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Sempra Energy/SDG&E/SoCalGas September 30, 2014 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended

September 30, 2014

[ ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission File No.

Exact Name of Registrants as Specified in their Charters, Address and Telephone Number

States of Incorporation

I.R.S. Employer

Identification Nos.

Former name, former address and former fiscal year, if changed since last report

1-14201

SEMPRA ENERGY

California

33-0732627

No change

101 Ash Street

San Diego, California 92101

(619)696-2000

1-03779

SAN DIEGO GAS & ELECTRIC COMPANY

California

95-1184800

No change

8326 Century Park Court

San Diego, California 92123

(619)696-2000

1-01402

SOUTHERN CALIFORNIA GAS COMPANY

California

95-1240705

No change

555 West Fifth Street

Los Angeles, California 90013

(213)244-1200

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Sempra Energy

Yes

San Diego Gas & Electric Company

Yes

Southern California Gas Company

Yes

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large

accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Sempra Energy

[ X ]

[ ]

San Diego Gas & Electric Company

[ ]

[ X ]

[ ]

Southern California Gas Company

[ ]

[ X ]

[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Sempra Energy

Yes

San Diego Gas & Electric Company

Yes

Southern California Gas Company

Yes

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

Common stock outstanding on October 31, 2014:

Sempra Energy

246,218,250 shares

San Diego Gas & Electric Company

Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy

Southern California Gas Company

Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy

SEMPRA ENERGY FORM 10-Q SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q TABLE OF CONTENTS
		Page
Information Regarding Forward-Looking Statements		4

PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	84
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	125
Item 4.	Controls and Procedures	126

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	127
Item 1A.	Risk Factors	127
Item 6.	Exhibits	127

Signatures		130

This combined Form 10-Q is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

You should read this report in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Part I – Item 1 sections are provided for each reporting company, except for the Notes to Condensed Consolidated Financial Statements. The Notes to Condensed Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Part I – Item 1 are combined for the reporting companies.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.

In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “forecasts,” “contemplates,” “intends,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “potential,” “target,” “pursue,” “goals,” “outlook,” “maintain,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, opportunities, projections, initiatives, objectives or intentions, we are making forward-looking statements.

Factors, among others, that could cause our actual results and future actions to differ materially from those described in forward-looking statements include

§	local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments;

actions and the timing of actions, including issuances of permits to construct and licenses for operation, by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, Atomic Safety and Licensing Board, California Energy Commission, U.S. Environmental Protection Agency, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;

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

§	the timing and success of business development efforts and construction, maintenance and capital projects, including risks in obtaining permits, licenses, certificates and other authorizations on a timely basis and risks in obtaining adequate and competitive financing for such projects;

§	delays in the timing of costs incurred and the timing of the regulatory agency authorization to recover such costs in rates from customers;

§	inflation, interest and exchange rates;

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

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

§	the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures and the decommissioning of San Onofre Nuclear Generating Station (SONGS);

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

§	cybersecurity threats to the energy grid and the confidentiality of our proprietary information and the personal information of our customers, terrorist attacks that threaten system operations and critical infrastructure, and wars;

risks inherent with nuclear power facilities and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in, or operating costs of, the nuclear facility due to an extended outage and facility closure, and increased regulatory oversight;

§	risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

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

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

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

§	the impact on reliability of San Diego Gas & Electric Company’s (SDG&E) electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources;

§	the impact on competitive customer rates of the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system;

§	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements due to insufficient market interest, unattractive pricing or other factors;

§	the resolution of litigation; and

§	other uncertainties, all of which are difficult to predict and many of which are beyond our control.

We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described in this report and in our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
	(unaudited)
REVENUES
Utilities	$	2,463	$	2,223	$	7,318	$	6,889
Energy-related businesses		352		328		970		963
Total revenues		2,815		2,551		8,288		7,852
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas		(293)		(261)		(1,308)		(1,182)
Cost of electric fuel and purchased power		(680)		(537)		(1,761)		(1,461)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power		(163)		(120)		(427)		(325)
Other cost of sales		(42)		(47)		(122)		(144)
Operation and maintenance		(726)		(698)		(2,131)		(2,162)
Depreciation and amortization		(292)		(286)		(866)		(828)
Franchise fees and other taxes		(104)		(96)		(301)		(283)
Plant closure adjustment (loss)		―		―		13		(200)
Gain on sale of equity interests and assets		19		39		48		113
Equity earnings, before income tax		22		3		62		21
Other income, net		29		16		118		79
Interest income		6		5		15		15
Interest expense		(144)		(137)		(418)		(413)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		447		432		1,210		1,082
Income tax expense		(71)		(117)		(291)		(327)
Equity earnings, net of income tax		7		8		22		13
Net income		383		323		941		768
Earnings attributable to noncontrolling interests		(35)		(22)		(76)		(41)
Call premium on preferred stock of subsidiary		―		(3)		―		(3)
Preferred dividends of subsidiaries		―		(2)		(1)		(5)
Earnings	$	348	$	296	$	864	$	719

Basic earnings per common share	$	1.41	$	1.21	$	3.52	$	2.95

Weighted-average number of shares outstanding, basic (thousands)		246,137		244,140		245,703		243,682

Diluted earnings per common share	$	1.39	$	1.19	$	3.45	$	2.89

Weighted-average number of shares outstanding, diluted (thousands)		250,771		249,259		250,278		248,723

Dividends declared per share of common stock	$	0.66	$	0.63	$	1.98	$	1.89
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	Three months ended September 30, 2014 and 2013
	(unaudited)
	Sempra Energy Shareholders' Equity
	Pretax		Income Tax		Net-of-Tax		Noncontrolling
	Amount		(Expense) Benefit		Amount		Interests (After-Tax)		Total
2014:
Net income	$	419	$	(71)	$	348	$	35	$	383
Other comprehensive income (loss):
Foreign currency translation adjustments		(100)		―		(100)		(11)		(111)
Pension and other postretirement benefits		8		(3)		5		―		5
Financial instruments		(4)		1		(3)		3		―
Total other comprehensive loss		(96)		(2)		(98)		(8)		(106)
Comprehensive income	$	323	$	(73)	$	250	$	27	$	277
2013:
Net income	$	418	$	(117)	$	301	$	22	$	323
Other comprehensive income (loss):
Foreign currency translation adjustments		5		―		5		―		5
Pension and other postretirement benefits		5		(2)		3		―		3
Financial instruments		(5)		1		(4)		(2)		(6)
Total other comprehensive income (loss)		5		(1)		4		(2)		2
Comprehensive income		423		(118)		305		20		325
Preferred dividends of subsidiaries		(2)		―		(2)		―		(2)
Comprehensive income, after preferred
dividends of subsidiaries	$	421	$	(118)	$	303	$	20	$	323
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (CONTINUED)
(Dollars in millions)
	Nine months ended September 30, 2014 and 2013
	(unaudited)
	Sempra Energy Shareholders' Equity
	Pretax		Income Tax		Net-of-Tax		Noncontrolling
	Amount		(Expense) Benefit		Amount		Interests (After-Tax)		Total
2014:
Net income	$	1,156	$	(291)	$	865	$	76	$	941
Other comprehensive income (loss):
Foreign currency translation adjustments		(141)		―		(141)		(12)		(153)
Pension and other postretirement benefits		21		(8)		13		―		13
Financial instruments		(24)		9		(15)		2		(13)
Total other comprehensive loss		(144)		1		(143)		(10)		(153)
Comprehensive income		1,012		(290)		722		66		788
Preferred dividends of subsidiary		(1)		―		(1)		―		(1)
Comprehensive income, after preferred
dividends of subsidiary	$	1,011	$	(290)	$	721	$	66	$	787
2013:
Net income	$	1,054	$	(327)	$	727	$	41	$	768
Other comprehensive income (loss):
Foreign currency translation adjustments		149		―		149		(24)		125
Pension and other postretirement benefits		12		(5)		7		―		7
Financial instruments		8		(3)		5		16		21
Total other comprehensive income (loss)		169		(8)		161		(8)		153
Comprehensive income		1,223		(335)		888		33		921
Preferred dividends of subsidiaries		(5)		―		(5)		―		(5)
Comprehensive income, after preferred
dividends of subsidiaries	$	1,218	$	(335)	$	883	$	33	$	916
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	667	$	904
Restricted cash			22		24
Trade accounts receivable, net			1,055		1,308
Other accounts and notes receivable, net			209		214
Due from unconsolidated affiliates			3		4
Income taxes receivable			91		85
Deferred income taxes			452		301
Inventories			472		287
Regulatory balancing accounts – undercollected			821		556
Other regulatory assets			59		38
Fixed-price contracts and other derivatives			83		106
Asset held for sale, power plant			293		―
Other			187		170
Total current assets			4,414		3,997

Investments and other assets:
Restricted cash			10		25
Due from unconsolidated affiliates			133		14
Regulatory assets arising from pension and other postretirement
benefit obligations			435		435
Other regulatory assets			2,048		2,113
Nuclear decommissioning trusts			1,087		1,034
Investments			1,797		1,575
Goodwill			951		1,024
Other intangible assets			418		426
Sundry			1,280		1,141
Total investments and other assets			8,159		7,787

Property, plant and equipment:
Property, plant and equipment			35,829		34,407
Less accumulated depreciation and amortization			(9,420)		(8,947)
Property, plant and equipment, net ($417 and $438 at September 30, 2014 and December 31, 2013, respectively, related to VIE)			26,409		25,460
Total assets		$	38,982	$	37,244
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	1,309	$	545
Accounts payable – trade			1,153		1,088
Accounts payable – other			129		127
Dividends and interest payable			327		271
Accrued compensation and benefits			345		376
Regulatory balancing accounts – overcollected			―		91
Current portion of long-term debt			188		1,147
Fixed-price contracts and other derivatives			49		55
Customer deposits			149		154
Other			643		515
Total current liabilities			4,292		4,369
Long-term debt ($317 and $325 at September 30, 2014 and December 31, 2013, respectively, related to VIE)			12,437		11,253

Deferred credits and other liabilities:
Customer advances for construction			144		155
Pension and other postretirement benefit obligations, net of plan assets			659		667
Deferred income taxes			3,113		2,804
Deferred investment tax credits			38		42
Regulatory liabilities arising from removal obligations			2,725		2,623
Asset retirement obligations			2,043		2,084
Fixed-price contracts and other derivatives			220		228
Deferred credits and other			1,154		1,169
Total deferred credits and other liabilities			10,096		9,772

Commitments and contingencies (Note 11)

Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 246 million and 244 million shares
outstanding at September 30, 2014 and December 31, 2013, respectively; no par value)			2,499		2,409
Retained earnings			9,205		8,827
Accumulated other comprehensive income (loss)			(371)		(228)
Total Sempra Energy shareholders’ equity			11,333		11,008
Preferred stock of subsidiary			20		20
Other noncontrolling interests			804		822
Total equity			12,157		11,850
Total liabilities and equity		$	38,982	$	37,244
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2014		2013
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	941	$	768
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		866		828
Deferred income taxes and investment tax credits		131		327
Gain on sale of equity interests and assets		(48)		(113)
Plant closure (adjustment) loss		(13)		200
Equity earnings		(84)		(34)
Fixed-price contracts and other derivatives		(19)		(25)
Other		32		23
Net change in other working capital components		(215)		(454)
Changes in other assets		28		(203)
Changes in other liabilities		42		13
Net cash provided by operating activities		1,661		1,330

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(2,320)		(1,785)
Expenditures for investments and acquisition of businesses, net of cash acquired		(192)		(21)
Proceeds from sale of equity interests and assets, net of cash sold		92		566
Proceeds from U.S. Treasury grants		―		238
Distributions from investments		15		141
Purchases of nuclear decommissioning and other trust assets		(505)		(514)
Proceeds from sales by nuclear decommissioning and other trusts		498		510
Decrease in restricted cash		156		285
Increase in restricted cash		(139)		(311)
Advances to unconsolidated affiliates		(81)		―
Other		10		(10)
Net cash used in investing activities		(2,466)		(901)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(450)		(452)
Preferred dividends paid by subsidiaries		(1)		(5)
Issuances of common stock		43		57
Repurchases of common stock		(38)		(45)
Issuances of debt (maturities greater than 90 days)		3,063		1,404
Payments on debt (maturities greater than 90 days)		(1,845)		(1,444)
Proceeds from sale of noncontrolling interests, net of $25 in offering costs		―		574
(Decrease) increase in short-term debt, net		(111)		81
Net distributions to noncontrolling interests		(84)		(28)
Other		(5)		15
Net cash provided by financing activities		572		157

Effect of exchange rate changes on cash and cash equivalents		(4)		―

(Decrease) increase in cash and cash equivalents		(237)		586
Cash and cash equivalents, January 1		904		475
Cash and cash equivalents, September 30	$	667	$	1,061
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Nine months ended September 30,
	2014		2013
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	359	$	359
Income tax payments, net of refunds		154		106

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of businesses:
Assets acquired	$	―	$	13
Cash paid, net of cash acquired		―		(11)
Liabilities assumed	$	―	$	2

Nuclear facility plant reclassified to regulatory asset, net of depreciation and amortization	$	―	$	512
Accrued capital expenditures		385		285
Increase in capital lease obligations for investment in property, plant and equipment		60		―
Capital expenditures recoverable by U.S. Treasury grants receivable		―		3
Sequestration of U.S. Treasury grants receivable		―		(23)
Dividends declared but not paid		166		158
Financing of build-to-suit property		49		―
Call premium on preferred stock of subsidiary		―		3
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
	(unaudited)
Operating revenues
Electric	$	1,133	$	970	$	2,892	$	2,685
Natural gas		100		93		391		381
Total operating revenues		1,233		1,063		3,283		3,066
Operating expenses
Cost of electric fuel and purchased power		441		315		1,036		776
Cost of natural gas		39		36		165		157
Operation and maintenance		276		266		784		852
Depreciation and amortization		134		126		395		367
Franchise fees and other taxes		67		57		177		158
Plant closure (adjustment) loss		―		―		(13)		200
Total operating expenses		957		800		2,544		2,510
Operating income		276		263		739		556
Other income, net		9		10		29		30
Interest income		―		―		―		1
Interest expense		(51)		(50)		(152)		(147)
Income before income taxes		234		223		616		440
Income tax expense		(65)		(84)		(217)		(147)
Net income		169		139		399		293
Earnings attributable to noncontrolling interest		(12)		(5)		(20)		(1)
Earnings		157		134		379		292
Call premium on preferred stock		―		(3)		―		(3)
Preferred dividend requirements		―		(2)		―		(4)
Earnings attributable to common shares	$	157	$	129	$	379	$	285
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	SDG&E Shareholder's Equity
	Pretax		Income Tax		Net-of-Tax		Noncontrolling
	Amount		(Expense) Benefit		Amount		Interest (After-Tax)		Total
	Three months ended September 30, 2014 and 2013
	(unaudited)
2014:
Net income	$	222	$	(65)	$	157	$	12	$	169
Other comprehensive income:
Pension and other postretirement benefits		1		―		1		―		1
Financial instruments		―		―		―		4		4
Total other comprehensive income		1		―		1		4		5
Comprehensive income	$	223	$	(65)	$	158	$	16	$	174
2013:
Net income	$	218	$	(84)	$	134	$	5	$	139
Other comprehensive income (loss):
Pension and other postretirement benefits		2		(1)		1		―		1
Financial instruments		―		―		―		(1)		(1)
Total other comprehensive income (loss)		2		(1)		1		(1)		―
Comprehensive income	$	220	$	(85)	$	135	$	4	$	139

