1,062

709

976

(26)

(20)

(80)

(91)

1,306

671

880

(1,363)

(1,269)

(1,402)

Net Cash Provided by (Used in) Financing Activities

552

495

(4)

(46)

(27)

^[2]

^[2]

1,479

1,385

1,361

622

557

608

Southern California Gas Company [Member] | As previously reported [Member] | Accounting Standards Update 2017-07 [Member]

$ 30

1,479

1,385

622

557

Southern California Gas Company [Member] | Recast [Member] | Accounting Standards Update 2017-07 [Member]

1,474

1,391

627

551

$ 31

$ 38

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

ACQUISTION AND DIVESTITURE ACTIVITY - ASSETS ACQUIRED AND LIABILITIES ASSUMED (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 14, 2016

Sep. 26, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Fair value of equity interest in IEnova Pipelines immediately prior to acquisition

$ 28

$ 1,144

^[1]

$ 0

^[1]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]

Acquisition of business – measurement period adjustment

$ 2,397

$ 2,364

^[2]

2,397

2,364

^[2]

$ 819

(13)

Cash consideration (fair value of total consideration)

$ 1,144

Fair value of equity interest in IEnova Pipelines immediately prior to acquisition

1,144

Total fair value of business combination

2,288

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]

1,248

Other noncurrent assets

(11)

(3)

Fixed-price contracts and other derivatives, current

(49)

(6)

(20)

(315)

(5)

Fixed-price contracts and other derivatives, noncurrent

(127)

(19)

Other noncurrent liabilities

(11)

Total identifiable net assets

827

Sempra Mexico [Member] | IEnova Pipelines [Member] | Scenario, Adjustment [Member]

$ 1,461

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]

Acquisition of business – measurement period adjustment

(119)

$ (119)

$ 86

Sempra Mexico [Member] | Ventika [Member]

Cash consideration (fair value of total consideration)

$ 310

Fair value of equity interest in IEnova Pipelines immediately prior to acquisition

Total fair value of business combination

310

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]

154

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]

673

Other noncurrent assets

(125)

(1)

Fixed-price contracts and other derivatives, current

(7)

(4)

(8)

(478)

(2)

Fixed-price contracts and other derivatives, noncurrent

(120)

(10)

Other noncurrent liabilities

Total identifiable net assets

194

Sempra Mexico [Member] | Ventika [Member] | Scenario, Adjustment [Member]

$ 116

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]

$ 13

Acquisition of business – measurement period adjustment

$ (13)

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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

1 Months Ended

3 Months Ended

12 Months Ended

Jan. 12, 2018

USD ($)

Nov. 15, 2017

USD ($)

Oct. 03, 2017

USD ($)

Aug. 21, 2017

USD ($)

director

Jul. 10, 2017

USD ($)

ppa

Dec. 14, 2016

USD ($)

Oct. 13, 2016

USD ($)

Sep. 26, 2016

USD ($)

Jul. 01, 2016

USD ($)

Sep. 30, 2016

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Nov. 14, 2017

Sep. 06, 2017

USD ($)

Sep. 25, 2016

Jan. 01, 2015

Dec. 31, 2014

Cash paid, net of cash and cash equivalents acquired

$ (147.0)

$ (1,342.0)

^[1]

$ (3.0)

^[1]

Earnings/Income attributable to common shares

11,207.0

10,183.0

10,231.0

$ (501.0)

$ 57.0

$ 259.0

$ 441.0

$ 379.0

$ 622.0

$ 16.0

$ 353.0

256.0

1,370.0

1,349.0

47.0

51.0

^[1]

52.0

^[1]

76.0

$ 76.0

76.0

$ 76.0

IEnova [Member]

Cash consideration (fair value of total consideration)

$ 351.0

Ventika [Member] | IEnova [Member]

Cash consideration (fair value of total consideration)

$ 50.0

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

Percentage of consideration funded by equity issuance

$ 9,450.0

Shares issued

$ 25.9

65.00%

Percentage of consideration funded by debt issuance

35.00%

Plan percentage of capital structure allocated to debt

57.50%

Plan percentage of capital structure allocated to equity

42.50%

Transaction costs incurred

$ 43.0

Fee receivable if agreement terminated

$ 190.0

Sempra Mexico [Member] | IEnova [Member]

Ownership percentage held by noncontrolling owners

33.60%

18.90%

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

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

25.00%

Ownership percentage before acquisition

50.00%

Debt assumed

$ 96.0

100.00%

50.00%

100.00%

Cash paid, net of cash and cash equivalents acquired

50.00%

$ 165.0

Weighted average life of finite-lived intangible acquired

23 years

Cash Acquired from Acquisition

$ 18.0

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

$ 66.0

Ownership percentage before acquisition

50.00%

25.00%

50.00%

Cash consideration (fair value of total consideration)

$ 1,144.0

66.0

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

$ 0.0

Cash consideration (fair value of total consideration)

50.00%

$ 1,144.0

Ownership percentage before acquisition

66.0

Debt assumed

$ 364.0

50.00%

Cash paid, net of cash and cash equivalents acquired

100.00%

$ 1,078.0

Proceeds from debt issued

$ 1,150.0

Gain on acquisition of remaining voting rights

$ 617.0

Gain on acquisition of remaining voting rights, net of tax

$ 432.0

432.0

4.0

$ 1.0

Earnings/Income attributable to common shares

82.0

33.0

Sempra Mexico [Member] | Ventika [Member]

Cash consideration (fair value of total consideration)

$ 310.0

0.0

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

$ 154.0

Proceeds from debt issued

100.00%

Debt assumed

$ 610.0

250.0

Cash

10.0

1.0

Earnings/Income attributable to common shares

4.0

$ 3.0

$ 310.0

252

20 years

$ 50.0

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

$ 68.0

Weighted average life of finite-lived intangible acquired

19 years

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

Cash consideration (fair value of total consideration)

$ 124.0

Number of purchase power agreements | ppa

200

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

18 years

Cash consideration (fair value of total consideration)

$ 18.0

$ 4.0

100.00%

$ 22.0

100

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

15 years

100.00%

$ 8.0

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

20 years

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

100.00%

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

100.00%

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

100.00%

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

80.03%

Ownership percentage held by noncontrolling owners

19.75%

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

Ownership percentage held by noncontrolling owners

0.22%

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

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

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

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

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

Proceeds from issuance of debt

$ 4,900.0

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

Proceeds from issuance of debt

$ 2,700.0

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

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

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

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

1 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2016

USD ($)

Sep. 30, 2016

USD ($)

May 31, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Apr. 30, 2015

USD ($)

Sep. 30, 2016

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Sep. 12, 2016

USD ($)

May 09, 2016

Mar. 29, 2016

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

Liabilities assumed

$ 261

$ 1,322

^[1]

$ 2

^[1]

Sempra Renewables [Member] | Rosamond Solar [Member]

$ 2,517

$ 2,080

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

Gain on sale of equity interests

100.00%

Proceeds from sale

$ 26

Gain on sale of assets, after tax

$ 18

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

Other than temporary impairment in investment, net of tax

$ 44

$ 27

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

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

Gain on sale of equity interests

625

Proceeds from sale

$ 347

Gain on sale of assets, after tax

$ 36

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

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

Gain on sale of equity interests

$ 130

Gain on sale of assets, after tax

Proceeds from sale

$ 318

Cash

$ 2

Liabilities assumed

$ 67

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

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

Proceeds from sale of investments

25.00%

$ 443

$ 440

484

440

Other than temporary impairment in investment, net of tax

$ 44

$ 27

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

ACQUISTION AND DIVESTITURE ACTIVITY - SUMMARY OF DECONSOLIDATIONS (Details) - USD ($)
$ in Millions

1 Months Ended

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Sep. 12, 2016

Dec. 31, 2015

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

$ 2,397

$ 2,364

^[1]

$ 819

2,517

2,080

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

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

$ 0

$ 72

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

Proceeds, net of transaction costs

$ 304

Cash

(2)

(17)

(199)

(72)

Other noncurrent assets

Long-term debt, including current portion

Other noncurrent liabilities

$ 89

Gain on sale of business and equity interests

$ 130

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

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

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

1 Months Ended

12 Months Ended

Feb. 28, 2017

USD ($)

Dec. 31, 2017

USD ($)

Bcf

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Nov. 15, 2017

Nov. 14, 2017

Sep. 26, 2016

Sep. 25, 2016

May 31, 2016

May 09, 2016

Mar. 31, 2016

USD ($)

Mar. 29, 2016

Jun. 30, 2015

USD ($)

Nov. 30, 2014

USD ($)

Oct. 01, 2014

USD ($)

Schedule of Equity Method Investments [Line Items]

Undistributed earnings of equity method investments

$ 89

$ 44

Debt instrument converted

2,517

2,080

^[1]

$ 0

^[1]

Interest costs capitalized

256

236

201

Fair value at origin guarantee obligation associated with cash flow requirements

$ 82

Current guarantor obligations

R B S Sempra Commodities [Member]

Schedule of Equity Method Investments [Line Items]

Schedule of Equity Method Investments [Line Items]

$ 67

Cameron LNG [Member]

Threshold for canceling of hedge, Percent of unamortized principal

50.20%

50.00%

Indirect economic and beneficial and ownership interest prior to financial completion

37.65%

Indirect economic and beneficial and ownership interest after financial completion

10.00%

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

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Maximum Exposure, Percentage

50.20%

Debt instrument, maximum borrowing amount

$ 3,900

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

Schedule of Equity Method Investments [Line Items]

Schedule of Equity Method Investments [Line Items]

50.00%

Sempra Mexico [Member] | IMG [Member]

50.00%

Schedule of Equity Method Investments [Line Items]

$ 72

100

Transportation service contract term

40.00%

25 years

Sempra Mexico [Member] | TransCanada [Member]

Schedule of Equity Method Investments [Line Items]

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

60.00%

Schedule of Equity Method Investments [Line Items]

50.00%

Schedule of Equity Method Investments [Line Items]

Ownership percentage of operating partner

50.00%

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

Schedule of Equity Method Investments [Line Items]

$ 484

113

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

25.00%

Schedule of Equity Method Investments [Line Items]

Proved developed reserves | Bcf

$ 1

1.5

Project capacity | MT

13.9

Proved undeveloped reserve | MT

Proved undeveloped reserve per day | Bcf

1.7

Interest costs capitalized

$ 47

$ 49

Percentage of debt hedged by interest rate derivatives

$ 7,400

50.00%

Notional amount of derivatives

$ 1,500

$ 3,700

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

Schedule of Equity Method Investments [Line Items]

Weighted average rate prior to project completion

1.59%

Weighted average rate after project completion

1.78%

Fixed percentage interest rate

3.32%

3.19%

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

Schedule of Equity Method Investments [Line Items]

Debt instrument converted

$ 19

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

$ 1

Schedule of Equity Method Investments [Line Items]

Debt instrument, maximum borrowing amount

$ 288

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

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Maximum Exposure, Percentage

49.80%

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

Schedule of Equity Method Investments [Line Items]