	Nine months ended September 30, 2014 and 2013
	(unaudited)
2014:
Net income	$	596	$	(217)	$	379	$	20	$	399
Other comprehensive income:
Pension and other postretirement benefits		3		(1)		2		―		2
Financial instruments		―		―		―		3		3
Total other comprehensive income		3		(1)		2		3		5
Comprehensive income	$	599	$	(218)	$	381	$	23	$	404
2013:
Net income	$	439	$	(147)	$	292	$	1	$	293
Other comprehensive income:
Pension and other postretirement benefits		3		(1)		2		―		2
Financial instruments		―		―		―		14		14
Total other comprehensive income		3		(1)		2		14		16
Comprehensive income	$	442	$	(148)	$	294	$	15	$	309
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	33	$	27
Restricted cash			8		6
Accounts receivable – trade, net			389		266
Accounts receivable – other, net			27		28
Due from unconsolidated affiliates			1		1
Income taxes receivable			―		32
Deferred income taxes			―		103
Inventories			70		86
Regulatory balancing accounts, net			772		556
Other regulatory assets			52		29
Fixed-price contracts and other derivatives			38		61
Other			92		75
Total current assets			1,482		1,270

Other assets:
Restricted cash			10		25
Deferred taxes recoverable in rates			787		788
Regulatory assets arising from fixed-price contracts and other derivatives			39		63
Regulatory assets arising from pension and other postretirement
benefit obligations			92		106
Other regulatory assets			815		991
Nuclear decommissioning trusts			1,087		1,034
Sundry			340		254
Total other assets			3,170		3,261

Property, plant and equipment:
Property, plant and equipment			15,086		14,346
Less accumulated depreciation and amortization			(3,763)		(3,500)
Property, plant and equipment, net ($417 and $438 at September 30, 2014 and December 31, 2013, respectively, related to VIE)			11,323		10,846
Total assets		$	15,975	$	15,377
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	―	$	59
Accounts payable			402		420
Due to unconsolidated affiliates			36		39
Income taxes payable			8		―
Deferred income taxes			41		―
Dividends and interest payable			51		39
Accrued compensation and benefits			111		113
Current portion of long-term debt			115		29
Fixed-price contracts and other derivatives			38		38
Customer deposits			69		71
Other			398		271
Total current liabilities			1,269		1,079
Long-term debt ($317 and $325 at September 30, 2014 and December 31, 2013, respectively, related to VIE)			4,573		4,525

Deferred credits and other liabilities:
Customer advances for construction			40		34
Pension and other postretirement benefit obligations, net of plan assets			120		132
Deferred income taxes			2,054		2,021
Deferred investment tax credits			22		24
Regulatory liabilities arising from removal obligations			1,535		1,403
Asset retirement obligations			759		861
Fixed-price contracts and other derivatives			155		175
Deferred credits and other			362		404
Total deferred credits and other liabilities			5,047		5,054

Commitments and contingencies (Note 11)

Equity:
Common stock (255 million shares authorized; 117 million shares outstanding;
no par value)			1,338		1,338
Retained earnings			3,678		3,299
Accumulated other comprehensive income (loss)			(7)		(9)
Total SDG&E shareholder's equity			5,009		4,628
Noncontrolling interest			77		91
Total equity			5,086		4,719
Total liabilities and equity		$	15,975	$	15,377
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2014		2013
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	399	$	293
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		395		367
Deferred income taxes and investment tax credits		193		100
Plant closure (adjustment) loss		(13)		200
Fixed-price contracts and other derivatives		(5)		(7)
Other		(30)		(9)
Net change in other working capital components		(252)		(284)
Changes in other assets		106		(164)
Changes in other liabilities		28		13
Net cash provided by operating activities		821		509

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(790)		(679)
Purchases of nuclear decommissioning trust assets		(501)		(511)
Proceeds from sales by nuclear decommissioning trusts		498		507
Decrease in restricted cash		109		54
Increase in restricted cash		(96)		(52)
Other		(16)		3
Net cash used in investing activities		(796)		(678)

CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid		―		(4)
Issuances of long-term debt		100		450
Payments on long-term debt		(22)		(183)
Decrease in short-term debt, net		(59)		―
Capital distribution made by Otay Mesa VIE		(38)		(12)
Other		―		(2)
Net cash (used in) provided by financing activities		(19)		249

Increase in cash and cash equivalents		6		80
Cash and cash equivalents, January 1		27		87
Cash and cash equivalents, September 30	$	33	$	167

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	136	$	127
Income tax (refunds) payments, net		(4)		33

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Nuclear facility plant reclassified to regulatory asset, net of depreciation and amortization	$	―	$	512
Accrued capital expenditures		118		108
Increase in capital lease obligations for investment in property, plant and equipment		60		―
Call premium on preferred stock		―		3
Dividends declared but not paid		―		1
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
	(unaudited)

Operating revenues	$	855	$	807	$	2,857	$	2,694
Operating expenses
Cost of natural gas		237		209		1,066		966
Operation and maintenance		326		314		968		936
Depreciation and amortization		109		100		321		280
Franchise fees and other taxes		30		29		98		95
Total operating expenses		702		652		2,453		2,277
Operating income		153		155		404		417
Other income, net		6		2		13		9
Interest expense		(17)		(17)		(50)		(52)
Income before income taxes		142		140		367		374
Income tax expense		(44)		(38)		(110)		(107)
Net income		98		102		257		267
Preferred dividend requirements		―		―		(1)		(1)
Earnings attributable to common shares	$	98	$	102	$	256	$	266
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	Pretax		Income Tax		Net-of-Tax
	Amount		(Expense) Benefit		Amount
	Three months ended September 30, 2014 and 2013
	(unaudited)
2014:
Net income	$	142	$	(44)	$	98
Other comprehensive income:
Pension and other postretirement benefits		4		(2)		2
Total other comprehensive income		4		(2)		2
Comprehensive income	$	146	$	(46)	$	100
2013:
Net income/Comprehensive income	$	140	$	(38)	$	102

	Nine months ended September 30, 2014 and 2013
	(unaudited)
2014:
Net income	$	367	$	(110)	$	257
Other comprehensive income:
Pension and other postretirement benefits		4		(2)		2
Total other comprehensive income		4		(2)		2
Comprehensive income	$	371	$	(112)	$	259
2013:
Net income	$	374	$	(107)	$	267
Other comprehensive income:
Financial instruments		1		―		1
Total other comprehensive income		1		―		1
Comprehensive income	$	375	$	(107)	$	268
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	25	$	27
Accounts receivable – trade, net			324		595
Accounts receivable – other, net			55		97
Due from unconsolidated affiliates			274		21
Income taxes receivable			29		25
Inventories			221		69
Regulatory balancing accounts, net			49		―
Other regulatory assets			6		5
Other			35		34
Total current assets			1,018		873

Other assets:
Regulatory assets arising from pension obligations			341		326
Other regulatory assets			399		262
Other postretirement benefit plan assets, net of plan liabilities			93		95
Sundry			137		124
Total other assets			970		807

Property, plant and equipment:
Property, plant and equipment			12,542		11,831
Less accumulated depreciation and amortization			(4,576)		(4,364)
Property, plant and equipment, net			7,966		7,467
Total assets		$	9,954	$	9,147
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		September 30,		December 31,
		2014		2013(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt		$	―	$	42
Accounts payable – trade			336		346
Accounts payable – other			83		79
Due to unconsolidated affiliate			―		16
Deferred income taxes			164		45
Accrued compensation and benefits			131		141
Regulatory balancing accounts, net			―		91
Current portion of long-term debt			―		252
Customer deposits			74		75
Other			125		125
Total current liabilities			913		1,212
Long-term debt			1,906		1,159
Deferred credits and other liabilities:
Customer advances for construction			102		108
Pension obligation, net of plan assets			357		339
Regulatory liabilities arising from other postretirement benefit assets			93		95
Deferred income taxes			1,050		993
Deferred investment tax credits			16		18
Regulatory liabilities arising from removal obligations			1,173		1,205
Asset retirement obligations			1,245		1,182
Deferred credits and other			292		287
Total deferred credits and other liabilities			4,328		4,227

Commitments and contingencies (Note 11)

Shareholders' equity:
Preferred stock			22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)			866		866
Retained earnings			1,935		1,679
Accumulated other comprehensive income (loss)			(16)		(18)
Total shareholders' equity			2,807		2,549
Total liabilities and shareholders' equity		$	9,954	$	9,147
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2014		2013
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	257	$	267
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		321		280
Deferred income taxes and investment tax credits		94		72
Other		(2)		(6)
Net change in other working capital components		(19)		(56)
Changes in other assets		(70)		(65)
Changes in other liabilities		15		(5)
Net cash provided by operating activities		596		487

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(764)		(521)
(Increase) decrease in loans to affiliates, net		(281)		17
Net cash used in investing activities		(1,045)		(504)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		―		(50)
Preferred dividends paid		(1)		(1)
Issuances of long-term debt		747		―
Repayment of long-term debt		(250)		―
Decrease in short-term debt, net		(42)		―
Other		(7)		―
Net cash provided by (used in) financing activities		447		(51)

Decrease in cash and cash equivalents		(2)		(68)
Cash and cash equivalents, January 1		27		83
Cash and cash equivalents, September 30	$	25	$	15

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	43	$	44
Income tax payments, net of refunds		19		66

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	137	$	97
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION

Sempra Energy

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

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

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

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

We provide descriptions of each of our segments in Note 12.

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

Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova further in Note 5 under “Shareholders’ Equity and Noncontrolling Interests – Sale of Noncontrolling Interests.”

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 4 and 13 herein and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013 (the Annual Report), which includes the combined reports for Sempra Energy, SDG&E and SoCalGas.

SDG&E

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

SoCalGas

SoCalGas’ Condensed Consolidated Financial Statements include its accounts and the de minimus accounts of inactive subsidiaries. SoCalGas’ common stock is wholly owned by Pacific Enterprises (PE), which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

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

We have prepared the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after September 30, 2014 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.

All December 31, 2013 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2013 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the Securities and Exchange Commission.

You should read the information in this Quarterly Report in conjunction with the Annual Report.

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

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

NOTE 2. NEW ACCOUNTING STANDARDS

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

SEMPRA ENERGY, SDG&E AND SOCALGAS

Accounting Standards Update (ASU) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” (ASU 2013-11): ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. If a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes, an entity is required to present the unrecognized tax benefit in the financial statements as a liability instead of combined with deferred tax assets.

We adopted ASU 2013-11 on January 1, 2014 as required, and it did not significantly affect our financial condition, results of operations or cash flows.

ASU 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09): ASU 2014-09 provides accounting guidance for revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach.

We will adopt ASU 2014-09 on January 1, 2017 as required, and we are currently evaluating the effect of adopting it on our financial condition, results of operations and cash flows.

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

During the nine months ended September 30, 2014 and 2013, Sempra Energy completed the sale of equity interests in various subsidiaries that were previously wholly owned. The following table summarizes the deconsolidation of those subsidiaries, and we discuss each transaction below:

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

		Mesquite Solar 1		Copper Mountain Solar 2		Sempra Energy Consolidated
		At September 19		At July 11
2013:
Proceeds from sale, net of transaction costs(1)		$	100	$	68	$	168
Property, plant and equipment, net			(461)		(266)		(727)
Other assets			(72)		(30)		(102)
Long-term debt, including current portion			297		146		443
Other liabilities			31		19		50
Gain on sale of equity interests			(36)		(4)		(40)
Equity method investments upon deconsolidation		$	(141)	$	(67)	$	(208)
(1)	Transaction costs were $3 million at both Mesquite Solar 1 and Copper Mountain Solar 2.

SEMPRA MEXICO

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

SEMPRA RENEWABLES

In July 2013, Sempra Renewables formed a joint venture with Consolidated Edison Development (ConEdison Development), a nonrelated party, by selling a 50-percent interest in its 150-MW Copper Mountain Solar 2 solar power facility for $71 million in cash. Sempra Renewables recognized a pretax gain on the sale of $4 million ($2 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2013.

In September 2013, Sempra Renewables acquired the rights to develop the 75-MW Broken Bow 2 Wind project in Custer County, Nebraska. The project achieved commercial operation in October 2014. Sempra Renewables does not have an ownership interest in the Broken Bow 1 Wind Farm.

In September 2013, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in its 150-MW Mesquite Solar 1 solar power facility for $103 million in cash. Sempra Renewables recognized a pretax gain on the sale of $36 million ($22 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2013.

In March 2014, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in its 250-MW Copper Mountain Solar 3 solar power facility for $66 million in cash, net of $2 million cash sold. Sempra Renewables recognized a pretax gain on the sale of $27 million ($16 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2014.

In May 2014, Sempra Renewables invested $109 million, subject to a commitment for a purchase price adjustment to be based on financial position at closing, to become a 50-percent partner with ConEdison Development in four solar projects in California. We discuss our investment in the California solar partnership further in Note 4.

Our remaining 50-percent interests in Copper Mountain Solar 2, Mesquite Solar 1 and Copper Mountain Solar 3 are accounted for under the equity method. Based on the nature of the underlying assets, these solar investments are considered in-substance real estate. Therefore, in accordance with applicable U.S. GAAP, for each of these solar investment transactions, the equity method investments were measured at their historical cost and no portion of the gains was attributable to a remeasurement of the retained investments to fair value.

SEMPRA NATURAL GAS

Mesquite Power Sale

In February 2013, Sempra Natural Gas sold one 625-MW block of its 1,250-MW Mesquite Power natural gas-fired power plant in Arizona, including a portion related to common plant, for approximately $371 million in cash to the Salt River Project Agricultural Improvement and Power District (SRP). We recognized a pretax gain on the sale of $74 million ($44 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2013.