50.00%

50.00%

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

INVESTMENTS IN UNCONSOLIDATED ENTITIES - SUMMARIZED FINANCIAL INFORMATION (Details) - USD ($) $ in Millions			12 Months Ended
	Nov. 15, 2017	Sep. 26, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 14, 2017	Sep. 25, 2016	May 31, 2016	May 09, 2016	Mar. 31, 2016	Mar. 29, 2016
Equity Method Investment, Summarized Financial Information [Abstract]
Gross revenue			$ 846	$ 1,079	$ 1,533
Operating expense			(590)	(726)	(845)
Income from operations			256	353	688
Interest expense			(217)	(127)	(312)
Net income/earnings			116	252	$ 440
Current assets			974	704
Noncurrent assets			14,087	9,970
Current liabilities			797	629
Noncurrent liabilities			$ 9,809	$ 6,627
Sempra LNG & Midstream [Member] \| Rockies Express [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage in equity method investee								25.00%	25.00%	25.00%	25.00%
IEnova [Member] \| Ductos Energéticos del Norte [Member] \| Sempra Mexico [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage before acquisition	100.00%					50.00%
Acquired percentage interest	50.00%
Ownership percentage in consolidated entity	100.00%
Ownership percentage in equity method investee						50.00%
IEnova [Member] \| IEnova Pipelines [Member] \| Sempra Mexico [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage before acquisition							50.00%
Acquired percentage interest		50.00%
Ownership percentage in consolidated entity		100.00%

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

DEBT AND CREDIT FACILITIES - LINES OF CREDIT (Details)		12 Months Ended
DEBT AND CREDIT FACILITIES - LINES OF CREDIT (Details)	Jan. 17, 2018 USD ($)	Dec. 31, 2017 USD ($) lender line_of_credit	Jan. 16, 2018 USD ($)	Dec. 31, 2016
Line of Credit Facility [Line Items]
Letters of credit outstanding		$ 629,000,000
Commitment from syndicated banks for acquisition		$ 4,000,000,000
Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Number of primary lines of credit \| line_of_credit		3
Weighted average interest rate on total short-term debt outstanding		1.92%		1.51%
Sempra South American Utilities [Member] \| Peru [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		$ 465,000,000
Line of credit outstanding		(169,000,000)
Committed lines of credit, remaining borrowing capacity		$ 296,000,000
Committed lines of credit, maximum debt to equity ratio		170.00%
Committed lines of credit, bank guarantee		$ 18,000,000
Sempra South American Utilities [Member] \| Chile [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		115,000,000
Line of credit outstanding		0
Committed lines of credit, remaining borrowing capacity		115,000,000
Sempra Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,170,000,000
Line of credit outstanding		(137,000,000)
Committed lines of credit, remaining borrowing capacity		1,033,000,000
South America and Mexico [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,750,000,000
Line of credit outstanding		(306,000,000)
Committed lines of credit, remaining borrowing capacity		1,444,000,000
Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,000,000,000
Committed lines of credit, remaining borrowing capacity		1,000,000,000
Committed lines of credit, capacity for issuance of letters of credit		$ 400,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Sempra Energy [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ 0
Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		2,335,000,000
Committed lines of credit, remaining borrowing capacity		1,404,000,000
Sempra Global [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		(931,000,000)
Southern California Gas Company [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		750,000,000
Committed lines of credit, remaining borrowing capacity		$ 634,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Weighted average interest rate on total short-term debt outstanding		1.64%		0.75%
Southern California Gas Company [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (116,000,000)
San Diego Gas and Electric Company [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		750,000,000
Committed lines of credit, remaining borrowing capacity		$ 497,000,000
Committed lines of credit, maximum ratio of indebtedness to total capitalization		65.00%
Weighted average interest rate on total short-term debt outstanding		1.65%
San Diego Gas and Electric Company [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (253,000,000)
California Utilities [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		1,000,000,000
Committed lines of credit, remaining borrowing capacity		631,000,000
Reduction in borrowing limit		(500,000,000)
Line of Credit Facility, Available Unused Credit Limit Reduction		(500,000,000)
Committed lines of credit, capacity for issuance of letters of credit		250,000,000
California Utilities [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		(369,000,000)
Reduction in borrowing limit		0
Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity		4,335,000,000
Committed lines of credit, remaining borrowing capacity		$ 3,035,000,000
Committed lines of credit, term		5 years
Committed lines of credit, number of lenders \| lender		21
Lender maximum share of debt percent		7.00%
Sempra Energy Consolidated [Member] \| Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit outstanding		$ (1,300,000,000)
Subsequent Event [Member] \| Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 1,250,000,000		$ 1,000,000,000
Increase in borrowing capacity	250,000,000
Subsequent Event [Member] \| Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	3,185,000,000		$ 2,335,000,000
Increase in borrowing capacity	$ 850,000,000

DEBT AND CREDIT FACILITIES - SCHEDULE OF LONG-TERM DEBT INSTRUMENTS (Details) - USD ($)
$ in Millions

Oct. 13, 2017

Dec. 31, 2017

Oct. 30, 2017

Jun. 30, 2017

Dec. 31, 2016

$ (1,427)

$ (913)

^[1]

16,445

14,429

^[1]

4,573

4,349

732

240

5,600

4,894

(220)

(191)

^[1]

(11)

(34)

San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due March 2017 [Member]

5,335

4,658

^[1]

$ 140

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due July 2018 [Member]

1.151%

$ 161

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due August 2021 [Member]

1.65%

$ 350

350

San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due February 2022 [Member]

3.00%

$ 161

197

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due September 2023 [Member]

1.914%

$ 450

450

San Diego Gas and Electric Company [Member] | First Mortgage Bonds Due May 2026 [Member]

3.60%

$ 500

500

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2026 [Member]

2.50%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due January and February 2034 [Member]

6.00%

$ 176

176

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2035 [Member]

5.875%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due September 2037 [Member]

5.35%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2039 [Member]

6.125%

$ 75

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2039 [Member]

4.00%

$ 300

300

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due May 2040 [Member]

6.00%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due August 2040 [Member]

5.35%

$ 500

500

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due November 2041 [Member]

4.50%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due April 2042 [Member]

3.95%

$ 250

250

San Diego Gas and Electric Company [Member] | First Mortgage Bonds, Due June 2047 [Member]

4.30%

$ 400

San Diego Gas and Electric Company [Member] | Capital Lease Obligations, Purchased Power Agreements [Member]

3.75%

San Diego Gas and Electric Company [Member] | Capital Lease Obligations, Other [Member]

$ 731

239

San Diego Gas and Electric Company [Member] | Other Long-term Debt [Member]

San Diego Gas and Electric Company [Member] | Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member]

$ 1,027

545

5.2925%

$ 3,000

3,000

3,010

3,009

(501)

^[1]

(7)

(17)

(20)

Southern California Gas Company [Member] | First Mortgage Bonds, Due June 2026 [Member]

2,485

2,982

^[1]

$ 500

500

Southern California Gas Company [Member] | First Mortgage Bonds, Due April 2018 [Member]

2.60%

$ 250

250

Southern California Gas Company [Member] | First Mortgage Bonds Due June 2018 [Member]

5.45%

$ 250

250

Southern California Gas Company [Member] | First Mortgage Bonds, Due September 2024 [Member]

1.55%

$ 500

500

Southern California Gas Company [Member] | First Mortgage Bonds Due June 2025 [Member]

3.15%

$ 350

350

Southern California Gas Company [Member] | First Mortgage Bonds, Due November 2035 [Member]

3.20%

$ 250

250

Southern California Gas Company [Member] | First Mortgage Bonds, Due November 2040 [Member]

5.75%

$ 300

300

Southern California Gas Company [Member] | First Mortgage Bonds, Due September 2042 [Member]

5.125%

$ 350

350

Southern California Gas Company [Member] | First Mortgage Bonds, Due March 2044 [Member]

3.75%

$ 250

250

Southern California Gas Company [Member] | Other Long-term Debt [Member]

4.45%

Southern California Gas Company [Member] | Other Long-term Debt, Due May 2026 [Member]

$ 10

$ 4

Southern California Gas Company [Member] | Other Long-term Debt, Due January 2028 [Member]

1.875%

$ 5

5.67%

Sempra Energy [Member]

Sempra Energy [Member] | Other Long Term Debt Due April 2017 [Member]

Build to suit lease

$ 138

137

$ 0

600

Sempra Energy [Member] | Other Long-term Debt, Due June 2018 [Member]

2.30%

$ 500

500

Sempra Energy [Member] | Other Long-term Debt, Due February 2019 [Member]

6.15%

$ 500

500

Sempra Energy [Member] | Other Long-term Debt, Due October 2019 [Member]

9.80%

$ 500

500

Sempra Energy [Member] | Other Long Term Debt Due March 2020 [Member]

1.625%

$ 500

500

Sempra Energy [Member] | Other Long Term Debt, Due November 2020 [Member]

2.40%

$ 400

400

Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]

2.85%

Effective percentage rate

$ 850

2.038%

Sempra Energy [Member] | Other Long-term Debt, Due October 2022 [Member]

$ 500

500

Sempra Energy [Member] | Other Long-term Debt, Due December 2023 [Member]

2.875%

$ 500

500

Sempra Energy [Member] | Other Long Term Debt Due June 2024 [Member]

4.05%

$ 500

500

Sempra Energy [Member] | Other Long-term Debt, Due November 2025 [Member]

3.55%

$ 350

350

Sempra Energy [Member] | Other Long Term Debt Due June 2027 [Member]

3.75%

$ 750

Sempra Energy [Member] | Other Long-Term Debt, Due October 2039 [Member]

3.25%

$ 750

750

Sempra Energy [Member] | Market Value Adjustment For Interest Rate Swap [Member]

6.00%

Sempra South American Utilities [Member]

$ (1)

(3)

Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through October 2030 [Member]

$ 205

185

Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member]

4.25%

Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member] | Minimum [Member]

$ 53

Sempra South American Utilities [Member] | Other Long-term Debt, Currently Through December 2018 [Member] | Maximum [Member]

5.18%

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member]

6.70%

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member] | Minimum [Member]

$ 415

346

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through September 2029 [Member] | Maximum [Member]

4.75%

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member]

8.75%

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member] | Minimum [Member]

$ 6

Sempra South American Utilities [Member] | Other Long Term Debt, Payable Currently Through May 2022 [Member] | Maximum [Member]

3.77%

Sempra Mexico [Member] | Other Long-term Debt, Due February 2018 [Member]

4.61%

$ 66

Sempra Mexico [Member] | Other Long Term Debt, Due February 2023 [Member]

2.66%

$ 198

189

Effective percentage rate

6.30%

4.12%

Sempra Mexico [Member] | Other Long-term Debt, Currently Through December 2026 [Member]

$ 314

352

Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2028 [Member]

4.63%

$ 300

Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032 [Member]

3.75%

$ 468

481

Long-term debt subject to fixed rate

6.67%

$ 251

Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032, Variable Rate Two [Member]

Effective percentage rate

4.62%

Long-term debt subject to variable rate

$ 39

Sempra Mexico [Member] | Other Long-term Debt, Currently Through January 2048 [Member]

$ 540

Sempra Mexico [Member] | Other Long Term Debt, Payable Currently Through March 2032, Variable Rate One [Member]

4.875%

Long-term debt subject to variable rate

Weighted average rate

6.29%

$ 178

Sempra Renewables [Member] | Other LongTerm Debt, Variable Rate Loan Payable Currently Through December 2028 [Member]

$ 77

3.668%

Long-term debt subject to fixed rate

3.325%

$ 59

Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member]

Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member] | Minimum [Member]

$ 20

Sempra LNG & Midstream [Member] | Other Long-term Debt, Currently Through October 2026 [Member] | Maximum [Member]