Cameron LNG

October 1, 2014 was the effective date of the formation of a joint venture partnership among Sempra Energy and three project partners involving Sempra Natural Gas’ Cameron LNG facility in Louisiana, as we discuss in Note 13. As of October 1, 2014, Sempra Natural Gas will account for its investment in the Cameron LNG joint venture under the equity method.

Asset Held for Sale, Power Plant

In January 2014, management approved a formal plan to market and sell the remaining 625-MW block of the Mesquite Power plant. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining 625-MW block of the Mesquite Power plant to ArcLight Capital Partners, LLC. We anticipate the sale will close late in 2014 or early in 2015, subject to customary regulatory approvals and assignment to the buyer of a 25-year power sales contract associated with the plant.

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 twelve 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, and we stop recording depreciation expense on the asset.

At September 30, 2014, the carrying amount of the major classes of assets and related liability held for sale associated with the plant includes the following:

(Dollars in millions)
Property, plant and equipment, net		$	290
Inventories			3
Total assets held for sale			293
Liability held for sale - asset retirement obligation(1)			(6)
		$	287
(1)	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

The estimated fair value, including estimated costs to sell, exceeds the carrying amount at September 30, 2014.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

SEMPRA SOUTH AMERICAN UTILITIES

Sempra South American Utilities previously owned 43 percent of two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur. In the first quarter of 2013, we recorded a noncash impairment charge of $10 million ($7 million after-tax) to reduce the carrying value of our investments to estimated fair value at that time. The net charge is reported in Equity Earnings, Net of Income Tax on the Condensed Consolidated Statement of Operations for the nine months ended September 30, 2013. In June 2013, we completed the sale of our Argentine investments for $13 million in cash. Our results for the nine months ended September 30, 2013 include an additional $7 million loss ($4 million after-tax) on the sale, which is also included in Equity Earnings, Net of Income Tax.

SEMPRA RENEWABLES

In May 2014, Sempra Renewables invested $109 million, subject to a purchase price adjustment, to become a 50-percent partner with ConEdison Development in four solar projects in California. The joint venture includes ConEdison Development’s CED California Holdings, LLC portfolio, which consists of the 50-MW Alpaugh 50, the 20-MW Alpaugh North and the 20-MW White River 1 facilities in Tulare County, and the 20-MW Corcoran 1 facility in Kings County (collectively, the California solar partnership). The renewable power from all of the projects has been sold under long-term contracts. Sempra Renewables and ConEdison Development each own a 50-percent interest in the four fully operating solar facilities.

Additionally, Sempra Renewables invested cash of $76 million and $5 million in its joint ventures during the nine months ended September 30, 2014 and 2013, respectively.

RBS SEMPRA COMMODITIES

RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses previously owned by us. We and our partner in the joint venture, The Royal Bank of Scotland plc (RBS), sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and early 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs, if any, in Equity Earnings, Before Income Tax on our Condensed Consolidated Statements of Operations.

We received a distribution from the partnership of $50 million in May 2013. The investment balance of $73 million at September 30, 2014 reflects remaining distributions expected to be received from the partnership in accordance with provisions of a 2011 agreement between us and RBS that addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. The amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 11 under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.

We recorded no equity earnings or losses related to the partnership for any of the three-month or nine-month periods ended September 30, 2014 and 2013.

NOTE 5. OTHER FINANCIAL DATA

U.S. TREASURY GRANTS

At December 31, 2012, we had receivables for U.S. Treasury grants based on eligible costs at certain of our renewable generating facilities. During the first quarter of 2013, the federal government imposed automatic federal budget cuts, known as “sequestration,” as required by The Budget Control Act of 2011. As a result, we recorded a reduction to our grants receivable of $23 million and a reversal of income tax benefit of $5 million during the first quarter of 2013. In June 2013, we received $74 million in cash related to the Copper Mountain Solar 2 grant. We received $164 million in cash for the remaining grant receivable for Mesquite Solar 1 in August 2013.

INVENTORIES

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)
	Natural Gas				Liquefied Natural Gas				Materials and Supplies				Total
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
SDG&E	$	6	$	3	$	―	$	―	$	64	$	83	$	70	$	86
SoCalGas		192		42		―		―		29		27		221		69
Sempra South American
Utilities		―		―		―		―		36		40		36		40
Sempra Mexico		―		―		6		3		9		9		15		12
Sempra Renewables		―		―		―		―		3		2		3		2
Sempra Natural Gas		121		68		5		5		1		5		127		78
Sempra Energy
Consolidated	$	319	$	113	$	11	$	8	$	142	$	166	$	472	$	287

GOODWILL

We discuss goodwill in Notes 1 and 3 of the Notes to Consolidated Financial Statements in the Annual Report. The decrease in goodwill from $1.024 billion at December 31, 2013 to $951 million at September 30, 2014 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in Other Comprehensive Income (Loss).

VARIABLE INTEREST ENTITIES (VIE)

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

§	the purpose and design of the VIE;

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

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

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

SDG&E

Tolling Agreements

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based upon our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. 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, as we discuss below.

Otay Mesa VIE

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

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy have consolidated Otay Mesa VIE. Otay Mesa VIE’s equity of $77 million at September 30, 2014 and $91 million at December 31, 2013 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $327 million at September 30, 2014, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.

Other Variable Interest Entities

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary at September 30, 2014. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.

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

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

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Operating revenues
Electric	$	―	$	(4)	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		(4)		―		―
Operating expenses
Cost of electric fuel and purchased power		(27)		(27)		(67)		(65)
Operation and maintenance		3		7		13		33
Depreciation and amortization		7		7		21		20
Total operating expenses		(17)		(13)		(33)		(12)
Operating income		17		9		33		12
Interest expense		(5)		(4)		(13)		(11)
Income before income taxes/Net income		12		5		20		1
Earnings attributable to noncontrolling interest		(12)		(5)		(20)		(1)
Earnings	$	―	$	―	$	―	$	―

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

ASSET RETIREMENT OBLIGATIONS

We discuss asset retirement obligations in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

The changes in asset retirement obligations are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
		Sempra Energy
		Consolidated				SDG&E				SoCalGas
		2014		2013		2014		2013		2014		2013
Balance at January 1(1)		$	2,152	$	2,056	$	913	$	741	$	1,199	$	1,253
Accretion expense			73		74		33		35		38		37
Liabilities incurred			3		4		―		―		―		―
Reclassification(2)			(6)		―		―		―		―		―
Payments			(15)		(1)		(15)		―		―		―
Revisions, GRC-related(3)			―		(135)		―		(30)		―		(105)
Revisions, other(4)(5)			(34)		181		(59)		207		25		―
Balance at September 30(1)		$	2,173	$	2,179	$	872	$	953	$	1,262	$	1,185
(1)	The current portions of the obligations are included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
(2)	Reclassification to liability held for sale - asset retirement obligation which is included in Other Current Liabilities on the Condensed Consolidated Balance Sheets, as we discuss in "Sempra Natural Gas – Asset Held for Sale, Power Plant" in Note 3 above.
(3)	The decreases in asset retirement obligations in 2013 at SDG&E and SoCalGas were due to revised estimates related to the 2012 General Rate Case (GRC) that received final approval in May 2013. At SDG&E, these revisions included increases in asset service lives ranging from 2 percent to 7 percent, and lower estimated cost of removal. At SoCalGas, the decrease included increases in asset service lives ranging from 4 percent to 6 percent, partially offset by a higher estimated cost of removal.
(4)	The decrease in asset retirement obligations in 2014 at SDG&E is due to revised estimates in an updated decommissioning cost study for the San Onofre Nuclear Generating Station, which we discuss in Note 9. The increase in asset retirement obligations in 2014 at SoCalGas is related to a change in estimates.
(5)	The increase in asset retirement obligations in 2013 at SDG&E is due to revised estimates recorded in the third quarter of 2013 related to the early decommissioning of SONGS Units 2 and 3 (see Note 9).

PENSION AND OTHER POSTRETIREMENT BENEFITS

Net Periodic Benefit Cost

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

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,
	2014		2013		2014		2013
Service cost	$	23	$	28	$	6	$	8
Interest cost		39		35		13		10
Expected return on assets		(42)		(39)		(15)		(15)
Amortization of:
Prior service cost (credit)		3		1		(2)		(1)
Actuarial loss		3		11		―		―
Settlements and special termination benefits		5		1		5		―
Regulatory adjustment		6		(14)		5		3
Total net periodic benefit cost	$	37	$	23	$	12	$	5
	Nine months ended September 30,
	2014		2013		2014		2013
Service cost	$	75	$	82	$	18	$	21
Interest cost		121		111		37		33
Expected return on assets		(128)		(121)		(47)		(44)
Amortization of:
Prior service cost (credit)		8		3		(4)		(3)
Actuarial loss		13		41		―		5
Settlements and special termination benefits		14		1		5		―
Regulatory adjustment		(18)		(65)		5		7
Total net periodic benefit cost	$	85	$	52	$	14	$	19

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,
	2014		2013		2014		2013
Service cost	$	8	$	8	$	2	$	2
Interest cost		10		9		3		2
Expected return on assets		(13)		(13)		(2)		(3)
Amortization of:
Prior service cost		―		―		―		1
Actuarial loss		1		3		―		―
Settlements and special termination benefits		―		1		5		―
Regulatory adjustment		6		3		4		1
Total net periodic benefit cost	$	12	$	11	$	12	$	3
	Nine months ended September 30,
	2014		2013		2014		2013
Service cost	$	23	$	24	$	5	$	6
Interest cost		32		30		7		6
Expected return on assets		(41)		(39)		(8)		(7)
Amortization of:
Prior service cost		1		1		2		3
Actuarial loss		3		10		―		―
Settlements and special termination benefits		2		1		5		―
Regulatory adjustment		7		(3)		1		1
Total net periodic benefit cost	$	27	$	24	$	12	$	9

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,
	2014		2013		2014		2013
Service cost	$	13	$	17	$	4	$	5
Interest cost		24		22		9		8
Expected return on assets		(26)		(24)		(12)		(12)
Amortization of:
Prior service cost (credit)		2		―		(2)		(2)
Actuarial loss		1		6		―		―
Settlement		4		―		―		―
Regulatory adjustment		―		(17)		1		2
Total net periodic benefit cost	$	18	$	4	$	―	$	1
	Nine months ended September 30,
	2014		2013		2014		2013
Service cost	$	45	$	50	$	12	$	13
Interest cost		75		68		28		26
Expected return on assets		(78)		(73)		(38)		(36)
Amortization of:
Prior service cost (credit)		6		1		(6)		(6)
Actuarial loss		5		23		―		4
Settlement		4		―		―		―
Regulatory adjustment		(25)		(62)		4		6
Total net periodic benefit cost	$	32	$	7	$	―	$	7

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2014:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2014:
Pension plans	$	95	$	28	$	39
Other postretirement benefit plans		14		12		―
Total expected contributions in 2014:
Pension plans	$	128	$	55	$	40
Other postretirement benefit plans		16		14		―

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 $477 million and $506 million at September 30, 2014 and December 31, 2013, respectively.

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2014 and 2013. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
		Three months ended September 30,				Nine months ended September 30,
		2014		2013		2014		2013
Numerator:
Earnings/Income attributable to common shares		$	348	$	296	$	864	$	719

Denominator:
Weighted-average common shares
	outstanding for basic EPS		246,137		244,140		245,703		243,682
Dilutive effect of stock options, restricted
	stock awards and restricted stock units		4,634		5,119		4,575		5,041
Weighted-average common shares
	outstanding for diluted EPS		250,771		249,259		250,278		248,723

Earnings per share:
Basic		$	1.41	$	1.21	$	3.52	$	2.95
Diluted			1.39		1.19		3.45		2.89

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation of dilutive common stock equivalents excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). We had no such antidilutive stock options outstanding during either the three months or nine months ended September 30, 2014 and 2013.

During the three months and nine months ended September 30, 2014 and 2013, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were no antidilutive RSUs or RSAs from the application of unearned compensation in the treasury stock method for either the three months or nine months ended September 30, 2014 and 2013.

Each performance-based RSU represents the right to receive up to 1.5 shares (2.0 shares for awards granted in 2014) of Sempra Energy common stock based on total shareholder return or EPS growth. RSU awards vest based on Sempra Energy’s four-year cumulative total shareholder return compared to the Standard & Poor’s (S&P) 500 Utilities Index, as follows:

Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)		Number of Sempra Energy Common Shares Received for Each Performance-Based Restricted Stock Unit(2)(3)
90th percentile or above (2014 awards only)		2.0
75th percentile (maximum for awards prior to 2014)		1.5
50th percentile		1.0
35th percentile or below		―
(1)	If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each RSU.
(2)	Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate.
(3)	If performance falls between the tiers shown above, we calculate the payout using linear interpolation.

Beginning in January 2014, we issued performance-based RSUs representing the right to receive up to 2.0 shares of Sempra Energy common stock based on Sempra Energy’s four-year EPS compound annual growth rate beginning January 1, 2014 and ending on December 31, 2017. These RSU awards vest as follows:

Four-Year Earnings Per Share Compound Annual Growth Rate		Number of Sempra Energy Common Shares Received for Each Performance-Based Restricted Stock Unit(1)(2)
8.0% or above		2.0
6.7%		1.5
4.4%		1.0
3.3% or below		―
(1)	Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate.
(2)	If performance falls between the tiers shown above, we calculate the payout using linear interpolation.

Our RSAs, which are solely service-based, and those RSUs that are solely service-based represent the right to receive 1.0 share at the end of the service period and have the same dividend equivalent rights as performance-based RSUs. We include RSAs and those RSUs that are solely service-based in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our performance-based RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative indices, dilutive performance-based RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 844,251 and 971,943 for the three months and nine months ended September 30, 2014, respectively, and 712,941 and 889,420 for the three months and nine months ended September 30, 2013, respectively.

SDG&E PREFERRED STOCK

In September 2013, SDG&E announced that it would redeem all six series of its outstanding shares of contingently redeemable preferred stock. The redemption was completed in October 2013 and, accordingly, we recorded the redemption value, including a $3 million early call premium, as a current liability at September 30, 2013. The early call premium is presented as Call Premium on Preferred Stock of Subsidiary on Sempra Energy’s and Call Premium on Preferred Stock on SDG&E’s Condensed Consolidated Statements of Operations. We provide more detail concerning SDG&E’s preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $8 million and $6 million for the three months ended September 30, 2014 and 2013, respectively, and $22 million and $17 million for the nine months ended September 30, 2014 and 2013, respectively. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s board of directors granted 444,241 performance-based RSUs and 108,986 service-based RSUs during the nine months ended September 30, 2014, primarily in January. Of the 444,241 performance-based RSUs granted, 355,638 vest based on our four-year comparative total shareholder return performance and 88,603 vest based on our four-year EPS compound annual growth rate performance.

During the nine months ended September 30, 2014, IEnova issued 136,996 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which, awards are cash settled based on the price of IEnova common stock.

CAPITALIZED FINANCING COSTS

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

Pipeline projects currently under construction by Sempra Mexico that are both regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC related to equity. Beginning in the fourth quarter of 2013, Sempra Mexico began recording AFUDC related to equity for its Sonora Pipeline project, which was $14 million and $34 million for the three months and nine months ended September 30, 2014, respectively.

The following table shows capitalized financing costs for the three months and nine months ended September 30, 2014 and 2013.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Sempra Energy Consolidated:
AFUDC related to debt	$	5	$	6	$	15	$	17
AFUDC related to equity		28		14		77		44
Other capitalized financing costs		6		9		22		22
Total Sempra Energy Consolidated	$	39	$	29	$	114	$	83
SDG&E:
AFUDC related to debt	$	3	$	4	$	10	$	12
AFUDC related to equity		8		10		26		30
Total SDG&E	$	11	$	14	$	36	$	42
SoCalGas:
AFUDC related to debt	$	2	$	2	$	5	$	5
AFUDC related to equity		7		4		18		14
Total SoCalGas	$	9	$	6	$	23	$	19

COMPREHENSIVE INCOME

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

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
				Pension and Other
				Postretirement Benefits
		Foreign								Total
		Currency		Unamortized		Unamortized				Accumulated Other
		Translation		Net Actuarial		Prior Service		Financial		Comprehensive
		Adjustments		Gain (Loss)		Credit		Instruments		Income (Loss)
		Three months ended September 30, 2014 and 2013
2014:
Balance as of June 30, 2014		$	(170)	$	(65)	$	―	$	(38)	$	(273)
Other comprehensive loss before
reclassifications			(100)		―		―		(2)		(102)
Amounts reclassified from accumulated other
comprehensive income (loss)			―		5		―		(1)		4
Net other comprehensive income (loss)			(100)		5		―		(3)		(98)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)
2013:
Balance as of June 30, 2013		$	(96)	$	(98)	$	1	$	(26)	$	(219)
Other comprehensive income (loss) before
reclassifications			5		―		―		(6)		(1)
Amounts reclassified from accumulated other
comprehensive income			―		3		―		2		5
Net other comprehensive income (loss)			5		3		―		(4)		4
Balance as of September 30, 2013		$	(91)	$	(95)	$	1	$	(30)	$	(215)

		Nine months ended September 30, 2014 and 2013
2014:
Balance as of December 31, 2013		$	(129)	$	(73)	$	―	$	(26)	$	(228)
Other comprehensive loss before
reclassifications			(141)		―		―		(28)		(169)
Amounts reclassified from accumulated other
comprehensive income			―		13		―		13		26
Net other comprehensive income (loss)			(141)		13		―		(15)		(143)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)
2013:
Balance as of December 31, 2012		$	(240)	$	(102)	$	1	$	(35)	$	(376)
Other comprehensive income (loss) before
reclassifications			(121)		―		―		1		(120)
Amounts reclassified from accumulated other
comprehensive income			270	(2)	7		―		4		281
Net other comprehensive income			149		7		―		5		161
Balance as of September 30, 2013		$	(91)	$	(95)	$	1	$	(30)	$	(215)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.
(2)	Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
		Pension and Other
		Postretirement Benefits
						Total
		Unamortized		Unamortized		Accumulated Other
		Net Actuarial		Prior Service		Comprehensive
		Gain (Loss)		Credit		Income (Loss)
		Three months ended September 30, 2014 and 2013
2014:
Balance as of June 30, 2014		$	(9)	$	1	$	(8)
Amounts reclassified from accumulated other
comprehensive income			1		―		1
Net other comprehensive income			1		―		1
Balance as of September 30, 2014		$	(8)	$	1	$	(7)
2013:
Balance as of June 30, 2013		$	(11)	$	1	$	(10)
Amounts reclassified from accumulated other
comprehensive income			1		―		1
Net other comprehensive income			1		―		1
Balance as of September 30, 2013		$	(10)	$	1	$	(9)

		Nine months ended September 30, 2014 and 2013
2014:
Balance as of December 31, 2013		$	(10)	$	1	$	(9)
Amounts reclassified from accumulated other
comprehensive income			2		―		2
Net other comprehensive income			2		―		2
Balance as of September 30, 2014		$	(8)	$	1	$	(7)
2013:
Balance as of December 31, 2012		$	(12)	$	1	$	(11)
Amounts reclassified from accumulated other
comprehensive income			2		―		2
Net other comprehensive income			2		―		2
Balance as of September 30, 2013		$	(10)	$	1	$	(9)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
		Pension and Other
		Postretirement Benefits
								Total
		Unamortized		Unamortized				Accumulated Other
		Net Actuarial		Prior Service		Financial		Comprehensive
		Gain (Loss)		Credit		Instruments		Income (Loss)
		Three months ended September 30, 2014 and 2013
2014:
Balance as of June 30, 2014		$	(5)	$	1	$	(14)	$	(18)
Amounts reclassified from accumulated other
comprehensive income			2		―		―		2
Net other comprehensive income			2		―		―		2
Balance as of September 30, 2014		$	(3)	$	1	$	(14)	$	(16)
2013:
Balance as of June 30 and September 30, 2013		$	(4)	$	1	$	(14)	$	(17)

		Nine months ended September 30, 2014 and 2013
2014:
Balance as of December 31, 2013		$	(5)	$	1	$	(14)	$	(18)
Amounts reclassified from accumulated other
comprehensive income			2		―		―		2
Net other comprehensive income			2		―		―		2
Balance as of September 30, 2014		$	(3)	$	1	$	(14)	$	(16)
2013:
Balance as of December 31, 2012		$	(4)	$	1	$	(15)	$	(18)
Amounts reclassified from accumulated other
comprehensive income			―		―		1		1
Net other comprehensive income			―		―		1		1
Balance as of September 30, 2013		$	(4)	$	1	$	(14)	$	(17)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated		Amounts reclassified
other comprehensive income (loss)		from accumulated other				Affected line item on Condensed
components		comprehensive income (loss)				Consolidated Statements of Operations
		Three months ended September 30,
		2014		2013
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	8	$	3	Interest Expense
Interest rate instruments			(5)		―	Gain on Sale of Equity Interests and Assets
Interest rate instruments			2		3	Equity Earnings, Before Income Tax
Commodity contracts not subject						Revenues: Energy-Related
	to rate recovery		(2)		―	Businesses
Total before income tax			3		6
			(1)		(2)	Income Tax Expense
Net of income tax			2		4
			(3)		(2)	Earnings Attributable to Noncontrolling Interests
		$	(1)	$	2

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

Total reclassifications for the period, net of tax		$	4	$	5
SDG&E:
Financial instruments:
Interest rate instruments		$	3	$	2	Interest Expense
			(3)		(2)	Earnings Attributable to Noncontrolling Interest
		$	―	$	―

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

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

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

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated		Amount reclassified
other comprehensive income (loss)		from accumulated other				Affected line item on Condensed
components		comprehensive income (loss)				Consolidated Statements of Operations
		Nine months ended September 30,
		2014		2013
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	270	Equity Earnings, Net of Income Tax(1)

Financial instruments:
Interest rate and foreign exchange instruments		$	17	$	9	Interest Expense
Interest rate instruments			(3)		―	Gain on Sale of Equity Interests and Assets
Interest rate instruments			7		7	Equity Earnings, Before Income Tax
Commodity contracts not subject to						Revenues: Energy-Related
	rate recovery		8		(5)	Businesses
Total before income tax			29		11
			(8)		(1)	Income Tax Expense
Net of income tax			21		10
			(8)		(6)	Earnings Attributable to Noncontrolling Interests
		$	13	$	4

Pension and other postretirement benefits:
Amortization of actuarial loss		$	21	$	12	(2)
			(8)		(5)	Income Tax Expense
Net of income tax		$	13	$	7

Total reclassifications for the period, net of tax		$	26	$	281
SDG&E:
Financial instruments:
Interest rate instruments		$	8	$	6	Interest Expense
			(8)		(6)	Earnings Attributable to Noncontrolling Interest
		$	―	$	―

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

Total reclassifications for the period, net of tax		$	2	$	2
SoCalGas:
Financial instruments:
Interest rate instruments		$	―	$	1	Interest Expense
			―		―	Income Tax Expense
Net of income tax		$	―	$	1

Pension and other postretirement benefits:
Amortization of actuarial loss		$	4	$	―	(2)
			(2)		―	Income Tax Expense
Net of income tax		$	2	$	―

Total reclassifications for the period, net of tax		$	2	$	1
(1)	Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4.
(2)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following three tables provide a reconciliation of changes in Sempra Energy’s, SDG&E’s and SoCalGas’ shareholders’ equity and noncontrolling interests for the nine months ended September 30, 2014 and 2013.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Sempra Energy		Non-
		Shareholders’		controlling		Total
		Equity		Interests		Equity
Balance at December 31, 2013	$	11,008	$	842	$	11,850
Comprehensive income		722		66		788
Preferred dividends of subsidiary		(1)		―		(1)
Share-based compensation expense		35		―		35
Common stock dividends declared		(486)		―		(486)
Issuance of common stock		71		―		71
Repurchase of common stock		(38)		―		(38)
Tax benefit related to share-based compensation		22		―		22
Equity contributed by noncontrolling interest		―		1		1
Distributions to noncontrolling interests		―		(85)		(85)
Balance at September 30, 2014	$	11,333	$	824	$	12,157
Balance at December 31, 2012	$	10,282	$	401	$	10,683
Comprehensive income		888		33		921
Preferred dividends of subsidiaries		(5)		―		(5)
Share-based compensation expense		30		―		30
Common stock dividends declared		(460)		―		(460)
Issuance of common stock		57		―		57
Repurchase of common stock		(45)		―		(45)
Tax benefit related to share-based compensation		30		―		30
Sale of noncontrolling interests, net of offering costs		135		439		574
Distributions to noncontrolling interests		―		(28)		(28)
Call premium on preferred stock of subsidiary		(3)		―		(3)
Balance at September 30, 2013	$	10,909	$	845	$	11,754

SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST ― SDG&E
(Dollars in millions)
		SDG&E		Non-
		Shareholder’s		controlling		Total
		Equity		Interest		Equity
Balance at December 31, 2013	$	4,628	$	91	$	4,719
Comprehensive income		381		23		404
Distributions to noncontrolling interest		―		(37)		(37)
Balance at September 30, 2014	$	5,009	$	77	$	5,086
Balance at December 31, 2012	$	4,222	$	76	$	4,298
Comprehensive income		294		15		309
Preferred stock dividends declared		(4)		―		(4)
Distributions to noncontrolling interest		―		(12)		(12)
Call premium on preferred stock		(3)		―		(3)
Balance at September 30, 2013	$	4,509	$	79	$	4,588

SHAREHOLDERS' EQUITY ― SOCALGAS
(Dollars in millions)
		SoCalGas
		Shareholders'
		Equity
Balance at December 31, 2013	$	2,549
Comprehensive income		259
Preferred stock dividends declared		(1)
Balance at September 30, 2014	$	2,807
Balance at December 31, 2012	$	2,235
Comprehensive income		268
Preferred stock dividends declared		(1)
Common stock dividends declared		(50)
Balance at September 30, 2013	$	2,452

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

Sale of Noncontrolling Interests

In the first quarter of 2013, a Sempra Energy subsidiary IEnova, completed a private offering in the U.S. and outside of Mexico and a concurrent public offering in Mexico of common stock. The aggregate shares of common stock sold in the offerings represent approximately 18.9 percent of IEnova’s outstanding ownership interest. IEnova is reported within the Sempra Mexico reportable segment.

The proceeds from the offerings, net of offering costs, were approximately $574 million in U.S. dollar equivalent. IEnova has used the net proceeds of the offerings primarily for general corporate purposes, and for the funding of its investments and ongoing expansion plans. Consistent with applicable accounting guidance, changes in noncontrolling interests that do not result in a change of control are accounted for as equity transactions. 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 and overallotment options, we recorded an increase in Sempra Energy’s shareholders’ equity of $135 million in the first quarter of 2013 for the sale of IEnova shares to noncontrolling interests.

IEnova is a separate legal entity comprised primarily 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. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA.

We discuss the IEnova offerings in more detail in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Preferred Stock

The preferred stock of SoCalGas is presented at Sempra Energy as a noncontrolling interest. In 2013, SDG&E had preferred stock outstanding until it was fully redeemed in October 2013. At Sempra Energy, the preferred stock dividends of both SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

At September 30, 2014 and December 31, 2013, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
		Percent Ownership Held by Others			September 30, 2014		December 31, 2013
SDG&E:
Otay Mesa VIE		100	%	$	77	$	91
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)		23.6 – 43.4			23		27
Luz del Sur		20.2			219		222
Tecsur		9.8			3		3
Sempra Mexico:
IEnova		18.9			444		442
Sempra Natural Gas:
Bay Gas Storage, Ltd.		9.1			23		22
Liberty Gas Storage, LLC		25.0			14		14
Southern Gas Transmission Company		49.0			1		1
Total Sempra Energy				$	804	$	822
(1)	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages amongst these subsidiaries.

TRANSACTIONS WITH AFFILIATES

Due from Unconsolidated Affiliates – Sempra Energy Consolidated

Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A. to provide project financing for the construction of transmission lines. Eletrans S.A. is an affiliate of Chilquinta Energía that we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. At September 30, 2014 and December 31, 2013, the principal balance outstanding was $39 million and $14 million, plus $1 million and a negligible amount of accumulated interest outstanding, respectively, at a fixed interest rate of 4 percent.

In the third quarter of 2014, Sempra Mexico made two four-year, U.S. dollar-denominated loans to an affiliate of Sempra Mexico’s joint venture with PEMEX to finance the Los Ramones Norte pipeline project. At September 30, 2014, these loans have principal balances outstanding aggregating $71 million plus $1 million of accumulated interest. These loans accrue interest at a variable rate based on a 30-day LIBOR plus 450 basis points (4.66 percent at September 30, 2014).

As we discuss in Note 3, in July 2014, Sempra Mexico sold a 50-percent interest in the first phase of the Energía Sierra Juárez wind project. Upon deconsolidation, the newly formed joint venture repaid a portion, in the amount of $18 million, of a previous intercompany loan from Sempra Mexico to Energía Sierra Juárez. The joint venture assumed the obligation to Sempra Mexico for the remainder of the loan, which has a principal balance outstanding at September 30, 2014 of $20 million plus $1 million of accumulated interest. This loan accrues interest at a variable rate based on a 30-day LIBOR plus 637.5 basis points (6.53 percent at September 30, 2014).