2.87%

Sempra LNG & Midstream [Member] | Other Long Term Debt, Payable Currently Through December 2017 [Member]

3.51%

$ 0

Other Sempra Energy [Member]

8.45%

$ 9,405

7,548

(706)

(722)

Unamortized premium on long-term debt

(13)

(10)

(65)

(31)

LIBOR [Member] | Sempra Energy [Member] | Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]

8,625

6,789

Otay Mesa VIE [Member] | San Diego Gas and Electric Company [Member]

0.45%

(10)

Otay Mesa VIE [Member] | San Diego Gas and Electric Company [Member] | Otay Mesa Energy Center Loan Payable Currently Through April 2019 [Member]

284

293

$ 295

$ 305

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

DEBT AND CREDIT FACILITIES - MATURITIES OF LONG-TERM DEBT (5 YEAR SCHEDULE) (Details)	Dec. 31, 2017 USD ($)
Schedule Of Long Term Debt Maturities [Line Items]
2018	$ 1,412,000,000
2019	1,419,000,000
2020	1,033,000,000
2021	1,346,000,000
2022	647,000,000
Thereafter	11,282,000,000
Long-term Debt Maturities, Total Repayments Of Principal	17,139,000,000
San Diego Gas and Electric Company [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2018	207,000,000
2019	321,000,000
2020	36,000,000
2021	385,000,000
2022	18,000,000
Thereafter	3,901,000,000
Long-term Debt Maturities, Total Repayments Of Principal	4,868,000,000
Southern California Gas Company [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2018	500,000,000
2019	0
2020	0
2021	0
2022	0
Thereafter	2,509,000,000
Long-term Debt Maturities, Total Repayments Of Principal	3,009,000,000
Other Sempra Energy [Member]
Schedule Of Long Term Debt Maturities [Line Items]
2018	705,000,000
2019	1,098,000,000
2020	997,000,000
2021	961,000,000
2022	629,000,000
Thereafter	4,872,000,000
Long-term Debt Maturities, Total Repayments Of Principal	$ 9,262,000,000

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

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

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

DEBT AND CREDIT FACILITIES - OTHER LONG-TERM DEBT (Details) - USD ($)			1 Months Ended	12 Months Ended
	Oct. 13, 2017	Dec. 14, 2016	Jun. 30, 2017	Dec. 31, 2015	Jan. 31, 2018	Dec. 31, 2017	Oct. 30, 2017	Feb. 28, 2017	Dec. 31, 2016
Sempra Energy [Member] \| Other Long-term Debt, Due October 2019 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 500,000,000			$ 500,000,000
Stated percentage rate						1.625%
Sempra Energy [Member] \| Other Long Term Debt, Variable Rate Notes Due March 2021 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 850,000,000	$ 850,000,000		0
Sempra Energy [Member] \| Other Long Term Debt, Variable Rate Notes Due March 2021 [Member] \| LIBOR [Member]
Debt Instrument [Line Items]
Variable percentage rate	0.45%
Sempra Energy [Member] \| Fixed Rate Notes Maturing in 2027 [Member]
Debt Instrument [Line Items]
Stated percentage rate			3.25%
Debt amount			$ 750,000,000
San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 4,573,000,000			4,349,000,000
Luz Del Sur [Member] \| South America Utilities [Member] \| Corporate Bonds Maturing in 2023 [Member]
Debt Instrument [Line Items]
Stated percentage rate								6.375%
Debt amount								$ 50,000,000
Luz Del Sur [Member] \| South America Utilities [Member] \| Corporate Bonds Maturing in 2027 [Member]
Debt Instrument [Line Items]
Stated percentage rate						5.9375%
Debt amount						$ 50,000,000
IEnova [Member] \| Sempra Mexico [Member] \| Ventika [Member]
Debt Instrument [Line Items]
Power purchase agreement term		20 years
Sempra Mexico [Member] \| Other Long Term Debt, Payable Currently Through March 2032 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 468,000,000			481,000,000
Stated percentage rate						6.67%
Sempra Mexico [Member] \| Other Long-term Debt, Currently Through January 2028 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 300,000,000			0
Stated percentage rate						3.75%
Sempra Mexico [Member] \| Other Long-term Debt, Currently Through January 2048 [Member]
Debt Instrument [Line Items]
Gross long-term debt						$ 540,000,000			$ 0
Stated percentage rate						4.875%
Subsequent Event [Member] \| Sempra Energy [Member] \| Fixed and Variable Rate Notes [Member]
Debt Instrument [Line Items]
Gross long-term debt					$ 5,000,000,000
Peaker Plant Facility [Member] \| San Diego Gas and Electric Company [Member]
Debt Instrument [Line Items]
Power purchase agreement term				25 years
Capital lease obligations incurred			$ 500,000,000

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

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

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

INCOME TAXES - DEFERRED INCOME TAXES (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

Less: valuation allowances

$ 133

$ 31

Deferred income taxes, noncurrent

170

234

^[1]

Sempra Energy Consolidated [Member]

2,767

3,745

^[1]

Deferred Tax Liabilities, Gross [Abstract]

Differences in financial and tax bases of fixed assets, investments and other assets

4,233

6,111

U.S. state and non-U.S. withholding tax on repatriation of foreign earnings

360

Other deferred income tax liabilities

376

783

Property taxes

117

143

Total deferred income tax liabilities

5,123

7,100

Compensation-related items

Tax credits

1,066

431

Net operating losses

968

2,304

199

252

Postretirement benefits

251

434

Other deferred income tax assets

115

Accrued expenses not yet deductible

112

Deferred income tax assets before valuation allowances

2,659

3,620

Less: valuation allowances

133

Total deferred income tax assets

2,526

3,589

Net deferred income tax liability

2,597

3,511

Deferred income taxes, noncurrent

170

234

2,767

3,745

Deferred Tax Liabilities, Gross [Abstract]

Differences in financial and tax bases of fixed assets, investments and other assets

1,472

2,549

Other deferred income tax liabilities

113

379

Property taxes

Total deferred income tax liabilities

1,621

2,980

Compensation-related items

Tax credits

Net operating losses

Postretirement benefits

Other deferred income tax assets

State income taxes

Accrued expenses not yet deductible

Total deferred income tax assets

151

Net deferred income tax liability

1,530

2,829

1,530

2,829

^[1]

Deferred Tax Liabilities, Gross [Abstract]

Differences in financial and tax bases of fixed assets, investments and other assets

987

1,699

Other deferred income tax liabilities

271

411

Property taxes

Total deferred income tax liabilities

1,271

2,135

Compensation-related items

Tax credits

Net operating losses

Postretirement benefits

152

244

Other deferred income tax assets

State income taxes

Accrued expenses not yet deductible

Total deferred income tax assets

276

426

Net deferred income tax liability

995

1,709

$ 995

$ 1,709

^[1]

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

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

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

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

EMPLOYEE BENEFIT PLANS - NARRATIVE (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dedicated assets in support of certain benefit plans

$ 455

$ 430

^[1]

Pension Plan [Member]

Change in plan liability due to divestiture

Change in plan assets due to divestiture

Increase in liability due to special termination benefits

194

Other Postretirement Benefits Plan [Member]

Change in plan liability due to divestiture

Change in plan assets due to divestiture

Increase in liability due to special termination benefits

San Diego Gas and Electric Company [Member] | Pension Plan [Member]

Increase in liability due to special termination benefits

San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member]

$ 0

Increase in liability due to special termination benefits

Southern California Gas Company [Member] | Pension Plan [Member]

Increase in liability due to special termination benefits

175

Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member]

Increase in liability due to special termination benefits

$ 0

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

EMPLOYEE BENEFIT PLANS - EMPLOYEE BENEFIT PLANS (Details) - USD ($)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]

$ (1,148,000,000)

$ (1,208,000,000)

^[1]

Net actuarial gain (loss) expected to be amortized next year

(10,000,000)

Prior service cost (credit) expected to be amortized next year

$ 1,000,000

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

7.00%

Pension Plan [Member]

$ 3,679,000,000

3,649,000,000

117,000,000

107,000,000

$ 114,000,000

151,000,000

160,000,000

154,000,000

286,000,000

116,000,000

(182,000,000)

(217,000,000)

(61,000,000)

Plan amendments

1,000,000

Curtailments

(1,000,000)

(194,000,000)

(75,000,000)

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

3,857,000,000

3,679,000,000

3,649,000,000

2,459,000,000

2,484,000,000

421,000,000

207,000,000

155,000,000

104,000,000

(182,000,000)

(217,000,000)

(44,000,000)

(194,000,000)

(75,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

2,659,000,000

2,459,000,000

2,484,000,000

(1,198,000,000)

(1,220,000,000)

(1,198,000,000)

(1,220,000,000)

(69,000,000)

(56,000,000)

(1,129,000,000)

(1,164,000,000)

Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]

(1,198,000,000)

(1,220,000,000)

(84,000,000)

(95,000,000)

(4,000,000)

Total

(88,000,000)

(99,000,000)

Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]

3,551,000,000

3,465,000,000

Projected benefit obligation

3,623,000,000

3,431,000,000

Fair value of plan assets

3,334,000,000

3,227,000,000

2,659,000,000

2,459,000,000

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

117,000,000

107,000,000

114,000,000

151,000,000

160,000,000

154,000,000

(161,000,000)

(166,000,000)

(173,000,000)

11,000,000

Settlement and curtailment charges

36,000,000

30,000,000

38,000,000

38,000,000

16,000,000

4,000,000

38,000,000

16,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

(42,000,000)

(57,000,000)

(110,000,000)

150,000,000

101,000,000

38,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

26,000,000

17,000,000

1,000,000

4,000,000

(18,000,000)

(10,000,000)

(14,000,000)

(1,000,000)

Total recognized in net periodic benefit cost and OCI

(18,000,000)

15,000,000

7,000,000

$ 132,000,000

$ 116,000,000

$ 45,000,000

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.65%

4.08%

4.08%

4.46%

4.09%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

7.00%

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

$ 226,000,000

351,000,000

304,000,000

294,000,000

285,000,000

273,000,000

$ 1,217,000,000

Pension Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

Pension Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

Other Postretirement Benefits Plan [Member]

2.00%

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 922,000,000

$ 963,000,000

21,000,000

20,000,000

$ 26,000,000

39,000,000

42,000,000

44,000,000

20,000,000

6,000,000

(81,000,000)

(63,000,000)

(61,000,000)

(6,000,000)

Plan amendments

18,000,000

26,000,000

Curtailments

(1,000,000)

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

963,000,000

922,000,000

963,000,000

1,057,000,000

1,003,000,000

185,000,000

94,000,000

10,000,000

6,000,000

20,000,000

(63,000,000)

(61,000,000)

(4,000,000)

(1,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

1,209,000,000

1,057,000,000

1,003,000,000

246,000,000

135,000,000

246,000,000

135,000,000

266,000,000

179,000,000

(1,000,000)

(19,000,000)

(44,000,000)

Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]

246,000,000

135,000,000

4,000,000

3,000,000

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

Total

4,000,000

3,000,000

21,000,000

20,000,000

26,000,000

39,000,000

42,000,000

44,000,000

(66,000,000)

(69,000,000)

(68,000,000)

1,000,000

(4,000,000)

Settlement and curtailment charges

(4,000,000)

(1,000,000)

18,000,000

26,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

(11,000,000)