At September 30, 2014 and December 31, 2013, Sempra Energy had $3 million and $4 million, respectively, in accounts receivable from various Sempra Renewables joint venture investments.

Service Agreements

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

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2014		2013
SDG&E:
Current:
Due from various affiliates		$	1	$	1


Due to Sempra Energy		$	27	$	25
Due to SoCalGas			9		―
Due to various affiliates			―		14
		$	36	$	39

Income taxes due from Sempra Energy(1)		$	27	$	70
SoCalGas:
Current:
Due from Sempra Energy(2)		$	265	$	―
Due from SDG&E			9		―
Due from various affiliates			―		21
		$	274	$	21


Due to Sempra Energy		$	―	$	16


Income taxes due from Sempra Energy(1)		$	21	$	18
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies’ having always filed separate returns.
(2)	Net receivable includes a loan to Sempra Energy of $281 million at September 30, 2014 at an interest rate of 0.08 percent.

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

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014			2013
SDG&E	$	2	$	3	$	8	$	8
SoCalGas		17		17		51		48

OTHER INCOME, NET

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

OTHER INCOME, NET
(Dollars in millions)
		Three months ended				Nine months ended
		September 30,				September 30,
			2014		2013		2014		2013
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	28	$	14	$	77	$	44
Investment (losses) gains(1)			(3)		(6)		20		16
(Losses) gains on interest rate and foreign exchange instruments, net			(6)		4		3		17
Regulatory interest, net(2)			2		1		5		3
Sundry, net			8		3		13		(1)
Total		$	29	$	16	$	118	$	79
SDG&E:
Allowance for equity funds used during construction		$	8	$	10	$	26	$	30
Regulatory interest, net(2)			2		1		5		3
Sundry, net			(1)		(1)		(2)		(3)
Total		$	9	$	10	$	29	$	30
SoCalGas:
Allowance for equity funds used during construction		$	7	$	4	$	18	$	14
Sundry, net			(1)		(2)		(5)		(5)
Total		$	6	$	2	$	13	$	9
(1)	Represents investment (losses) gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

INCOME TAXES

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
		Three months ended September 30,
		2014				2013
Sempra Energy Consolidated	$	71	16	%	$	117	27	%
SDG&E		65	28			84	38
SoCalGas		44	31			38	27
		Nine months ended September 30,
		2014				2013
Sempra Energy Consolidated	$	291	24	%	$	327	30	%
SDG&E		217	35			147	33
SoCalGas		110	30			107	29

Changes in Income Tax Expense and Effective Income Tax Rates

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended September 30, 2014 was mainly due to a lower effective tax rate, primarily from:

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

§	higher income tax benefit from Mexican currency translation and inflation adjustments; and

§	favorable adjustments to prior years’ income tax items in 2014; offset by

§	$8 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru.

In the first nine months of 2014, the decrease in income tax expense was due to a lower effective tax rate, offset by higher pretax income. Pretax income in 2013 included the loss from the early retirement of San Onofre Nuclear Generating Station (SONGS), offset by the favorable impact of the retroactive application of the 2012 GRC in 2013. The lower effective income tax rate was primarily due to:

§	$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings above in “Shareholders’ Equity and Noncontrolling Interests – Sale of Noncontrolling Interests;” and

§	$25 million tax benefit due to the release in 2014 of Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments; offset by

§	$32 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru; and

a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that may no longer be recoverable from customers in rates pursuant to the proposed settlement agreement to resolve the California Public Utilities Commission’s (CPUC) Order Instituting Investigation (OII) into the SONGS outage that we discuss in Note 9.

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

§	self-developed software expenditures

§	repairs to certain utility plant fixed assets

§	renewable energy income tax credits

§	deferred income tax benefits related to renewable energy projects

§	exclusions from taxable income of the equity portion of AFUDC

§	depreciation on a certain portion of utility plant assets

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

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

SDG&E

The decrease in SDG&E’s income tax expense in the three months ended September 30, 2014 was mainly due to a lower effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2014 compared to unfavorable adjustments in 2013; and

§	lower unfavorable impact on our effective tax rate in 2014 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; offset by

§	lower deductions for self-developed software expenditures.

The increase in SDG&E’s income tax expense in the nine months ended September 30, 2014 was due to higher pretax income and a higher effective tax rate. Pretax income in 2013 included the loss from the early retirement of SONGS, offset by the favorable impact of the retroactive application of the 2012 GRC in 2013. The higher effective tax rate was primarily due to:

§	the $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS discussed in Note 9;

§	lower exclusions from taxable income of the equity portion of AFUDC; and

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

§	favorable adjustments to prior years’ income tax items in 2014 compared to unfavorable adjustments in 2013.

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

SoCalGas

The increase in SoCalGas’ income tax expense in the three months ended September 30, 2014 was mainly due to a higher effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2013; and

§	lower deductions for self-developed software expenditures.

The increase in SoCalGas’ income tax expense in the nine months ended September 30, 2014 was mainly due to a higher effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2013; offset by

§	higher deductions for certain repairs expenditures that are capitalized for financial statement purposes.

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

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

§	the equity portion of AFUDC

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

§	self-developed software expenditures

§	depreciation on a certain portion of utility plant fixed assets

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

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

NOTE 6. DEBT AND CREDIT FACILITIES

LINES OF CREDIT

At September 30, 2014, Sempra Energy Consolidated had an aggregate of $4.1 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the major components of which we detail below. Available unused credit on these lines at September 30, 2014 was $2.8 billion. Some of Sempra Energy’s subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $875 million at September 30, 2014. Available unused credit on these lines totaled $630 million at September 30, 2014.

Sempra Energy

Sempra Energy has a $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share.

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2014 and December 31, 2013, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. The facility also provides for issuance of up to $635 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.

At September 30, 2014, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.

Sempra Global

Sempra Global has a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2014 and December 31, 2013, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

At September 30, 2014, Sempra Global had $1.2 billion of commercial paper outstanding supported by the facility. At December 31, 2013, Sempra Global had $200 million of commercial paper outstanding classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows.

California Utilities

SDG&E and SoCalGas have a combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $300 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit.

Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility’s credit ratings. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2014 and December 31, 2013, the California Utilities were in compliance with this and all other financial covenants under the credit facility.

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

At September 30, 2014, SDG&E had $100 million of commercial paper outstanding supported by the facility at an interest rate of 0.40 percent. SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at September 30, 2014 was $558 million at SDG&E and $658 million at SoCalGas, subject to the combined limit on the facility of $877 million.

Sempra Mexico

In June 2014, IEnova entered into an agreement for a $200 million, U.S. dollar-denominated, three-year corporate revolving credit facility to finance working capital and for general corporate purposes. The lender is Banco Santander, (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander Mexico. At September 30, 2014, Mexico had $145 million of outstanding borrowings supported by the facility, and available unused credit on the line was $55 million.

In August 2014, IEnova entered into an agreement for a $100 million, U.S. dollar-denominated, three-year corporate revolving credit facility to finance working capital and for general corporate purposes. The lender is Sumitomo Mitsui Banking Corporation. At September 30, 2014, Mexico had no outstanding borrowings supported by the facility.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt at Sempra Energy were 0.76 percent and 0.64 percent at September 30, 2014 and December 31, 2013, respectively. The weighted average interest rate on total short-term debt was 0.13 percent at both SDG&E and SoCalGas at December 31, 2013. The weighted average interest rate at Sempra Energy at December 31, 2013 includes interest rates for the $200 million of the commercial paper borrowings supported by the Sempra Global credit facility classified as long-term, as we discuss above.

LONG-TERM DEBT

Sempra Energy

In June 2014, Sempra Energy publicly offered and sold $500 million of 3.55-percent, fixed-rate notes maturing in 2024. Sempra Energy used the proceeds from this offering for the repayment of commercial paper.

SDG&E

In the second quarter of 2014, SDG&E issued $100 million of commercial paper maturing in May 2015, which is supported by the California Utilities’ credit facility discussed above and has a weighted average interest rate of 0.40 percent at September 30, 2014.

SoCalGas

In September 2014, SoCalGas publicly offered and sold $500 million of 3.15-percent first mortgage bonds maturing in 2024. SoCalGas used the proceeds from this offering for the repayment of commercial paper and other general corporate purposes.

In March 2014, SoCalGas publicly offered and sold $250 million of 4.45-percent first mortgage bonds maturing in 2044. SoCalGas used the proceeds from this offering for the repayment of its 5.5-percent first mortgage bonds that matured in March 2014.

Sempra Mexico

In June 2014, Energía Sierra Juárez entered into a $240 million loan to project finance the construction of the wind project. The variable rate loan is secured by the project and will convert to an 18-year term loan upon completion of the first phase of the project. To partially moderate its exposure to interest rate changes associated with the term loan, Energía Sierra Juárez entered into floating-to-fixed interest rate swaps for 90 percent of the loan amount, which will result in an effective fixed rate of 6.1 percent. The swap is effective on the conversion to a term loan. The remaining 10 percent of principal bears interest at rates varying with market rates (0.16 percent at September 30, 2014). The loan agreement also provides for a $31.7 million letter of credit facility. Energía Sierra Juárez also entered into a separate, Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project. On June 12, 2014, Energía Sierra Juárez drew down $82 million of the construction loan. On July 16, 2014, this $82 million of long-term debt and the related swaps were deconsolidated upon the sale of a 50-percent interest in Energía Sierra Juárez, as we discuss in Note 3.

Sempra Renewables

On March 6, 2014, Sempra Renewables entered into a $356 million construction loan to finance its Copper Mountain Solar 3 project. The loan is secured by the project and will convert to a 10-year term loan upon completion of the project. To partially moderate its exposure to interest rate changes, Copper Mountain Solar 3 entered into floating-to-fixed interest rate swaps for 75 percent of the loan amount, resulting in an effective fixed rate of 5.35 percent. The remaining 25 percent bears interest at rates varying with market rates (0.16 percent at September 30, 2014). In connection with the loan agreement, Copper Mountain Solar 3 may also utilize up to $72 million under a letter of credit facility, which may be used to meet project collateral requirements and debt service reserve requirements. On March 6, 2014, Copper Mountain Solar 3 drew down $97 million from the loan. On March 13, 2014, this $97 million of long-term debt and the related swaps were deconsolidated upon the sale of a 50-percent interest in Copper Mountain Solar 3, as we discuss in Note 3.

INTEREST RATE SWAPS

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

NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

HEDGE ACCOUNTING

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

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

ENERGY DERIVATIVES

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

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

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

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

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

We summarize net energy derivative volumes at September 30, 2014 and December 31, 2013 as follows:

NET ENERGY DERIVATIVE VOLUMES

Segment and Commodity		September 30, 2014	December 31, 2013
California Utilities:
SDG&E:
Natural gas		43 million MMBtu	43 million MMBtu	(1)
Congestion revenue rights		27 million MWh	33 million MWh	(2)
SoCalGas - natural gas		―	2 million MMBtu

Energy-Related Businesses:
Sempra Natural Gas:
Electric power		―	1 million MWh
Natural gas		31 million MMBtu	15 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

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

INTEREST RATE DERIVATIVES

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

In the first quarter of 2014, we entered into fixed-to-floating interest rate swaps on Sempra Energy debt that were designated as fair value hedges. We swapped $200 million 6.15-percent fixed-rate debt maturing in 2018, $200 million 9.8-percent fixed-rate debt maturing in 2019 and $100 million 2.875-percent fixed-rate debt maturing in 2022 to variable rate debt, resulting in initial effective interest rates of 3.80 percent, 6.01 percent and 2.37 percent, respectively. These swaps were terminated in July 2014.

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

At September 30, 2014 and December 31, 2013, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:

INTEREST RATE DERIVATIVES
(Dollars in millions)
		September 30, 2014			December 31, 2013
		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges(1)		$	404	2014-2028	$	413	2014-2028
Fair value hedges			300	2016		300	2016
SDG&E:
Cash flow hedge(1)			327	2019		335	2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We are exposed to exchange rate movements at our Mexican subsidiaries, which have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts. We may also utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries. On February 14, 2013, Sempra Mexico entered into cross-currency swap agreements, which were designated as cash flow hedges. We discuss the notional amount of the swaps in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

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

FINANCIAL STATEMENT PRESENTATION

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at September 30, 2014 and December 31, 2013, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2014
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	12	$	7	$	(17)	$	(77)
Commodity contracts not subject to rate recovery			1		―		―		―
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			8		24		(7)		(20)
Commodity contracts not subject to rate recovery			39		10		(36)		(7)
Associated offsetting commodity contracts			(32)		(7)		32		7
Associated offsetting cash collateral			―		―		1		―
Commodity contracts subject to rate recovery			14		82		(13)		(6)
Associated offsetting commodity contracts			(4)		(2)		4		2
Associated offsetting cash collateral			―		―		3		―
Net amounts presented on the balance sheet			38		114		(33)		(101)
Additional cash collateral for commodity contracts
not subject to rate recovery			15		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			30		―		―		―
Total(4)		$	83	$	114	$	(33)	$	(101)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(32)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery			11		82		(11)		(6)
Associated offsetting commodity contracts			(2)		(2)		2		2
Associated offsetting cash collateral			―		―		3		―
Net amounts presented on the balance sheet			9		80		(22)		(36)
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			28		―		―		―
Total(4)		$	38	$	80	$	(22)	$	(36)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		$	3	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(2)		―		2		―
Net amounts presented on the balance sheet			1		―		―		―
Additional cash collateral for commodity contracts
not subject to rate recovery			2		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			2		―		―		―
Total		$	5	$	―	$	―	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.


DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2013
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	14	$	12	$	(18)	$	(75)
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			8		22		(7)		(17)
Commodity contracts not subject to rate recovery			47		7		(51)		(5)
Associated offsetting commodity contracts			(43)		(5)		43		5
Associated offsetting cash collateral			―		―		1		―
Commodity contracts subject to rate recovery			35		72		(10)		(8)
Associated offsetting commodity contracts			(3)		(2)		3		2
Net amounts presented on the balance sheet			58		106		(39)		(98)
Additional cash collateral for commodity contracts
not subject to rate recovery			17		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			31		―		―		―
Total(4)		$	106	$	106	$	(39)	$	(98)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(39)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery			34		72		(9)		(8)
Associated offsetting commodity contracts			(3)		(2)		3		2
Net amounts presented on the balance sheet			31		70		(22)		(45)
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			29		―		―		―
Total(4)		$	61	$	70	$	(22)	$	(45)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		$	1	$	―	$	(1)	$	―
Net amounts presented on the balance sheet			1		―		(1)		―
Additional cash collateral for commodity contracts
not subject to rate recovery			2		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			2		―		―		―
Total		$	5	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

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

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2014		2013		2014		2013
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	6	$	6
Interest rate instruments		Other Income, Net		(1)		1		―		(4)
Total(1)			$	―	$	3	$	6	$	2
(1)	There were negligible gains from hedge ineffectiveness on these swaps for the three-month period, and $9 million of gains from hedge ineffectiveness for the nine-month period ended September 30, 2014, respectively. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net. There was no hedge ineffectiveness in 2013.