12,000,000

9,000,000

7,000,000

10,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

(2,000,000)

(4,000,000)

Total recognized in net periodic benefit cost and OCI

(2,000,000)

(4,000,000)

$ 7,000,000

$ 5,000,000

$ 6,000,000

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.70%

4.19%

4.19%

4.49%

4.15%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

6.47%

6.98%

Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost

$ 5,000,000

Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost

(4,000,000)

Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations

53,000,000

Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations

(44,000,000)

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

9,000,000

52,000,000

52,000,000

54,000,000

53,000,000

53,000,000

$ 262,000,000

Other Postretirement Benefits Plan [Member] | Pre-65Retiree [Member]

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Rate to which the cost trend rate is assumed to decline (the ultimate trend)

7.00%

8.00%

8.10%

5.00%

Year the rate reaches the ultimate trend

2022

Other Postretirement Benefits Plan [Member] | Retiree Aged 65 or Older [Member]

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Rate to which the cost trend rate is assumed to decline (the ultimate trend)

5.00%

5.50%

4.50%

Year the rate reaches the ultimate trend

2022

Other Postretirement Benefits Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

Other Postretirement Benefits Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

2.00%

Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]

Net actuarial gain (loss) expected to be amortized next year

$ (1,000,000)

Prior service cost (credit) expected to be amortized next year

1,000,000

Southern California Gas Company [Member] | Pension Plan [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

2,343,000,000

$ 2,255,000,000

76,000,000

67,000,000

$ 74,000,000

98,000,000

101,000,000

98,000,000

216,000,000

77,000,000

(73,000,000)

(158,000,000)

(175,000,000)

1,000,000

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

2,486,000,000

2,343,000,000

2,255,000,000

1,579,000,000

1,537,000,000

269,000,000

128,000,000

93,000,000

72,000,000

(73,000,000)

(158,000,000)

1,000,000

(175,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

1,694,000,000

1,579,000,000

1,537,000,000

(792,000,000)

(764,000,000)

(792,000,000)

(764,000,000)

(3,000,000)

(2,000,000)

(789,000,000)

(762,000,000)

Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]

(792,000,000)

(764,000,000)

(6,000,000)

(2,000,000)

(3,000,000)

Total

(8,000,000)

(9,000,000)

Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]

2,241,000,000

2,167,000,000

Projected benefit obligation

2,462,000,000

2,320,000,000

Fair value of plan assets

2,220,000,000

2,148,000,000

1,694,000,000

1,579,000,000

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

76,000,000

67,000,000

74,000,000

98,000,000

101,000,000

98,000,000

(103,000,000)

(106,000,000)

9,000,000

19,000,000

11,000,000

21,000,000

30,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

(34,000,000)

(12,000,000)

(90,000,000)

95,000,000

73,000,000

6,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

4,000,000

2,000,000

(1,000,000)

Total recognized in net periodic benefit cost and OCI

(1,000,000)

6,000,000

2,000,000

$ 94,000,000

$ 79,000,000

$ 8,000,000

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.65%

4.10%

4.10%

4.50%

4.15%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

7.00%

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

$ 113,000,000

192,000,000

188,000,000

179,000,000

173,000,000

172,000,000

$ 782,000,000

Southern California Gas Company [Member] | Pension Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

Southern California Gas Company [Member] | Pension Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member]

2.00%

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 691,000,000

$ 752,000,000

14,000,000

$ 17,000,000

29,000,000

32,000,000

34,000,000

13,000,000

16,000,000

(86,000,000)

(44,000,000)

(45,000,000)

18,000,000

11,000,000

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

737,000,000

691,000,000

752,000,000

870,000,000

822,000,000

151,000,000

79,000,000

3,000,000

1,000,000

13,000,000

(44,000,000)

(45,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

993,000,000

870,000,000

822,000,000

256,000,000

179,000,000

256,000,000

179,000,000

256,000,000

179,000,000

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

256,000,000

179,000,000

14,000,000

17,000,000

29,000,000

32,000,000

34,000,000

(53,000,000)

(56,000,000)

(3,000,000)

(4,000,000)

(7,000,000)

(3,000,000)

18,000,000

11,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

3,000,000

12,000,000

2,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

Total recognized in net periodic benefit cost and OCI

$ 2,000,000

$ 0

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.70%

4.20%

4.20%

4.50%

4.15%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

6.37%

7.00%

Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost

$ 4,000,000

Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost

(3,000,000)

Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations

48,000,000

Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations

(40,000,000)

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

2,000,000

38,000,000

39,000,000

40,000,000

40,000,000

40,000,000

$ 197,000,000

Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

Southern California Gas Company [Member] | Other Postretirement Benefits Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

2.00%

Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract]

$ (182,000,000)

$ (232,000,000)

^[1]

Net actuarial gain (loss) expected to be amortized next year

(1,000,000)

Prior service cost (credit) expected to be amortized next year

San Diego Gas and Electric Company [Member] | Pension Plan [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

935,000,000

965,000,000

29,000,000

$ 29,000,000

38,000,000

41,000,000

39,000,000

50,000,000

7,000,000

(83,000,000)

(25,000,000)

(75,000,000)

2,000,000

(7,000,000)

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

971,000,000

935,000,000

965,000,000

714,000,000

752,000,000

120,000,000

59,000,000

22,000,000

3,000,000

(83,000,000)

(25,000,000)

3,000,000

(75,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

776,000,000

714,000,000

752,000,000

(195,000,000)

(221,000,000)

(195,000,000)

(221,000,000)

(13,000,000)

(10,000,000)

(182,000,000)

(211,000,000)

Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]

(195,000,000)

(221,000,000)

(8,000,000)

Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]

930,000,000

904,000,000

Projected benefit obligation

939,000,000

902,000,000

Fair value of plan assets

900,000,000

874,000,000

776,000,000

714,000,000

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

29,000,000

38,000,000

41,000,000

39,000,000

(47,000,000)

(49,000,000)

(54,000,000)

1,000,000

8,000,000

9,000,000

10,000,000

2,000,000

16,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

(8,000,000)

(45,000,000)

(20,000,000)

22,000,000

3,000,000

4,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

2,000,000

1,000,000

(6,000,000)

(1,000,000)

Total recognized in net periodic benefit cost and OCI

1,000,000

(7,000,000)

$ 23,000,000

$ 3,000,000

$ (3,000,000)

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.64%

4.08%

4.08%

4.35%

4.00%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

7.00%

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

$ 48,000,000

90,000,000

76,000,000

74,000,000

71,000,000

68,000,000

$ 314,000,000

San Diego Gas and Electric Company [Member] | Pension Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

San Diego Gas and Electric Company [Member] | Pension Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member]

2.00%

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 190,000,000

$ 165,000,000

5,000,000

$ 7,000,000

8,000,000

7,000,000

8,000,000

7,000,000

(9,000,000)

6,000,000

(16,000,000)

(14,000,000)

14,000,000

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

185,000,000

190,000,000

165,000,000

169,000,000

161,000,000

30,000,000

13,000,000

5,000,000

2,000,000

7,000,000

(16,000,000)

(14,000,000)

Defined Benefit Plan, Funded (Unfunded) Status of Plan [Abstract]

195,000,000

169,000,000

161,000,000

10,000,000

(21,000,000)

10,000,000

(21,000,000)

10,000,000

(21,000,000)

Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]

10,000,000

(21,000,000)

5,000,000

7,000,000

8,000,000

7,000,000

8,000,000

(11,000,000)

(12,000,000)

(11,000,000)

3,000,000

(1,000,000)

14,000,000

Defined Benefit Plan, Net Periodic Benefit Cost, Total

(14,000,000)

5,000,000

2,000,000

7,000,000

Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax [Abstract]

Total recognized in net periodic benefit cost and OCI

$ 5,000,000

$ 2,000,000

$ 7,000,000

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

3.65%

4.15%

4.15%

4.50%

4.15%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]

6.91%

6.90%

6.91%

Effect of 1% increase on total of service and interest cost components of net periodic postretirement health care benefit cost

$ 1,000,000

Effect of 1% decrease on total of service and interest cost components of net periodic postretirement health care benefit cost

Effect of 1% increase on the health care component of the accumulated other postretirement benefit obligations

3,000,000

Effect of 1% decrease on the health care component of the accumulated other postretirement benefit obligations

(2,000,000)

Defined Benefit Plan, Expected Future Benefit Payment [Abstract]

3,000,000

10,000,000

10,000,000

10,000,000

11,000,000

11,000,000

$ 52,000,000

San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Maximum [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

10.00%

San Diego Gas and Electric Company [Member] | Other Postretirement Benefits Plan [Member] | Minimum [Member]

10.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

2.00%

Mobile Gas [Member] | Other Postretirement Benefits Plan [Member]

2.00%

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Rate to which the cost trend rate is assumed to decline (the ultimate trend)

8.10%

5.00%

Year the rate reaches the ultimate trend

2022

Chilquinta Energia [Member] | Other Postretirement Benefits Plan [Member]

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Rate to which the cost trend rate is assumed to decline (the ultimate trend)

3.00%

3.00%

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

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

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

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

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

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

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

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

DERIVATIVE FINANCIAL INSTRUMENTS - INCOME STATEMENT (Details) - USD ($)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Derivative Instruments, Gain (Loss) [Line Items]

Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]

$ (7,000,000)

$ (21,000,000)

^[1]

$ 10,000,000

^[1]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) on fair value hedge ineffectiveness

1,000,000

Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Other Income [Member] | Interest rate instruments [Member]

3,000,000

6,000,000

Derivative Instruments, Gain (Loss) [Line Items]

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

(2,000,000)

(5,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

(8,000,000)

(21,000,000)

(106,000,000)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(23,000,000)

(33,000,000)

(29,000,000)

Loss on cash flow hedge ineffectiveness

5,000,000

4,000,000

2,000,000

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate and foreign exchange instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

19,000,000

(8,000,000)

(18,000,000)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

4,000,000

(17,000,000)

(18,000,000)

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Equity Earnings Before Income Tax [Member] | Interest rate instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

(25,000,000)

(9,000,000)

(80,000,000)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(8,000,000)

(10,000,000)

(12,000,000)

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Remeasurement of Equity Method Investment [Member] | Interest rate and foreign exchange instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(7,000,000)

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Equity Earnings Net Of Income Tax [Member] | Interest rate and foreign exchange instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

(9,000,000)

5,000,000

(20,000,000)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(12,000,000)

(5,000,000)

(13,000,000)

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

3,000,000

(13,000,000)

12,000,000

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(9,000,000)

6,000,000

14,000,000

Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Revenues: Energy-Related Businesses [Member] | Foreign exchange instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

4,000,000

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

2,000,000

Not Designated as Hedging Instrument [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Other Income [Member] | Interest rate and foreign exchange instruments [Member]

118,000,000

(103,000,000)

(92,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Equity Earnings Net Of Income Tax [Member] | Foreign exchange instruments [Member]

49,000,000

(32,000,000)

(4,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]

1,000,000

3,000,000

(4,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]

16,000,000

(18,000,000)

42,000,000

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Cost of Electric Fuel and Purchased Power [Member] | Commodity contracts subject to rate recovery [Member]

1,000,000

(1,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Not Designated as Hedging Instrument [Member] | Cost of Natural Gas [Member] | Commodity contracts subject to rate recovery [Member]

54,000,000

(53,000,000)

(126,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

(2,000,000)

(4,000,000)

1,000,000

Derivative Instruments, Gain (Loss) [Line Items]

San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

2,000,000

3,000,000

^[1]

4,000,000

^[1]

Derivative Instruments, Gain (Loss) [Line Items]

Loss on cash flow hedge ineffectiveness

San Diego Gas and Electric Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

(2,000,000)

(6,000,000)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(13,000,000)

(12,000,000)

San Diego Gas and Electric Company [Member] | Not Designated as Hedging Instrument [Member] | Cost of Electric Fuel and Purchased Power [Member] | Commodity contracts subject to rate recovery [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Southern California Gas Company [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Expense [Member] | Interest rate instruments [Member]

54,000,000

(53,000,000)

(126,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Pretax gain (loss) on derivative recognized in OCI (effective portion)

Pretax gain (loss) reclassified from AOCI into earnings (effective portion)

(1,000,000)

Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery [Member]

(2,000,000)

(3,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

Southern California Gas Company [Member] | Not Designated as Hedging Instrument [Member] | Cost of Natural Gas [Member] | Commodity contracts subject to rate recovery [Member]

1,000,000

(1,000,000)

Derivative Instruments, Gain (Loss) [Line Items]

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

$ (2,000,000)

$ (4,000,000)

$ 1,000,000

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

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

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

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

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

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

1 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 26, 2016

May 31, 2016

Mar. 31, 2016

Jun. 30, 2017

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

Sep. 29, 2016

May 09, 2016

Mar. 29, 2016

$ 0

$ 617

^[1]

$ 0

Market Approach Valuation Technique [Member] | IEnova Pipelines [Member] | Level 2 [Member]

2,517

$ 2,080

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

% of fair value measurement

$ 1,144

100.00%

Range of inputs

100.00%

Market Approach Valuation Technique [Member] | TdM [Member] | Level 2 [Member]

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

% of fair value measurement

$ 62

$ 78

$ 145

100.00%

Range of inputs

100.00%

Market Approach Valuation Technique [Member] | Rockies Express [Member] | Level 2 [Member]

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

% of fair value measurement

$ 440

100.00%

Range of inputs

100.00%

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

50.00%

100.00%

Gain on acquisition of remaining voting rights, net of tax

$ 617

432

1,144

Reclassification adjustment from AOCI

520

(7)

Fair value of business combination

$ 2,288

Sempra Mexico [Member] | TdM [Member]

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

Other than temporary impairment in investment, net of tax

$ 71

$ 131

$ 111

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

Other than temporary impairment in investment, net of tax

$ 44

$ 27

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

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

25.00%

$ 440

484

Other than temporary impairment in investment, net of tax

$ 44

$ 27

Proceeds from sale of investments

$ 443

$ 440

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

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

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

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

SEMPRA ENERGY - SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE - COMMON STOCK ACTIVITY (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Jan. 09, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Earnings Per Share [Abstract]

Common stock, shares authorized

750,000,000

Common stock par value (in dollars per share)

$ 0

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Common shares outstanding, January 1

250,152,514

248,298,080

246,330,884

RSUs vesting

362,022

1,363,555

1,499,062

Stock options exercised

164,454

167,742

227,815

Savings plan issuance

567,428

653,607

652,631

Common stock investment plan

254,047

266,056

249,665

Issuance of RSUs held in our Deferred Compensation Plan

7,811

Shares repurchased

149,299

596,526

661,977

Common shares outstanding, December 31

251,358,977

250,152,514

248,298,080

Schedule of Capitalization, Equity [Line Items]

Subsequent Event [Member] | Public Offering [Member]

$ 47

$ 51

^[1]

$ 52

^[1]

Schedule of Capitalization, Equity [Line Items]

Shares issued

23,364,486

Subsequent Event [Member] | Over-Allotment Option [Member]

Schedule of Capitalization, Equity [Line Items]

Shares issued

3,504,672

Jointly Owned Utility Plant Interests [Line Items]

$ 368

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

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - NARRATIVE (Details) - USD ($)
$ in Millions

1 Months Ended

12 Months Ended

Mar. 13, 2017

Apr. 30, 2016

Oct. 31, 2015

Dec. 31, 2017

Feb. 28, 2017

Dec. 31, 2016

^[1]

Nuclear plant closure regulatory asset, current

$ 325

$ 348

Nuclear plant closure regulatory asset, noncurrent

1,517

3,414

Litigation settlement payable

$ 1,033

1,026

$ 118

Percent of arbitration expenses awarded

95.00%

Settlement payable net of arbitration expense

$ 60

Period of environmental exit

10 years

SONGS mitigation costs remaining

$ 4,400

San Onofre Nuclear Generating Station (SONGS) [Member]

Jointly Owned Utility Plant Interests [Line Items]

Insurance recovery

$ 400

Jointly Owned Utility Plant Interests [Line Items]

Nuclear plant closure regulatory asset, current

$ 316

340

Nuclear plant closure regulatory asset, noncurrent

451

2,012

Decommissioning liability

1,033

$ 1,026

607

Cost study estimate decommissioning escalated

$ 1,000

Litigation settlement payable

Arbitration expense

Settlement payable net of arbitration expense

Legal fees

Litigation settlement amount allocated to ratepayers and shareholders

$ 1

Percentage of environmental exit costs incurred

20.00%

SONGS mitigation costs remaining

$ 899

$ 24

Nuclear decommissioning trust authorized recovery amount

362

$ 60

San Diego Gas and Electric Company [Member] | Nuclear Plant Closure [Member]

Jointly Owned Utility Plant Interests [Line Items]

Regulatory asset threshold to cease rate recovery

775

Receivable for nuclear plant closure

152

Nuclear plant closure regulatory asset, current

Nuclear plant closure regulatory asset, noncurrent

$ 120

San Diego Gas and Electric Company [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]

Jointly Owned Utility Plant Interests [Line Items]

Ownership percentage

20.00%

Portion of weighted average return on preferred stock included in nuclear plant return on ratebase

50.00%

Insurance recovery

$ 80

Recovery allocation percentage

5.00%

Ratepayers [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]

Jointly Owned Utility Plant Interests [Line Items]

Amount funded to customers through Energy Resource Recovery Account

$ 75

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

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

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL (Details) - USD ($)
$ in Millions

1 Months Ended

12 Months Ended

Apr. 18, 2016

Oct. 31, 2017

May 31, 2017

Feb. 28, 2017

Sep. 30, 2016

May 31, 2016

Dec. 31, 2017

Dec. 31, 2016

^[1]

Dec. 31, 2015

^[1]

Jointly Owned Utility Plant Interests [Line Items]

Decrease in nuclear decommissioning balancing account

$ (108)

$ (198)

$ (586)

Jointly Owned Utility Plant Interests [Line Items]

Decommissioning liability

607

Cost study estimate decommissioning escalated

1,000

Decrease in nuclear decommissioning balancing account

$ (56)

$ (35)

$ (474)

San Diego Gas and Electric Company [Member] | Total Ownership [Member]

Jointly Owned Utility Plant Interests [Line Items]

Damages awarded to other party

$ 162

$ 43

Damages sought

$ 58

$ 56

San Diego Gas and Electric Company [Member] | San Onofre Nuclear Generating Station (SONGS) [Member]

Jointly Owned Utility Plant Interests [Line Items]

Damages awarded to other party

$ 9

$ 32

Damages sought

$ 12

Decrease in regulatory asset

(23)

Decrease in nuclear decommissioning balancing account

(8)

Decrease in SONGS O&M cost balancing account

$ (1)

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

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS) - NUCLEAR INSURANCE (Details) - San Diego Gas and Electric Company [Member] - USD ($) $ in Millions	Jan. 10, 2018	Jan. 09, 2018	Jan. 05, 2018	Jan. 04, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Maximum required nuclear liability insurance available					$ 450.0
Maximum secondary financial protection available					13,000.0
Maximum required company contribution if nuclear liability loss occurs					50.9
Annual maximum required company contribution if nuclear liability loss occurs					7.6
Federal nuclear property damage insurance, minimum required					1,060.0
Federal nuclear property damage insurance premium assessment					10.4
Maximum nuclear property insurance terrorism coverage					$ 3,240.0
Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Maximum required nuclear liability insurance available			$ 100.0	$ 450.0
Federal nuclear property damage insurance, minimum required	$ 50.0	$ 1,060.0

REGULATORY MATTERS - REGULATORY ACCOUNTS (Details) - USD ($)
$ in Millions

2 Months Ended

12 Months Ended

Feb. 27, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

$ 351

$ 0

^[1]

$ 0

^[1]

Amortization expense on regulatory assets

35.00%

$ 50

$ 65

$ 62

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Net Regulatory Assets (Liabilities) Sempra Energy Consolidated [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

(2,189)

764

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Regulatory balancing accounts - net undercollected, Noncurrent

$ 351

$ 0

^[1]

$ 0

^[1]

Amortization expense on regulatory assets

35.00%

$ 49

$ 63

$ 60

San Diego Gas and Electric Company [Member] | Fixed-price contracts and other derivatives [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Costs related to SONGS plant closure [Member]

141

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Costs related to wildfire litigation [Member]

183

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Deferred income taxes (refundable) recoverable in rates [Member]

353

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Pension and other postretirement benefit plan obligations [Member]

(281)

1,014

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Removal obligations [Member]

153

210

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member]

(1,846)

(1,725)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member] | Maximum [Member]

$ 9

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Unamortized loss on reacquired debt [Member] | Minimum [Member]

10 years

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Environmental costs [Member]

1 year

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Legacy meters [Member]

$ 29

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Sunrise Powerlink fire mitigation [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

$ 119

118

San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Commodity – electric [Member]

52-year

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Gas transportation [Member]

$ 82

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Safety and reliability [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Public purpose programs [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Regulatory Balancing Accounts, Other balancing accounts [Member]

(70)

(106)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Other regulatory (liabilities) assets [Member]

233

249

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

San Diego Gas and Electric Company [Member] | Net Regulatory Assets (Liabilities) SDGE [Member]

(70)

(2)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

(1,476)

627

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Regulatory balancing accounts - net undercollected, Noncurrent

$ 118

$ 85

Amortization expense on regulatory assets

35.00%

$ 1

$ 2

Southern California Gas Company [Member] | Deferred income taxes (refundable) recoverable in rates [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Pension and other postretirement benefit plan obligations [Member]

(437)

417

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Employee benefit costs [Member]

513

563

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Removal obligations [Member]

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member]

(924)

(972)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member] | Maximum [Member]

$ 8

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Unamortized loss on reacquired debt [Member] | Minimum [Member]

8 years

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Environmental costs [Member]

3 years

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Workers’ compensation [Member]

$ 22

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Regulatory Balancing Accounts, Commodity - gas including transportation

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Regulatory Balancing Accounts, Safety and reliability [Member]

151

207

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Regulatory Balancing Accounts, Public purpose programs [Member]

266

230

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Regulatory Balancing Accounts, Other balancing accounts [Member]

(274)

(270)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Other regulatory (liabilities) assets [Member]

(114)

(204)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Southern California Gas Company [Member] | Net Regulatory Assets (Liabilities) SoCalGas [Member]

(64)

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

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

(796)

$ 66

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

Subsequent Event [Member]

$ 351

Schedule Of Net Regulatory Assets (Liabilities) [Line Items]