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax gain (loss) recognized					Gain (loss) reclassified from AOCI
		in OCI (effective portion)					into earnings (effective portion)
		Three months ended September 30,					Three months ended September 30,
		2014		2013		Location	2014		2013
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)		$	(5)	$	(8)	Interest Expense	$	(8)	$	(3)
						Gain on Sale of Equity
Interest rate instruments			5		―	Interests and Assets		5		―
						Equity Earnings,
Interest rate instruments			(4)		(3)	Before Income Tax		(2)		(3)
Commodity contracts not subject						Revenues: Energy-Related
to rate recovery			1		1	Businesses		2		―
Total(2)		$	(3)	$	(10)		$	(3)	$	(6)
SDG&E:
Interest rate instruments(1)(2)		$	1	$	(3)	Interest Expense	$	(3)	$	(2)

		Nine months ended September 30,					Nine months ended September 30,
		2014		2013		Location	2014		2013
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)		$	(15)	$	(3)	Interest Expense	$	(17)	$	(9)
						Gain on Sale of Equity
Interest rate instruments			3		―	Interests and Assets		3		―
						Equity Earnings,
Interest rate instruments			(34)		11	Before Income Tax		(7)		(7)
Commodity contracts not subject						Revenues: Energy-Related
to rate recovery			(5)		5	Businesses		(8)		5
Total(2)		$	(51)	$	13		$	(29)	$	(11)
SDG&E:
Interest rate instruments(1)(2)		$	(5)	$	8	Interest Expense	$	(8)	$	(6)
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	―	$	(1)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)	There was a negligible amount of ineffectiveness related to these hedges in 2014 and 2013.

For Sempra Energy Consolidated we expect that losses of $25 million, which are net of income tax benefit, that are currently recorded in AOCI (including $13 million in noncontrolling interests, of which $12 million is related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

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

For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at September 30, 2014 is approximately 14 years and 5 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables’ equity method investees is 21 years.

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

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2014		2013		2014		2013
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments	Other Income, Net	$	(6)	$	4	$	(6)	$	17
Foreign exchange instruments	Equity Earnings,
	Net of Income Tax		(2)		―		(4)		(3)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		3		1		2		2
Commodity contracts not subject	Cost of Natural Gas, Electric Fuel
to rate recovery	and Purchased Power		1		―		3		―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(1)		―		19		(9)
Commodity contracts subject
to rate recovery	Cost of Natural Gas		1		1		2		―
Total		$	(4)	$	6	$	16	$	7
SDG&E:
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power	$	(1)	$	―	$	19	$	(9)
SoCalGas:
Commodity contracts subject
to rate recovery	Cost of Natural Gas	$	1	$	1	$	2	$	―

CONTINGENT FEATURES

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

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at September 30, 2014 and December 31, 2013 is $2 million and $3 million, respectively. At September 30, 2014, if the credit ratings of Sempra Energy were reduced below investment grade, $2 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position was negligible at September 30, 2014 and $3 million at December 31, 2013. At September 30, 2014, if the credit ratings of SDG&E were reduced below investment grade, a negligible amount 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.

NOTE 8. FAIR VALUE MEASUREMENTS

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the nine months ended September 30, 2014.

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2014 and December 31, 2013. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels.

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

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

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2014 and December 31, 2013 in the tables below include the following:

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

We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We may also manage foreign exchange rate exposures using derivatives. We primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). All Level 3 recurring items are related to CRRs at SDG&E, as we discuss below under “Level 3 Information.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates.

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

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

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Fair value at September 30, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	637	$	―	$	―	$	―	$	637
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			56		47		―		―		103
Municipal bonds			―		121		―		―		121
Other securities			―		200		―		―		200
Total debt securities			56		368		―		―		424
Total nuclear decommissioning trusts(2)			693		368		―		―		1,061
Interest rate and foreign exchange instruments			―		51		―		―		51
Commodity contracts not subject to rate recovery			7		4		―		15		26
Commodity contracts subject to rate recovery			―		3		87		30		120
Total		$	700	$	426	$	87	$	45	$	1,258
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	121	$	―	$	―	$	121
Commodity contracts not subject to rate recovery			2		3		―		(2)		3
Commodity contracts subject to rate recovery			3		10		―		(3)		10
Total		$	5	$	134	$	―	$	(5)	$	134

		Fair value at December 31, 2013
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	614	$	―	$	―	$	―	$	614
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			59		58		―		―		117
Municipal bonds			―		111		―		―		111
Other securities			―		153		―		―		153
Total debt securities			59		322		―		―		381
Total nuclear decommissioning trusts(2)			673		322		―		―		995
Interest rate and foreign exchange instruments			―		56		―		―		56
Commodity contracts not subject to rate recovery			1		5		―		17		23
Commodity contracts subject to rate recovery			2		1		99		31		133
Total		$	676	$	384	$	99	$	48	$	1,207
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	117	$	―	$	―	$	117
Commodity contracts not subject to rate recovery			4		8		―		(5)		7
Commodity contracts subject to rate recovery			―		13		―		―		13
Total		$	4	$	138	$	―	$	(5)	$	137
(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		Fair value at September 30, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	637	$	―	$	―	$	―	$	637
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			56		47		―		―		103
Municipal bonds			―		121		―		―		121
Other securities			―		200		―		―		200
Total debt securities			56		368		―		―		424
Total nuclear decommissioning trusts(2)			693		368		―		―		1,061
Commodity contracts not subject to rate recovery			―		―		―		1		1
Commodity contracts subject to rate recovery			―		2		87		28		117
Total		$	693	$	370	$	87	$	29	$	1,179
Liabilities:
Interest rate instruments		$	―	$	48	$	―	$	―	$	48
Commodity contracts subject to rate recovery			3		10		―		(3)		10
Total		$	3	$	58	$	―	$	(3)	$	58

		Fair value at December 31, 2013
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	614	$	―	$	―	$	―	$	614
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			59		58		―		―		117
Municipal bonds			―		111		―		―		111
Other securities			―		153		―		―		153
Total debt securities			59		322		―		―		381
Total nuclear decommissioning trusts(2)			673		322		―		―		995
Commodity contracts not subject to rate recovery			―		―		―		1		1
Commodity contracts subject to rate recovery			1		1		99		29		130
Total		$	674	$	323	$	99	$	30	$	1,126
Liabilities:
Interest rate instruments		$	―	$	55	$	―	$	―	$	55
Commodity contracts subject to rate recovery			―		12		―		―		12
Total		$	―	$	67	$	―	$	―	$	67
(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
		Fair value at September 30, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Commodity contracts not subject to rate recovery		$	―	$	―	$	―	$	2	$	2
Commodity contracts subject to rate recovery			―		1		―		2		3
Total		$	―	$	1	$	―	$	4	$	5
Liabilities:
Commodity contracts subject to rate recovery		$	―	$	―	$	―	$	―	$	―
Total		$	―	$	―	$	―	$	―	$	―

		Fair value at December 31, 2013
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Commodity contracts not subject to rate recovery		$	―	$	―	$	―	$	2	$	2
Commodity contracts subject to rate recovery			1		―		―		2		3
Total		$	1	$	―	$	―	$	4	$	5
Liabilities:
Commodity contracts subject to rate recovery		$	―	$	1	$	―	$	―	$	1
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 Congestion Revenue Rights (CRRs) classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	Three months ended September 30,
	2014		2013
Balance at July 1	$	85	$	47
Realized and unrealized gains		3		1
Allocated transmission instruments		9		15
Settlements		(10)		(6)
Balance at September 30	$	87	$	57
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	2

	Nine months ended September 30,
	2014		2013
Balance as of January 1	$	99	$	61
Realized and unrealized gains (losses)		9		(2)
Allocated transmission instruments		10		15
Settlements		(31)		(17)
Balance as of September 30	$	87	$	57
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	1

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

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (CAISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. At September 30, 2014 the auction prices ranged from $(6) per MWh to $12 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. At September 30, 2013 the auction prices ranged from $(8) per MWh to $8 per MWh. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2014 and December 31, 2013:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2014
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)		$	12,346	$	―	$	12,626	$	873	$	13,499
Preferred stock of subsidiary			20		―		23		―		23
SDG&E:
Total long-term debt(2)		$	4,463	$	―	$	4,463	$	427	$	4,890
SoCalGas:
Total long-term debt(3)		$	1,913	$	―	$	2,053	$	―	$	2,053
Preferred stock			22		―		24		―		24

		December 31, 2013
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)		$	12,022	$	―	$	11,925	$	751	$	12,676
Preferred stock of subsidiary			20		―		20		―		20
SDG&E:
Total long-term debt(2)		$	4,386	$	―	$	4,226	$	335	$	4,561
SoCalGas:
Total long-term debt(3)		$	1,413	$	―	$	1,469	$	―	$	1,469
Preferred stock			22		―		22		―		22
(1)	Before reductions for unamortized discount (net of premium) of $21 million and $17 million at September 30, 2014 and December 31, 2013, respectively, and excluding build-to-suit and capital leases of $300 million and $195 million at September 30, 2014 and December 31, 2013, respectively, and commercial paper classified as long-term debt of $200 million at December 31, 2013. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(2)	Before reductions for unamortized discount of $10 million and $11 million at September 30, 2014 and December 31, 2013, respectively, and excluding capital leases of $235 million and $179 million at September 30, 2014 and December 31, 2013, respectively.
(3)	Before reductions for unamortized discount of $7 million and $4 million at September 30, 2014 and December 31, 2013, respectively, and excluding capital leases of $2 million at December 31, 2013.

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

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

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

Energía Sierra Juárez

In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold, as discussed in Note 3 above. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax). Upon deconsolidation, our equity method investment in Energía Sierra Juárez was measured at fair value, which resulted in a $7 million after-tax gain attributable to a remeasurement of the retained investment to fair value. The fair value measurement was based on the cash sales price of $26 million paid by InterGen N.V., a nonrelated party and market participant. Use of this market participant input as the indicator of fair value is a Level 2 measurement in the fair value hierarchy.

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
			Estimated		Fair
			Fair		Value	% of Fair Value		Range of
			Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Energía Sierra
Juárez		$	26(1)	Market approach	Level 2	100%	Equity sale offer price	100%
(1)	At measurement date of July 16, 2014.

NOTE 9. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

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

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

SONGS Outage and Retirement

Background

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

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

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

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

SONGS OII

In November 2012, in response to the outage, the CPUC issued the SONGS OII, pursuant to California Public Utilities’ Code Section 455.5, which applies to cost recovery issues resulting from long-term outages of operating assets. The SONGS OII consolidated most SONGS outage-related issues into a single proceeding. The SONGS OII, among other things, designated all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 as subject to refund to customers, pending the outcome of all phases of the proceeding. The SONGS OII proceeding is also intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA). We provide additional information on the SONGS OII in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Entry Into Settlement Agreement

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

On September 23, 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which incorporates the terms of a Settlement Amendment and reflects changes to adopt all the modifications and clarifications requested in the ruling issued on September 5, 2014. On October 9, 2014, the CPUC issued a proposed decision (SONGS PD) approving the Amended Settlement Agreement. We anticipate a final decision by the CPUC by the end of 2014.

If the SONGS PD is ultimately approved by the CPUC, the Amended Settlement Agreement will constitute a complete and final resolution of the SONGS OII and related CPUC proceedings regarding the SGRP at SONGS and the related outage and subsequent shutdown of SONGS. The Amended Settlement Agreement does not affect on-going or future proceedings before the NRC, or litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries as described below) or proceedings addressing decommissioning activities and costs.

The Settling Parties have agreed to exercise their best efforts to obtain CPUC approval. However, the Amended Settlement Agreement is subject to termination by any of the Settling Parties if CPUC approval has not been issued before December 23, 2014, and there is no assurance that one or more of the Settling Parties won’t do so.

The following is a summary of the Amended Settlement Agreement as it relates to SDG&E.

Disallowances, Refunds and Rate Recoveries

If the Amended Settlement Agreement is approved as proposed in the SONGS PD, SDG&E will

§	remove from rate base, as of February 1, 2012, its investment in the SGRP and refund to its customers the amount collected for its investment in and any return on its investment in the SGRP since such date. As of February 1, 2012, SDG&E’s net book value in the SGRP was approximately $160 million;

§	be authorized to recover in rates its remaining investment in SONGS, including base plant and construction work in progress (CWIP), 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 proceeding then in effect (collectively, SONGS rate of return or SONGS ROR).

This results in a SONGS ROR of 2.75 percent for the period from February 1, 2012 through December 31, 2012 and 2.35 percent for the period from January 1, 2013 through December 31, 2014. The SONGS ROR for future periods will fluctuate based on SDG&E’s authorized weighted average returns on debt and preferred stock in effect for those future periods;

§	be authorized to recover in rates its recorded 2012 and 2013 operations and maintenance expenses; in addition, SDG&E will be authorized to recover in rates the recorded costs for the 2012 refueling outage of Unit 2, subject to customary prudency review;

§	be required to file an application in 2015 to recover in rates its 2014 recorded operation and maintenance expenses and non-operating operations and maintenance expenses;

§	be authorized to recover in rates its remaining investment in materials and supplies over a ten-year period commencing February 1, 2012, together with a return on investment at the SONGS ROR;

§	be authorized to recover in rates its remaining investment in nuclear fuel inventory and any costs incurred, or to be incurred, associated with nuclear fuel supply contracts over a ten-year period, together with a return equal to SDG&E’s commercial paper borrowing rate;

be authorized to recover in rates through its fuel and purchased power balancing account (ERRA), subject to the normal CPUC compliance reviews, all costs incurred to purchase power in the market to replace the power that would have been generated at SONGS if not for the outage and shutdown of SONGS, and to recover by December 31, 2015 any SONGS-related ERRA undercollections. SDG&E’s replacement power purchase costs through June 6, 2013 (the date of SONGS’ retirement) were approximately $165 million, using the methodology followed in the SONGS OII; and

have a five-year funding commitment of $1 million per year to the University of California (UC) Energy Institute (or other existing UC entity engaged in energy technology development) to create a Research Development and Demonstration program, whose goal would be to deploy new technologies, methodologies, and /or design modifications to reduce greenhouse gas (GHG) emissions, particularly at current and future generating plants in California. This term was a modification suggested by the CPUC.