21.00%

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

REGULATORY MATTERS - GENERAL RATE CASE (Details) - USD ($) $ in Millions			1 Months Ended	3 Months Ended		12 Months Ended
	Oct. 06, 2017	Oct. 31, 2016	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2017	Sep. 30, 2016
Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement	$ 2,989
GRC requested revenue requirement adjustment	533
Refund of tax memorandum account, pre-tax				$ 72
Refund of tax memorandum account, net of tax				(43)
Change in tax estimates, pre-tax				(11)
Change in tax estimates, net of tax				(6)	$ 6
Adjustment to revenue related to tax repairs deductions, pre-tax				(83)
Adjustment to revenue related to tax repairs deductions, net of tax				(49)
Southern California Gas Company [Member] \| Year 2016 [Member]
General Rate Case [Line Items]
GRC revenue requirement			$ 2,204
Rate base adjustment						$ 38
Revenue requirement adjustment						$ 5
Change in income tax liability from prior year							$ (19)
Southern California Gas Company [Member] \| Years 2017 and 2018 [Member]
General Rate Case [Line Items]
Change in GRC revenue requirement						3.50%
Z Factor Mechanism, Deductible Per Event						$ 5
Southern California Gas Company [Member] \| Years 2012 through 2014 [Member]
General Rate Case [Line Items]
Regulatory liability			11		11
Southern California Gas Company [Member] \| Year 2015 [Member]
General Rate Case [Line Items]
Amended requested change in rate		$ 32
Southern California Gas Company [Member] \| General Rate Case [Member]
General Rate Case [Line Items]
Tracked income tax expense liability						65
San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement	2,199
GRC requested revenue requirement adjustment	$ 217
Refund of tax memorandum account, pre-tax				37
Refund of tax memorandum account, net of tax				(22)
Change in tax estimates, pre-tax				(15)
Change in tax estimates, net of tax				(9)	9
Adjustment to revenue related to tax repairs deductions, pre-tax				(52)
Adjustment to revenue related to tax repairs deductions, net of tax				$ (31)
San Diego Gas and Electric Company [Member] \| Year 2016 [Member]
General Rate Case [Line Items]
GRC revenue requirement			1,791
Rate base adjustment						55
Revenue requirement adjustment						7
Change in income tax liability from prior year							$ (5)
San Diego Gas and Electric Company [Member] \| Years 2012 through 2014 [Member]
General Rate Case [Line Items]
Regulatory liability			$ 15		$ 15
San Diego Gas and Electric Company [Member] \| Year 2015 [Member]
General Rate Case [Line Items]
Amended requested change in rate		$ 53
San Diego Gas and Electric Company [Member] \| General Rate Case [Member]
General Rate Case [Line Items]
Tracked income tax expense liability						$ 69
Minimum [Member] \| Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	6.00%
Minimum [Member] \| San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	5.00%
Maximum [Member] \| Southern California Gas Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	8.00%
Maximum [Member] \| San Diego Gas and Electric Company [Member]
General Rate Case [Line Items]
GRC requested revenue requirement adjustment percentage	7.00%

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

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

1 Months Ended

12 Months Ended

Feb. 22, 2018

plaintiff

lawsuit

Jul. 19, 2017

Bcf

Mar. 13, 2017

Mar. 31, 2016

Feb. 28, 2017

USD ($)

Jan. 31, 2017

lawsuit

Sep. 30, 2016

USD ($)

Dec. 31, 2017

USD ($)

Bcf

appeal

Dec. 31, 2016

USD ($)

Dec. 31, 2016

GBP (£)

Dec. 31, 2015

USD ($)

^[1]

Dec. 31, 2015

GBP (£)

Oct. 21, 2016

Oct. 01, 2014

GBP (£)

$ 92,000,000

Litigation Settlement, Percent of Arbitration Expenses

351,000,000

$ 0

^[1]

$ 0

95.00%

84,000,000

53,000,000

^[2]

3,000,000

351,000,000

^[1]

$ 0

Recoverable costs through insurance settlement

88,000,000

887,000,000

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

$ 84,000,000

$ 53,000,000

^[2]

Number of Appeals Pending | appeal

Write-off of wildfire regulatory asset net of tax

$ 351,000,000

208,000,000

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

Litigation Settlement, Percent of Arbitration Expenses

95.00%

Aliso Canyon Natural Gas Storage Facility Gas Leak [Member]

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

$ 83,000,000

Amount of Natural Gas Released | Bcf

4.62

Perecentage of recorded estimated costs allocated to temporary relocation program

$ 83,000,000

Recorded estimated costs

$ 913,000,000

60.00%

Recoverable costs through insurance settlement

$ 887,000,000

84,000,000

Proceeds from Insurance Settlement, Operating Activities

418,000,000

$ 469,000,000

Loss Contingency, Period Of Required Climate Reductions

20 years

Loss Contingency, Period Of Required Regulatory Climate Reductions

100 years

Loss Contingency, Target Emissions Level | t

9,000,000

Loss Contingency, Total Actual Emissions, Floor | t

90,350

Loss Contingency, Total Actual Emissions, Ceiling | t

108,950

Loss Contingency, Mitigation Requirement | t

109,000

Storage Facility Maximum Capacity | Bcf

Aliso Canyon Facility As A Percentage of SoCalGas Total Storage Capacity

28.00%

63.00%

Storage Facility, Working Gas Target | Bcf

23.6

Storage Facility, Working Gas Minimum | Bcf

14.8

Net Book Value Of Aliso Canyon Natural Gas Storage Facility

$ 644,000,000

Construction in Work Progress Of Aliso Canyon Natural Gas Storage Facility

$ 252,000,000

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

Maximum Occupational Safety And Health Fines

$ 75,000

Penalty Assessments

233,500

Maximum Other Assessments

$ 5,000,000

Sempra Mexico Property Disputes [Member]

HMRC VAT Claim [Member] | Plaintiffs [Member]

Number of lawsuits

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

Damages sought | £

£ 80

VAT Tax Claim Paid Upon Appeal | £

£ 86

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

Number of lawsuits | lawsuit

373

Number Of Plaintiffs | plaintiff

45,000

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

Liability insurance coverage

$ 1,200,000,000

Loss Contingency, Environmental Mitigation Period

5 years

Storage Facility, Working Gas Target | Bcf

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

Liability insurance coverage

1,400,000,000

Loss Contingency, Environmental Mitigation Period

10 years

Storage Facility, Working Gas Target | Bcf

24.6

Consolidated Class Action Complaints [Member]

Number of lawsuits | lawsuit

Property Class Action [Member]

Number of lawsuits | lawsuit

Complaints Filed by Public Entities [Member]

Litigation Settlement, Amount Awarded to Other Party

$ 8,500,000

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

Litigation Settlement, Amount Awarded to Other Party

$ 1,000,000

R B S Sempra Commodities [Member]

Investment in RBS Sempra Commodities LLP

Damages sought | £

£ 160

$ 67,000,000

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

COMMITMENTS AND CONTINGENCIES - LONG-TERM PURCHASE COMMITMENT (Details)		1 Months Ended		12 Months Ended
	Mar. 13, 2017 USD ($)	May 31, 2017 USD ($)	May 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2011 USD ($) MMcf
Long-term Purchase Commitment [Line Items]
Litigation settlement payable	$ 118,000,000
Sempra LNG & Midstream [Member]
Long-term Purchase Commitment [Line Items]
Loss on release of pipeline capacity			$ 206,000,000
Litigation settlement payable		$ 57,000,000	47,000,000
San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Litigation settlement payable	$ 24,000,000
Sempra LNG & Midstream [Member]
Long-term Purchase Commitment [Line Items]
Loss on release of pipeline capacity			206,000,000
Loss on release of pipeline capacity net of tax			$ 123,000,000
Natural Gas Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				$ 292,000,000
2019				146,000,000
2020				48,000,000
2021				47,000,000
2022				45,000,000
Thereafter				127,000,000
Total Contractual Commitments				705,000,000
Purchases				1,429,000,000	$ 1,169,000,000	$ 1,200,000,000
Natural Gas Contracts [Member] \| SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				108,000,000
2019				59,000,000
2020				29,000,000
2021				28,000,000
2022				28,000,000
Thereafter				81,000,000
Total Contractual Commitments				333,000,000
Purchases				1,213,000,000	966,000,000	975,000,000
Natural Gas Storage and Transportation Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				231,000,000
2019				146,000,000
2020				48,000,000
2021				46,000,000
2022				44,000,000
Thereafter				127,000,000
Total Contractual Commitments				642,000,000
Natural Gas Transportation Contracts [Member] \| SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				108,000,000
2019				59,000,000
2020				29,000,000
2021				27,000,000
2022				27,000,000
Thereafter				81,000,000
Total Contractual Commitments				331,000,000
Natural Gas Supply Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				61,000,000
2019				0
2020				0
2021				1,000,000
2022				1,000,000
Thereafter				0
Total Contractual Commitments				63,000,000
Natural Gas Supply Contracts [Member] \| SoCalGas [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				0
2019				0
2020				0
2021				1,000,000
2022				1,000,000
Thereafter				0
Total Contractual Commitments				2,000,000
Purchased Power Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				702,000,000
2019				690,000,000
2020				631,000,000
2021				633,000,000
2022				598,000,000
Thereafter				5,726,000,000
Total Contractual Commitments				8,980,000,000
Purchases				1,694,000,000	1,667,000,000	1,573,000,000
Purchased Power Contracts [Member] \| SDG&E [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				577,000,000
2019				571,000,000
2020				510,000,000
2021				510,000,000
2022				496,000,000
Thereafter				5,457,000,000
Total Contractual Commitments				8,121,000,000
Purchases				781,000,000	752,000,000	715,000,000
Sunrise Powerlink Construction [Member] \| SDG&E [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
2018				3,000,000
2019				3,000,000
2020				3,000,000
2021				3,000,000
2022				3,000,000
Thereafter				104,000,000
Total Commitment				$ 119,000,000
Annual estimated escalation percentage				2.00%
Commitment period				52 years
Present value of future payments				$ 119,000,000
Continental Forge [Member] \| Sempra LNG & Midstream [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
Commitment period							18 years
Amount of Natural Gas to be Sold \| MMcf							500
Reduction in price index							$ 0.02
Liquefied Natural Gas Contracts [Member] \| Sempra LNG & Midstream [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				302,000,000
2019				383,000,000
2020				391,000,000
2021				403,000,000
2022				411,000,000
Thereafter				2,935,000,000
Total Contractual Commitments				4,825,000,000
Nuclear Plant Maintenance [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				10,000,000
Infrastructure Construction And Improvements [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				257,000,000
2019				62,000,000
2020				44,000,000
2021				24,000,000
2022				16,000,000
Thereafter				124,000,000
Total Contractual Commitments				527,000,000
Infrastructure Construction And Improvements [Member] \| San Diego Gas and Electric Company [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				1,000,000
2019				1,000,000
2020				1,000,000
Infrastructure Construction And Improvements [Member] \| California Utilities [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
Total Contractual Commitments				10,000,000
Infrastructure Construction And Improvements [Member] \| Southern California Gas Company [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				3,000,000
2019				2,000,000
2020				2,000,000
Infrastructure Construction And Improvements [Member] \| SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				117,000,000
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				78,000,000
2019				9,000,000
2020				19,000,000
2021				5,000,000
2022				1,000,000
Thereafter				5,000,000
Infrastructure Construction And Improvements [Member] \| Sempra South American Utilities [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				16,000,000
Infrastructure Improvements For Natural Gas And Electric Transmission And Distribution [Member] \| SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				$ 72,000,000
Long-term Contracts [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				43.00%
Other Owned Generation [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				56.00%
Spot Market Purchases [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				1.00%
Renewable Energy Contracts Expiring Through 2041 [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Purchase Commitment Component Percentage				37.00%
Sempra Renewables Construction [Member] \| Sempra Renewables [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				$ 80,000,000
2019				4,000,000
2020				3,000,000
2021				2,000,000
Total Contractual Commitments				89,000,000
Sempra Natural Gas Construction [Member] \| Sempra LNG & Midstream [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				6,000,000
San Luis Rey Synchronous Condensor And Bay Boulevard Substation [Member] \| SDG&E [Member]
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment				35,000,000
Pipelines [Member] \| Sempra Mexico [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
2018				73,000,000
2019				46,000,000
2020				19,000,000
2021				17,000,000
2022				15,000,000
Thereafter				119,000,000
Total Contractual Commitments				289,000,000
Renewable Energy PPAs [Member] \| SDG&E [Member]
Unrecorded Unconditional Purchase Obligation, Rolling Maturity [Abstract]
Total Contractual Commitments				5,400,000,000
Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2018				192,000,000
Power Purchase Agreements [Member] \| San Diego Gas and Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Capital lease depreciation expense				$ 8,000,000	$ 4,000,000	$ 4,000,000

COMMITMENTS AND CONTINGENCIES - OPERATING LEASES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 109	$ 77	$ 78
Future minimum lease payments
2018	85
2019	57
2020	51
2021	48
2022	42
Thereafter	300
Total	583
Future estimated rental payments
2018	13
2019	12
2020	12
2021	12
2022	13
Thereafter	46
Total	108
Total future rental commitments
2018	98
2019	69
2020	63
2021	60
2022	55
Thereafter	346
Total	$ 691
San Diego Gas and Electric Company [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 28	28	27
Future minimum lease payments
2018	22
2019	21
2020	20
2021	19
2022	18
Thereafter	54
Total	154
Future estimated rental payments
2018	2
2019	2
2020	2
2021	2
2022	2
Thereafter	3
Total	13
Total future rental commitments
2018	24
2019	23
2020	22
2021	21
2022	20
Thereafter	57
Total	167
Utility Subsidiaries [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Aggregate maximum lease limit	250
Lease limit utilized	$ 133
Southern California Gas Company [Member]
Operating Leases, Annual Rent Escalation [Abstract]
Minimum annual rent escalation	2.00%
Maximum annual rent escalation	5.00%
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 43	$ 38	$ 39
Future minimum lease payments
2018	29
2019	25
2020	20
2021	19
2022	13
Thereafter	36
Total	142
Future estimated rental payments
2018	11
2019	10
2020	10
2021	10
2022	11
Thereafter	43
Total	95
Total future rental commitments
2018	40
2019	35
2020	30
2021	29
2022	24
Thereafter	79
Total	$ 237

COMMITMENTS AND CONTINGENCIES - CAPITAL LEASES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Power Purchase Agreements [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2018	$ 192
2019	210
2020	210
2021	210
2022	210
Thereafter	3,299
Total minimum payments	4,331
Less: estimated executory costs	(502)
Less: interest	(2,548)
Present value of net minimum lease payments	1,281
Capital leases, Current portion	13
Capital leases, Noncurrent portion	718
Power Purchase Agreement Upon Completion of Power Plant [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Present value of net minimum lease payments	$ 550
HQ Build To Suit Lease [Member]
Leases, Capital [Abstract]
Capital Lease Term (Years)	25
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2018	$ 10
2019	10
2020	11
2021	11
2022	11
Thereafter	234
Total minimum payments	287
Present value of net minimum lease payments	138
Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2018	4
2019	2
2020	1
2021	0
2022	0
Thereafter	8
Present value of net minimum lease payments	8
Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	3	$ 2	$ 4
San Diego Gas and Electric Company [Member]
Leases, Capital [Abstract]
Capital lease obligations	$ 732	240
San Diego Gas and Electric Company [Member] \| Power Purchase Agreements [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	5
Number Of Power Purchase Agreements With Peaker Facilities In Commercial Operation In 2015	1
Capital lease obligations	$ 731
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 8	4	4
San Diego Gas and Electric Company [Member] \| Purchase Power Agreements With 25 Year Term [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	4
Capital Lease Term (Years)	25
San Diego Gas and Electric Company [Member] \| Purchase Power Agreements With 9 Year Term [Member]
Leases, Capital [Abstract]
Number Of Power Purchase Agreements With Peaker Facilities, Capital Leases	1
Capital Lease Term (Years)	9
San Diego Gas and Electric Company [Member] \| Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2018	$ 1
San Diego Gas and Electric Company [Member] \| Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 1	1	2
San Diego Gas and Electric Company [Member] \| Intermediate Stage Power Plant Facility [Member]
Leases, Capital [Abstract]
Power purchase agreement term	20 years
Generating capacity (in mw) \| MW	500
Southern California Gas Company [Member]
Leases, Capital [Abstract]
Capital lease obligations	$ 1	0
Southern California Gas Company [Member] \| Fleet And Other Capital Leases [Member]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2018	1
Southern California Gas Company [Member] \| Utility Fleet Leases [Member]
Capital Leases, Income Statement of Lessee [Abstract]
Capital lease depreciation expense	$ 2	$ 1	$ 2

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

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

SEGMENT INFORMATION (Details)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

segment

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Segment Reporting Information [Line Items]

Number of Reportable Segments | segment

Segment Reporting Information, Profit (Loss) [Abstract]

$ 11,207

$ 10,183

$ 10,231

659

553

561

Segment reporting information, Depreciation and Amortization

1,490

1,312

1,250

Segment reporting information, Income Tax Expense (Benefit)

1,276

389

341

Segment Reporting Information, Additional Information [Abstract]

$ (501)

$ 57

$ 259

$ 441

$ 379

$ 622

$ 16

$ 353

256

1,370

1,349

Segment Reporting Information Expenditures For Property Plant and Equipment

50,454

47,786

^[1]

50,454

47,786

^[1]

41,150

3,949

4,214

3,156

Entity-Wide Disclosure On Geographic Areas, United States [Member]

39,030

35,028

39,030

35,028

30,944

Segment Reporting Information, Profit (Loss) [Abstract]

Segment Reporting Information, Additional Information [Abstract]

8,547

8,004

8,119

Entity-Wide Disclosure On Geographic Areas, South America [Member]

31,487

28,351

31,487

28,351

26,132

Segment Reporting Information, Profit (Loss) [Abstract]

Segment Reporting Information, Additional Information [Abstract]

1,567

1,556

1,544

Entity-Wide Disclosure On Geographic Areas Mexico [Member]

2,180

1,863

2,180

1,863

1,652

Segment Reporting Information, Profit (Loss) [Abstract]

Segment Reporting Information, Additional Information [Abstract]

1,093

623

568

Operating Segments [Member] | SDG&E [Member]

5,363

4,814

5,363

4,814

3,160

Segment Reporting Information, Profit (Loss) [Abstract]

4,476

4,253

4,219

Segment reporting information, Depreciation and Amortization

203

195

204

670

646

604

Segment reporting information, Income Tax Expense (Benefit)

155

280

284

Segment Reporting Information, Additional Information [Abstract]

407

570

587

Segment Reporting Information Expenditures For Property Plant and Equipment

17,844

17,719

17,844

17,719

16,515

1,555

1,399

1,133

Operating Segments [Member] | SoCalGas [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

3,785

3,471

3,489

102

Segment reporting information, Depreciation and Amortization

515

476

461

Segment reporting information, Income Tax Expense (Benefit)

160

143

138

Segment Reporting Information, Additional Information [Abstract]

396

349

419

Segment Reporting Information Expenditures For Property Plant and Equipment

14,159

13,424

14,159

13,424

12,104

1,367

1,319

1,352

Operating Segments [Member] | Sempra South American Utilities [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

1,567

1,556

1,544

Segment reporting information, Depreciation and Amortization

Segment reporting information, Income Tax Expense (Benefit)

Segment Reporting Information, Additional Information [Abstract]

186

156

175

Segment Reporting Information Expenditures For Property Plant and Equipment

4,060

3,591

4,060

3,591

3,235

244

194

154

Operating Segments [Member] | Sempra Mexico [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

1,196

725

669

Segment reporting information, Depreciation and Amortization

156

Segment reporting information, Income Tax Expense (Benefit)

227

188

Segment Reporting Information, Additional Information [Abstract]

169

463

213

Segment Reporting Information Expenditures For Property Plant and Equipment

8,554

7,542

8,554

7,542

3,783

248

330

302

Operating Segments [Member] | Sempra Renewables [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment reporting information, Depreciation and Amortization

Segment reporting information, Income Tax Expense (Benefit)

(226)

(38)

(49)

Segment Reporting Information, Additional Information [Abstract]

252

Segment Reporting Information Expenditures For Property Plant and Equipment

2,898

3,644

2,898

3,644

1,441

497

835

Operating Segments [Member] | Sempra LNG & Midstream [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

540

508

653

Segment reporting information, Depreciation and Amortization

Segment reporting information, Income Tax Expense (Benefit)

(119)

(80)

Segment Reporting Information, Additional Information [Abstract]

150

(107)

Segment Reporting Information Expenditures For Property Plant and Equipment

4,872

5,564

4,872

5,564

5,566

117

Adjustment and Elimination [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Segment Reporting Information, Profit (Loss) [Abstract]

(1)

(2)

All Other [Member]

Segment reporting information, Depreciation and Amortization

284

282

263

Segment reporting information, Income Tax Expense (Benefit)

999

(184)

(138)

Segment Reporting Information, Additional Information [Abstract]

(1,304)

(116)

(152)

Segment Reporting Information Expenditures For Property Plant and Equipment

915

475

915

475

734

Intersegment Eliminations [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

(450)

(364)

(377)

(119)

(120)

Segment Reporting Information, Additional Information [Abstract]

(69)

(78)

(80)

Intersegment Eliminations [Member] | SDG&E [Member]

$ (2,848)

$ (4,173)

(2,848)

(4,173)

(2,228)

Segment Reporting Information, Profit (Loss) [Abstract]

Intersegment Eliminations [Member] | SoCalGas [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Intersegment Eliminations [Member] | Sempra Mexico [Member]

Segment Reporting Information, Profit (Loss) [Abstract]

Intersegment Eliminations [Member] | Sempra LNG & Midstream [Member]

103

102

101

Segment Reporting Information, Profit (Loss) [Abstract]

Significant Items Affecting Quarterly Results [Line Items]

$ 266

$ 180

$ 192

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

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

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

1 Months Ended

3 Months Ended

12 Months Ended

Jun. 30, 2017

May 31, 2017

Sep. 30, 2016

May 31, 2016

Mar. 31, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

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

$ 870

351

$ 0

^[1]

$ 0

Significant Items Affecting Quarterly Results [Line Items]

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

351

^[1]

$ 0

Significant Items Affecting Quarterly Results [Line Items]

Other than temporary impairment in investment, net of tax

$ 44

$ 27

Loss on release of pipeline capacity

$ 206

Loss on release of pipeline capacity net of tax

$ 123

Proceeds from settlement

$ 47

Proceeds from settlement net of taxes

$ 28

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

Significant Items Affecting Quarterly Results [Line Items]