Potential Third Party Recoveries

The Amended Settlement Agreement also addresses how potential recoveries from third parties will be allocated between ratepayers and SDG&E, as we describe below.

As we discuss in more detail in Note 11, SDG&E and the other owners of SONGS carry accidental property damage and accidental outage insurance issued by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company. Edison, on behalf of itself and the other minority owners in SONGS (including SDG&E), has placed NEIL on notice of claims under both policies. Under the Amended Settlement Agreement, recoveries from NEIL, if any, will first be applied to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SDG&E’s share of recoveries from NEIL attributable to the NEIL accidental outage policy exceeds such costs, recoveries will be allocated 95 percent to ratepayers and 5 percent to SDG&E. To the extent SDG&E’s share of recoveries from other NEIL policies (such as the accidental property damage policy) exceeds such costs, recoveries will be allocated 82.5 percent to ratepayers and 17.5 percent to SDG&E.

As we discuss in more detail in Note 11, SDG&E has filed a lawsuit against MHI, which designed and provided the steam generators that failed. This proceeding was stayed in favor of an arbitration proceeding instituted by Edison. Under the Amended Settlement Agreement, recoveries from MHI, if any, will first be applied to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SDG&E’s share of recoveries from MHI exceeds such costs, they will be allocated 50 percent to SDG&E and 50 percent to ratepayers.

The Amended Settlement Agreement provides for the resolution of the claims with NEIL and the dispute with MHI without requiring CPUC approval, but requires that Edison and SDG&E:

§	use their best efforts to inform the CPUC of any settlements or resolutions of the issues to the extent possible without compromising any aspect of such settlements or resolutions, and

§	allow the CPUC to review documentation of final resolution of third-party litigation and litigation costs to ensure that the ratepayer refund calculations are accurately calculated and that the litigation costs are not exorbitant in relation to the recovery obtained.

There is no assurance that there will be any recoveries from NEIL or MHI or that if there are recoveries, that they will exceed the costs incurred to pursue them. Were there to be recoveries, SDG&E cannot provide any assurance as to when they would be received or the amount of any such recoveries. SDG&E currently expects that NEIL will make a coverage determination regarding the accidental outage policy in the first quarter of 2015.

The Amended Settlement Agreement also provides SDG&E with an incentive in the event proceeds are secured from the sale of materials and supplies and/or nuclear fuel, as well as in the event that nuclear fuel investments are reduced by contract cancellations. This incentive allows SDG&E to retain 5 percent of its proportionate share of any sales proceeds and to recover 5 percent of its proportionate share of the excess of cancelled contract obligations over cancellation costs. The balance of the sale proceeds and cancellation benefits would be credited to ratepayers.

Accounting and Financial Impacts

As a result of the execution of the Amended Settlement Agreement by the Settling Parties and the issuance of the SONGS PD by the CPUC, SDG&E has concluded that the probable outcome of the SONGS OII is the approval and implementation of the Amended Settlement Agreement, although such outcome is dependent on final approval by the CPUC.

As disclosed in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report, SDG&E reported a pretax loss from plant closure of $200 million ($119 million after-tax) in the second quarter of 2013 as a result of its initial assessment of the financial impact of the outcome of the SONGS OII proceeding. As a result of entering into the Settlement Agreement in the first quarter of 2014, SDG&E recorded a $13 million reduction to the pretax loss from plant closure, but a $9 million increase in the after-tax loss from plant closure. The after-tax loss includes a $17 million charge to reduce certain tax regulatory assets which may no longer be recoverable in rates pursuant to the Settlement Agreement. After adjustment for the Amended Settlement Agreement, SDG&E’s total loss from plant closure, including amounts previously recorded in 2013, is $187 million pretax ($128 million after-tax). A regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is recorded on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E in Other Regulatory Assets (long-term). The amount of this regulatory asset is $192 million as of September 30, 2014. The impact of the modifications and clarifications in the Amended Settlement Agreement on the regulatory asset was recorded in the third quarter of 2014 and was not material.

Assuming the Amended Settlement Agreement is approved, and except for the impact of the amount and timing of any potential future recoveries from third parties, which SDG&E cannot estimate at this time, SDG&E does not expect that implementation of the Amended Settlement Agreement will have a material adverse impact on its future results of operations or financial condition.

Procedure

Under the Amended Settlement Agreement, the Settling Parties are required to use their best efforts to obtain CPUC approval. In April 2014, the Settling Parties filed a Motion requesting the CPUC to:

§	approve the Settlement Agreement without change;

§	find the Settlement Agreement reasonable;

§	withdraw the November 19, 2013 Proposed Decision on Phase 1 and Phase 1A issues in the SONGS OII; and

§	expedite consideration of the Settlement Agreement in order to provide its benefits to ratepayers as soon as possible.

Subject to the right of any settling party to terminate the Amended Settlement Agreement if it is not approved by the CPUC by December 23, 2014, the Settling Parties are further bound to:

§	support and mutually defend the Amended Settlement Agreement in its entirety;

§	oppose any modifications proposed by any non-settling party to the SONGS OII unless all Settling Parties agree; and

§	cooperate reasonably on all submissions necessary to achieve CPUC approval.

The Settling Parties further agree to review any CPUC orders regarding the Amended Settlement Agreement to determine if the CPUC has changed or modified it, deleted a term or imposed a new term. If any Settling Party is unwilling to accept any such change, modification, deletion or addition of a new term, then the Settling Parties will negotiate in good faith to seek a resolution acceptable to all Settling Parties. If they are unable to resolve the matter to the satisfaction of all Settling Parties, or to obtain prompt CPUC approval of an agreed upon resolution, then any Settling Party can terminate the Amended Settlement Agreement upon prompt notice.

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. CPUC rules do not provide for any fixed time period for the CPUC to act on the SONGS PD.

Unless and until the CPUC approves the Amended Settlement Agreement as proposed in the SONGS PD, there can be no assurance that the SONGS OII proceeding will provide for recoveries as currently estimated by SDG&E in accordance with the Amended Settlement Agreement, including the recovery of costs recorded as a regulatory asset, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement. Therefore, the regulatory asset of $192 million in Other Regulatory Assets (long-term) on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E at September 30, 2014 related to the SONGS plant closure could be subject to further change based upon future developments and the application of SDG&E’s judgment to those events.

NRC Proceedings

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

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

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

Nuclear Decommissioning and Funding

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by the regulations of various governmental and other agencies, including but not limited to, those of the NRC, the U.S. Department of the Navy (the land owner) and the CPUC. The NRC regulations generally categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations (provided by Edison to the NRC on June 12, 2013) and notice of permanent removal of fuel from the reactor vessels (provided by Edison on June 28 and July 22, 2013 for Units 3 and 2, respectively). Within two years after the cessation of operations, the licensee (Edison) must submit a post-shutdown decommissioning activities report (PSDAR), an irradiated fuel management plan (IFMP) and a site-specific decommissioning cost estimate (DCE). Edison submitted each of the PSDAR, the IFMP and the DCE to the NRC in September 2014.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. At September 30, 2014, the fair value of SDG&E’s NDT assets was $1.1 billion. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs. In February 2014, SDG&E filed a request with the CPUC for such authorization for costs incurred in 2013. Until CPUC approval to access the NDT to pay for such costs is received, SDG&E will use working capital to pay for any SONGS Units 2 and 3 decommissioning costs incurred, and such expenditures will be reimbursed from the NDT upon that approval.

SDG&E currently anticipates a decision regarding its ability to use the monies in the NDT by the end of 2014.

SDG&E and Edison have a joint application pending with the CPUC requesting continued rate recovery to fund the NDT to ensure that the NDT has sufficient funding to pay for the estimated cost of decommissioning SONGS. SDG&E is currently authorized to recover $8 million annually to fund additional investments in the NDT. In its pending application with the CPUC, SDG&E is requesting to recover $16 million on an annual basis to fund additional investments in the NDT. We expect a decision on this application by the end of 2014.

On September 5, 2014, the NRC approved Edison’s February 2014 request (made on behalf of SONGS co-owners) for exemptions from various federal decommissioning requirements. The approved exemptions provide NRC approval for SONGS co-owners to use NDT funds for all types of decommissioning activity costs, including fuel management and site restoration costs. As noted above, however, CPUC approval to access the NDT to pay for such costs is still required for the SONGS co-owners to use NDT funds.

Edison’s submission of the PSDAR and the DCE in September 2014 allows the SONGS co-owners to commence major decommissioning activities, and submission of the DCE provides the NRC authorization for the SONGS co-owners to access the majority of their decommissioning trust funds, both starting 90 days after the NRC receives the documents, unless the NRC staff raises objections. No objections have been received to date.

Nuclear Decommissioning Trusts

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

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

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
			Cost		Gains		Losses		Value
At September 30, 2014:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	99	$	4	$	―	$	103
Municipal bonds(2)			114		7		―		121
Other securities(3)			198		6		(4)		200
Total debt securities			411		17		(4)		424
Equity securities			212		427		(2)		637
Cash and cash equivalents			26		―		―		26
Total		$	649	$	444	$	(6)	$	1,087
At December 31, 2013:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	116	$	3	$	(2)	$	117
Municipal bonds			110		2		(1)		111
Other securities			155		3		(5)		153
Total debt securities			381		8		(8)		381
Equity securities			207		409		(2)		614
Cash and cash equivalents			39		―		―		39
Total		$	627	$	417	$	(10)	$	1,034
(1)	Maturity dates are 2016-2060
(2)	Maturity dates are 2014-2062
(3)	Maturity dates are 2014-2096

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

SALES OF SECURITIES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Proceeds from sales(1)	$	148	$	181	$	498	$	507
Gross realized gains		5		2		9		13
Gross realized losses		(3)		(8)		(8)		(15)
(1) Excludes securities that are held to maturity.

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

We provide additional information about SONGS in Note 11.

NOTE 10. CALIFORNIA UTILITIES' REGULATORY MATTERS

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

JOINT MATTERS

CPUC General Rate Case (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In May 2013, the CPUC approved a final decision (Final GRC Decision) in the California Utilities’ 2012 GRC. The Final GRC Decision was effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts included an incremental earnings impact of $52 million and $25 million related to 2012 and $17 million and $12 million related to the first quarter of 2013.

The amount of revenue associated with the retroactive period is being recovered in SDG&E’s rates over a 28-month period beginning in September 2013, and in SoCalGas’ rates over a 31-month period beginning in June 2013. At September 30, 2014, SDG&E reported on its Condensed Consolidated Balance Sheet $203 million as a regulatory asset, with $41 million classified as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered by SDG&E in rates through December 2015. At September 30, 2014, SoCalGas reported on its Condensed Consolidated Balance Sheet a regulatory asset of $65 million, with $13 million as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015.

The California Utilities filed their Notices of Intent (NOI) for the 2016 General Rate Case (2016 GRC) in July 2014. These NOIs included preliminary applications that propose revenue requirement increases of $168 million and $290 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements. As included in the NOI, these proposed increases in revenue requirements would result in a 0.9 percent increase in SDG&E’s system average electric rate and 0.5 percent and 5.5 percent increases in SDG&E’s and SoCalGas’ system average gas rates, respectively. In September 2014, the CPUC staff completed its review of the NOIs. The CPUC staff found them in compliance with the Commission’s rate case plan and recommended that the NOIs be accepted. Accordingly, SDG&E and SoCalGas expect to file their official applications in the fourth quarter of 2014, including a request for a final decision on each of the applications in late 2015, with changes in rates to become effective on January 1, 2016.

We provide additional information regarding the 2012 GRC in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Pipeline Operations Safety Assessments

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

In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011.

In April 2012, the CPUC transferred the PSEP to the Triennial Cost Allocation Proceeding (TCAP) and authorized SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP.

Also in April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill (SB) 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. The CPUC’s Safety and Enforcement Division will select the independent auditors and will oversee the audits. A schedule for the audits has not been established. In December 2012, the CPUC issued a final decision accepting the utilities’ pipeline safety plans filed pursuant to SB 705.

In June 2014, the CPUC issued a final decision in the TCAP proceeding addressing SDG&E’s and SoCalGas’ PSEP. Specifically, the decision:

§	approved the utilities’ model for implementing PSEP;

approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which are recorded in the regulatory accounts authorized by the CPUC as noted above;

§	approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and

§	established the criteria to determine the amounts that would not be eligible for cost recovery, including:

□	certain costs incurred or to be incurred searching for pipeline test records,

□	the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and

□	any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million for costs incurred in prior periods for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of September 30, 2014, SDG&E and SoCalGas have recorded PSEP implementation costs of $0.2 million and $47 million, respectively, in the CPUC-authorized regulatory account. In October 2014, SDG&E and SoCalGas filed a request with the CPUC for authority to recover from customers PSEP costs as incurred prior to a reasonableness review by the CPUC.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In early August 2014, the California Utilities filed their response to the application for rehearing objecting to the assertions by the ORA and TURN. The CPUC is not obligated to act on the application for rehearing by a certain date. The California Utilities are continuing to implement PSEP in accordance with the June 2014 decision.

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

Southern Gas System Reliability Project

In December 2013, SoCalGas and SDG&E filed a joint application with the CPUC seeking authority to recover the full cost of the Southern Gas System Reliability Project. Also known as the North-South Gas Project, the project will enhance reliability on the southern portions of the utilities’ integrated gas transmission system (Southern System). We estimate the cost of the project to be between $800 million to $850 million. Based on the CPUC schedule that provides for a draft decision in mid-2015, we anticipate a final CPUC decision by the end of 2015 and the project to be in service, subject to environmental permitting, by the end of 2019. We provide additional information about the project in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Utility Incentive Mechanisms

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

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

Natural Gas Procurement

In August 2014, the CPUC issued a final decision approving SoCalGas’ application for a gas cost incentive mechanism (GCIM) award of $5.8 million for natural gas procured for its core customers during the 12-month period ending March 31, 2013. In June 2014, SoCalGas filed an application with the CPUC for approval of a $13.7 million GCIM award for natural gas procured for its core customers during the 12-month period ending March 31, 2014. SoCalGas expects a final CPUC decision in the first half of 2015.

Energy Efficiency

In June 2014, SoCalGas and SDG&E filed advice letters requesting awards of $5.8 million and $7.6 million, respectively, based on their performance on energy efficiency programs during program years 2012 and 2013. Of these amounts, SoCalGas and SDG&E are seeking initial 2013 program awards of $1.5 million and $2.5 million, respectively, and asking that any necessary adjustment to the 2013 awards be made in 2015 after completion of the CPUC’s audit. We expect a resolution by the end of the second quarter of 2015.