Gain on acquisition of remaining voting rights

$ 617

617

Gain on acquisition of remaining voting rights, net of tax

432

$ 432

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

350

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

Significant Items Affecting Quarterly Results [Line Items]

Other than temporary impairment in investment, net of tax

$ 71

131

$ 71

$ 131

111

$ 111

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

$ 47

$ 90

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

Significant Items Affecting Quarterly Results [Line Items]

Write-off of wildfire regulatory asset net of tax

351

$ 208

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

SUBSEQUENT EVENTS (Details)
$ / shares in Units, $ in Millions

1 Months Ended

12 Months Ended

Jan. 12, 2018

USD ($)

Jan. 09, 2018

USD ($)

$ / shares

Rate

Jan. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

^[1]

Dec. 31, 2015

USD ($)

^[1]

Dec. 29, 2017

$ / shares

Sempra Energy [Member] | Common Stock [Member]

$ 47

$ 51

$ 52

Share price (in dollars per share) | $ / shares

$ 106.92

Subsequent Event [Member] | Public Offering [Member]

Subsequent Event [Member] | Over-Allotment Option [Member]

23,364,486

3,504,672

Subsequent Event [Member] | Common Stock [Member]

$ 368

26,869,158

Subsequent Event [Member] | Common Stock [Member] | Public Offering [Member]

$ 2,460

Price of shares issued (in dollars per share) | $ / shares

23,364,486

$ 107.00

Price of shares issued net of underwriting discount (in dollars per share) | $ / shares

$ 105.074

Subsequent Event [Member] | Common Stock [Member] | Over-Allotment Option [Member]

3,504,672

Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member]

$ 368

17,250,000

Conversion price per share (in dollars per share) | $ / shares

6.00%

$ 100.00

Conversion price per share net of underwriting discount (in dollars per share) | $ / shares

98.20

Liquidation preference (in dollars per share) | $ / shares

100

Value of shares issued

$ 1,690

Threshold appreciation price (in dollars per share) | $ / shares

$ 131.075

Share dividends issued, percentage of weighted average share price

97.00%

Number of shares issuable | shares

16,100,000

Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Minimum [Member]

Threshold appreciation price (in dollars per share) | $ / shares

$ 107.00

Shares issuable for each instrument | Rate

76.29%

Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Maximum [Member]

Threshold appreciation price (in dollars per share) | $ / shares

$ 131.075

Shares issuable for each instrument | Rate

93.45%

Subsequent Event [Member] | Sempra Energy [Member] | Convertible Preferred Stock [Member] | Over-Allotment Option [Member]

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

2,250,000

Proceeds from issuance of debt

$ 4,900

Redemption price percentage

101.00%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2019 [Member]

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2019 [Member] | LIBOR [Member]

$ 500

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2021 [Member]

0.25%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | Floating Rate Notes Due 2021 [Member] | LIBOR [Member]

$ 700

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 2.400% Senior Notes Due 2020 [Member]

0.50%

2.40%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 2.900% Senior Notes Due 2023 [Member]

$ 500

2.90%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 3.400% Senior Notes Due 2028 [Member]

$ 500

3.40%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 3.800% Senior Notes Due 2038 [Member]

$ 1,000

3.80%

Energy Future Holdings Corp. [Member] | Subsequent Event [Member] | 4.000% Senior Notes Due 2048 [Member]

$ 1,000

4.00%

Condensed Statement of Income Captions [Line Items]

$ 800

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

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

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - STATEMENT OF COMPREHENSIVE INCOME (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 351

$ 1,519

^[1]

$ 1,448

^[1]

Condensed Statement of Income Captions [Line Items]

142

(334)

Pretax amount [Member]

1,533

1,760

1,691

107

(260)

(6)

(80)

(13)

(3)

Total comprehensive income, after preferred dividends of subsidiaries

129

(343)

1,661

1,782

1,347

Income tax benefit [Member]

Condensed Statement of Income Captions [Line Items]

(1,276)

(389)

(341)

(8)

Total comprehensive income, after preferred dividends of subsidiaries

(7)

(1,283)

(374)

(307)

Net-of-tax amount [Member]

Condensed Statement of Income Captions [Line Items]

257

1,371

1,350

107

(260)

(47)

(9)

(2)

Total comprehensive income, after preferred dividends of subsidiaries

122

(309)

378

1,408

1,040

Parent Company [Member] | Pretax amount [Member]

Condensed Statement of Income Captions [Line Items]

223

1,189

1,199

107

(260)

(6)

(80)

(13)

(3)

Total comprehensive income, after preferred dividends of subsidiaries

129

(343)

352

1,212

856

Parent Company [Member] | Income tax benefit [Member]

Condensed Statement of Income Captions [Line Items]

181

150

(8)

Total comprehensive income, after preferred dividends of subsidiaries

(7)

196

184

Parent Company [Member] | Net-of-tax amount [Member]

Condensed Statement of Income Captions [Line Items]

256

1,370

1,349

107

(260)

(47)

(9)

(2)

Total comprehensive income, after preferred dividends of subsidiaries

122

(309)

$ 378

$ 1,408

$ 1,040

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

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - BALANCE SHEETS (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 288

$ 349

^[1]

^[1]

110

^[1]

136

142

^[1]

Investments in subsidiaries

3,341

3,110

^[1]

2,527

2,097

^[1]

598

201

^[1]

170

234

^[1]

Other assets

792

520

^[1]

Liabilities and shareholders’ equity:

50,454

47,786

^[1]

$ 41,150

1,427

913

^[1]

^[1]

545

517

^[1]

6,635

5,927

^[1]

16,445

14,429

^[1]

^[1]

Shareholders’ equity

12,670

12,951

^[1]

50,454

47,786

^[1]

Parent Company [Member]

104

$ 4

$ 3

272

Investments in subsidiaries

465

17,924

17,329

1,802

2,570

Other assets

656

592

Liabilities and shareholders’ equity:

20,849

20,578

500

600

280

359

Income taxes payable

153

396

374

1,176

1,486

6,198

5,100

Other long-term liabilities

300

517

505

524

Shareholders’ equity

12,670

12,951

Condensed Cash Flow Statements, Captions [Line Items]

$ 20,849

$ 20,578

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

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - CASH FLOWS (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 3,625

$ 2,311

^[1]

$ 2,898

^[1]

(3,949)

(4,214)

^[1]

(3,156)

^[1]

Purchase of trust assets

(2)

^[1]

Common stock dividends paid

(4,700)

(4,835)

^[1]

(2,868)

^[1]

(755)

(686)

^[1]

(628)

^[1]

^[1]

Issuances of long-term debt

(15)

(56)

^[1]

(74)

^[1]

4,509

2,951

^[1]

2,992

^[1]

Payments on long-term debt

(2,800)

(2,057)

^[1]

(1,854)

^[1]

Net cash provided by (used in) financing activities

(43)

(21)

^[1]

(20)

^[1]

1,007

2,502

^[1]

(176)

^[1]

^[2]

349

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES

288

349

^[2]

Financing of build-to-suit property

^[1]

^[1]

Common dividends issued in stock

^[1]

Dividends declared but not paid

214

196

^[1]

180

^[1]

Parent Company [Member]

Condensed Cash Flow Statements, Captions [Line Items]

(3)

Decrease (increase) in loans to affiliate, net

(11)

(5)

^[1]

(43)

^[1]

Purchase of trust assets

(5)

457

^[1]

(457)

^[1]

Expenditures for Merger-related transaction costs

(12)

Common stock dividends paid

(23)

452

(505)

(755)

(686)

(628)

Issuances of long-term debt

(15)

(56)

(74)

1,595

499

1,248

Payments on long-term debt

(600)

(750)

Increase (decrease) in loans from affiliates, net

(239)

504

(230)

Net cash provided by (used in) financing activities

(7)

(3)

(9)

(441)

411

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES

104

Financing of build-to-suit property

Common dividends issued in stock

Dividends declared but not paid

$ 207

$ 189

$ 174

[1]	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.
[2]	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

SCHEDULE I, CONDENSED FINANCIAL INFORMATION OF PARENT - FOOTNOTES (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Basis of Presentation

Rabbi trust investment gains

$ 9

$ 7

$ 6

Gain (loss) on settlement

(7)

(21)

^[1]

3,625

2,311

^[1]

2,898

^[1]

(4,700)

(4,835)

^[1]

(2,868)

^[1]

254

132

126

Long-term Debt, Fiscal Year Maturity [Abstract]

(1,427)

(913)

^[2]

Total long-term debt

16,445

14,429

^[2]

1,412

1,419

1,033

1,346

647

11,282

Parent Company [Member]

Basis of Presentation

Rabbi trust investment gains

(3)

(23)

452

(505)

(87)

(81)

(66)

107

(2)

Market value adjustments for interest rate swaps, net

(1)

(3)

Build-to-suit lease

138

137

6,737

5,734

(500)

(600)

(13)

(10)

Long-term Debt, Fiscal Year Maturity [Abstract]

(26)

(24)

Total long-term debt

6,198

5,100

500

1,000

900

850

500

2,850

Parent Company [Member] | 2.3% Notes April 1, 2017 [Member]

$ 0

600

Parent Company [Member] | 6.15% Notes June 15, 2018 [Member]

2.30%

$ 500

500

Parent Company [Member] | 9.8% Notes February 15, 2019 [Member]

6.15%

$ 500

500

Parent Company [Member] | 1.625% Notes October 7, 2019 [Member]

9.80%

$ 500

500

Parent Company [Member] | 2.4% Notes March 15, 2020 [Member]

1.625%

$ 500

500

Parent Company [Member] | 2.85% Notes November 15, 2020 [Member]

2.40%

$ 400

400

Parent Company [Member] | Notes at variable rates (2.038% at December 31, 2017) March 15, 2021 [Member]

2.85%

Effective rate percentage

$ 850

2.038%

Parent Company [Member] | 2.875% Notes October 1, 2022 [Member]

$ 500

500

Parent Company [Member] | 4.05% Notes December 1, 2023 [Member]

2.875%

$ 500

500

Parent Company [Member] | 3.55% Notes June 15, 2024 [Member]

4.05%

$ 500

500

Parent Company [Member] | 3.75% Notes November 15, 2025 [Member]

3.55%

$ 350

350

Parent Company [Member] | 3.25% Notes June 15, 2027 [Member]

3.75%

$ 750

Parent Company [Member] | 6% Notes October 15, 2039 [Member]

3.25%

$ 750

750

Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]

6.00%

Dividends received from subsidiaries

(3)

Parent Company [Member] | Foreign exchange instruments [Member]

452

(505)

Basis of Presentation

Gain (loss) on settlement

$ 50

(28)

As previously reported [Member] | Accounting Standards Update 2017-07 [Member]

As previously reported [Member] | Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]

254

132

Dividends received from subsidiaries

(178)

(255)

175

350

As previously reported [Member] | Parent Company [Member] | Accounting Standards Update 2017-07 [Member]

627

(155)

(87)

(81)

Recast [Member] | Accounting Standards Update 2017-07 [Member]

107

(2)

Recast [Member] | Parent Company [Member] | Accounting Standards Update 2017-07 [Member]

233

138

(80)

(76)

Effect of adoption [Member] | Parent Company [Member] | Accounting Standards Update 2016-15 [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]

$ 100

(7)

Dividends received from subsidiaries

175

350

(175)

(350)