SDG&E MATTERS

SONGS

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

Power Procurement and Resource Planning

Cleveland National Forest Transmission Projects

SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission replacement projects in and around the Cleveland National Forest (CNF). The proposed projects will replace and fire-harden five existing transmission lines at an estimated cost of between $400 million and $450 million. As directed by the CPUC, SDG&E filed an amended application in June 2013 to provide notice of certain alternatives proposed by the U.S. Forest Service (USFS) in connection with SDG&E’s request for a Master Special Use Permit (MSUP). USFS approval of the MSUP will establish land rights and conditions for SDG&E’s continued operation and maintenance of facilities located within the CNF. CPUC approval is not required for the MSUP, even though construction of the projects is subject to review by both the USFS and CPUC. A draft environmental report (EIR/EIS), developed jointly by the CPUC and USFS, was issued in September 2014 and a final EIR/EIS is expected in early 2015. SDG&E currently expects a CPUC decision approving the transmission projects in the first half of 2015 and then expects the various phases of this project to be placed in service starting in 2016 and continuing through the end of the project in 2019.

Sycamore-Peñasquitos Transmission Project

In March 2014, the CAISO selected SDG&E, as a result of a competitive bid process, to construct the Sycamore-Peñasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Peñasquitos substations. In July 2014, the CPUC notified SDG&E that the application requesting a Certificate of Public Convenience and Necessity (CPCN) to construct the line, which was filed with the CPUC in April 2014, is complete. The estimated $120 million to $150 million project was identified by the CAISO and a state task force as necessary to ensure grid reliability given the closure of SONGS. The project will also serve to strengthen renewable energy infrastructure in the region. SDG&E expects a CPUC decision approving the project in the first half of 2016, with the line expected to be in service in mid-2017.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 for a CPCN to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E’s electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a draft environmental report to be issued by the end of 2014 and a final CPUC decision approving the estimated $400 million to $500 million project in 2015. SDG&E obtained approval for the project from the CAISO in May 2011. As the project is planned in phases, SDG&E currently expects the entire project to be in service in 2019.

South Bay Substation and Relocation Project

SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation, the Bay Boulevard substation, to replace the aging and obsolete South Bay substation to accommodate regional energy demands. The existing substation will be demolished when the Bay Boulevard substation has been constructed, energized and all transmission lines have been transferred. In October 2013, the CPUC approved SDG&E’s permit to construct the Bay Boulevard substation at SDG&E’s proposed site. The project, estimated at $145 million to $175 million, will replace the existing 138/69-kV substation with the new 230/69/12-kV Bay Boulevard substation. In March 2014, the California Coastal Commission approved the project, subject to certain additional environmental enhancements. SDG&E is in the process of obtaining the remaining approvals and permits required to begin construction. SDG&E currently expects the project to be in service in 2017.

Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters

In February 2013, SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC to set the rate making methodology and rate of return for SDG&E’s FERC-regulated electric transmission operations and assets for the period beginning September 1, 2013. The filing proposed a FERC ROE of 11.3 percent and requested: 1) rates to be determined by a base period of historical costs and a forecast of capital investments and 2) a true-up period similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. In June and July 2013, the FERC issued orders accepting the filing, subject to refund, and established settlement and hearing procedures, with rates being effective as of 2013.

On January 31, 2014, SDG&E filed an uncontested multi-party settlement at the FERC regarding the TO4 filing. The settlement, approved by FERC in May 2014, will be in effect through December 31, 2018, is subject to a one-time right of termination by any party, and established a 10.05 percent ROE. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt to equity ratio will be set annually based on the actual ratio at the end of each year.

Energy Resource Recovery Account (ERRA)

The ERRA is the regulatory balancing account that SDG&E uses to recover the electric fuel and purchased power costs it incurs to provide energy to its bundled service customers. SDG&E files an application with the CPUC each year to establish the ERRA revenue requirement needed for the following calendar year. Additionally, to the extent the ERRA balance exceeds a certain tolerance or “ERRA Trigger”, SDG&E must file an application to adjust its rates upward or downward, as applicable, to address the under- or over-collected ERRA balance, respectively. In February 2014, the CPUC issued a decision granting SDG&E authority to increase rates to recover an ERRA Trigger revenue requirement of $221 million, which rate increase was effective on April 1, 2014 and will continue through December 31, 2015. In May 2014, the CPUC issued a final decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $242 million compared to the 2013 ERRA revenue requirement of $988 million. SDG&E implemented the increased revenue requirement on August 1, 2014.

Excess Wildfire Claims Cost Recovery

In August 2009, SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC proposing a new framework and mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed framework for the utilities but allowed SDG&E to maintain its authorized memorandum account so that SDG&E may file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account at a later time, subject to reasonableness review.

In February 2014, the Presiding Judge assigned by the FERC to SDG&E’s annual Electric Transmission Formula Rate filing (TO3 Cycle 6) issued an Initial Decision and an Order on Summary Judgment which authorizes SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations resulting from settlement activities for 2007 wildfire claims for that rate cycle period. This result will stand, subject to any successful appeal by the CPUC. In connection with this proceeding, the CPUC filed an appeal in the Ninth Circuit Court of Appeal of an earlier decision by the FERC denying the CPUC’s request to postpone the FERC proceeding pending CPUC action on cost recovery of the excess wildfire costs. The FERC has sought dismissal of the CPUC’s appeal on procedural grounds. The Court of Appeal has not yet ruled on the merits.

SDG&E intends to pursue recovery of the costs it has incurred for settlement activities associated with the 2007 wildfire claims allocated to SDG&E’s CPUC-regulated operations in a future application with the CPUC. SDG&E will continue to assess the potential for recovery of these costs in rates. We discuss the impact should SDG&E conclude that recovery in rates is no longer probable in “Legal Proceedings — SDG&E — 2007 Wildfire Litigation” in Note 11. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

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

SOCALGAS MATTER

Advanced Metering Infrastructure

In November 2011, the ORA (formerly the Division of Ratepayer Advocates or DRA) and TURN filed a joint petition requesting that the CPUC reconsider its prior approval of SoCalGas’ advanced metering infrastructure (AMI) project and stay AMI deployment while the CPUC considered the request. In June 2014, the CPUC denied the ORA/TURN petition, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision approving the project.

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

At September 30, 2014, Sempra Energy’s accrued liabilities for material legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $144 million. At September 30, 2014, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $127 million and $11 million, respectively.

SDG&E

2007 Wildfire Litigation

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

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

Numerous parties have sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. They assert various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved almost all of these lawsuits. In February 2014, the Court set a February 2015 trial date for a trial to be comprised of four of the remaining cases involving plaintiffs who claim damages resulting from the Witch fire. In June 2014, the Court continued the trial date for the Witch fire cases to June 2015.

SDG&E filed cross-complaints against Cox and three contractors, seeking indemnification for any liability that SDG&E might incur. SDG&E settled its claims against Cox and the three contractors for an aggregate of $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.

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

The wildfire litigation also includes claims of non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has now settled almost all of these claims of the approximately 6,500 plaintiffs for a total of approximately $1.25 billion. Substantially all of the remaining plaintiffs have submitted settlement demands and damage estimates, which total approximately $200 million. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.

SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of its reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, although such recovery will require future regulatory approval, at September 30, 2014, Sempra Energy and SDG&E have recorded assets of $371 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $357 million related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries in rates and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at September 30, 2014, the resulting after-tax charge against earnings would have been up to approximately $210 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims.

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

Since 2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. Most of the impact of this liability at September 30, 2014 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. The impact of the change in these reserves on SDG&E’s and Sempra Energy’s after-tax earnings for the three months and nine months ended September 30, 2014 and 2013 were not material. Additionally, through September 30, 2014, SDG&E has expended $426 million in excess of amounts covered by insurance and amounts recovered from third parties to pay for the settlement of wildfire claims and related costs.

We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 10 and discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sunrise Powerlink Electric Transmission Line

The Sunrise Powerlink is a 117-mile, 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012. The Sunrise Powerlink project was approved by the CPUC in December 2008, the Bureau of Land Management in January 2009, and the United States Forest Service in July 2010. Numerous administrative appeals and legal challenges have been resolved in favor of the project. Two legal challenges remain pending.

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

A claim for additional compensation has been submitted by one of SDG&E’s contractors on the Sunrise Powerlink project. The contractor was awarded the transmission line overhead and underground construction contract on a fixed-fee basis of $456 million after agreed-upon amendments. The contractor has asserted that it is owed additional compensation above the fixed-fee portion of the contract. In May 2013, the contractor filed claims totaling $180 million, including one in San Diego County for the sum of $99 million and the other in Imperial County for the sum of $81 million, seeking foreclosure of previously filed mechanics liens. In October 2013, the contractor served a Demand for Arbitration pursuant to contractual provisions. SDG&E has answered the demand and filed a counter claim against the contractor. The arbitration panel has set a July 2015 arbitration hearing date.

September 2011 Power Outage

In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diego against Arizona Public Service Company, Pinnacle West Capital Corporation and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E’s motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West Capital Corporation from the lawsuit. In September 2013, the court granted SDG&E’s motion for summary judgment and dismissed the lawsuit. In October 2013, the plaintiffs appealed the court’s dismissal of their action.

The FERC and North American Electric Reliability Corporation (NERC) Staff conducted a joint inquiry to determine the cause of the power failure and issued a report in May 2012 regarding their findings. Following that report, Staff from FERC’s Office of Enforcement (FERC Enforcement Staff) investigated potential violations of FERC’s Reliability Standards associated with the outage. In January 2014, FERC Enforcement Staff issued a Staff Notice of Alleged Violations, in which FERC Enforcement Staff alleged violations of various Reliability Standards by several entities. FERC Enforcement Staff did not allege or find any violations by SDG&E.

Smart Meters Patent Infringement Lawsuit

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

Lawsuit Against Mitsubishi Heavy Industries, Ltd.

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

Investment in Wind Farm

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

On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer is disputing SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims. On July 18, 2014, the Montana Supreme Court determined that Montana courts did not have jurisdiction over the parties’ dispute due to their contractual agreement to resolve any disputes in California, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial for March 6, 2015.

SoCalGas

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

Sempra Mexico

Permit Challenges and Property Disputes

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

The claimant also filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría de la Reforma Agraria (now the Secretaría de Desarrollo Agrario, Territorial y Urbano, or SEDATU) in 2006 to issue a title to him for the disputed property. In November 2013, the Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico have challenged the rulings. Sempra Mexico expects additional proceedings regarding the claims, although such proceedings are not related to the permit challenges referenced above. The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions. Sempra Energy has disputed the claims and allegations in this lawsuit.

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

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

Sempra Natural Gas

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

Other Litigation

As described in Note 4, Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. The Royal Bank of Scotland plc (RBS), our partner in the joint venture, was notified by the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigating value-added tax (VAT) refund claims made by various businesses in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactions by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued a protective assessment of £86 million for the VAT paid in connection with these transactions. In October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tier Tribunal. As a condition of the appeal, RBS was required to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax.

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

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

CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first nine months of 2014 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

SoCalGas’ natural gas purchase and pipeline capacity commitments have decreased by $110 million since December 31, 2013, primarily due to fulfillment of payment obligations and changes to forecasted gas prices in the first nine months of 2014. Net future payments are expected to decrease by $140 million in 2014, and increase by $30 million in 2015 compared to December 31, 2013.

Sempra Natural Gas’ natural gas purchase and transportation commitments have increased by $567 million since December 31, 2013, primarily due to new natural gas contracts in the first nine months of 2014. These contracts replace an agreement that expired in the third quarter of 2014 and will be used to support Sempra Mexico’s obligation to sell natural gas to the Mexican Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) and fuel Sempra Mexico’s Termoeléctrica de Mexicali natural gas-fired power plant. Net future payments are expected to decrease by $57 million in 2014, and increase by $174 million in 2015, $159 million in 2016, $162 million in 2017 and $129 million in 2018 compared to December 31, 2013.

LNG Purchase Agreement

At September 30, 2014, Sempra Natural Gas has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The agreement is priced using a predetermined formula based on natural gas market indices. Although this contract specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas.

Sempra Natural Gas’ commitment under the LNG purchase agreement, reflecting changes in forward prices since December 31, 2013 and actual transactions for the first nine months of 2014, are expected to decrease by $624 million in 2014, $11 million in 2015, and to increase by $10 million in 2016, $30 million in 2017, $36 million in 2018 and $345 million thereafter compared to December 31, 2013. These amounts are based on forward prices of the index applicable to the contract from 2014 to 2023 and an estimated one percent escalation per year beyond 2023. The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreement. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amounts possible.

Purchased-Power Contracts

SDG&E’s commitments under purchased-power contract commitments have increased by $1.1 billion since December 31, 2013. The increase is primarily due to new contracts associated with renewable energy development projects. Net future payments are therefore expected to decrease by $2 million in 2014, $46 million in 2015, and $1 million in 2016, and increase by $24 million in 2017, $54 million in 2018 and $1.1 billion thereafter compared to December 31, 2013.

Operating Leases

In the first nine months of 2014, the change to operating lease commitments at Sempra Renewables was a decrease of $83 million, primarily from the deconsolidation of the Copper Mountain Solar 3 project, as we discuss in Note 3. Net future payments are expected to decrease by $3 million in 2014, $2 million each year in 2015 through 2018 and $72 million thereafter.

Power Purchase Agreements

SDG&E has a 25-year power purchase agreement with a peaker plant facility that became operational in 2014. The power purchase agreement is accounted for as a capital lease. The capital lease obligation was valued at $60 million. Net changes to future minimum lease payments under all power purchase agreements are a decrease of $16 million in 2014, and increases of $7 million each year in 2015 through 2018 and $155 million thereafter compared to December 31, 2013.

Construction and Development Projects

In the first nine months of 2014, significant net increases to contractual commitments at SDG&E were $161 million, primarily for Palomar Energy Center, South Bay Substation project and the PSEP. Net future payments under these contractual commitments are expected to increase by $20 million in 2014, $116 million in 2015, $12 million in 2016, $9 million in 2017, and $6 million in 2018, and decrease by $2 million thereafter compared to December 31, 2013.

In the first nine months of 2014, significant net increases to contractual commitments at SoCalGas were $119 million, primarily for the Aliso Canyon Turbine Replacement Project and the PSEP. Net future payments under these contractual commitments are expected to increase by $71 million in 2014, $65 million in 2015, and $1 million in 2016, and decrease by $18 million in 2017 compared to December 31, 2013.

In the first nine months of 2014, significant net decreases to contractual commitments at Sempra Mexico were $115 million, primarily from the deconsolidation of the Energía Sierra Juárez project. Net future payments under these contractual commitments are expected to decrease by $81 million in 2014, $33 million in 2015 and $1 million thereafter.

In the first nine months of 2014, the change to contractual commitments at Sempra Renewables was a decrease of $544 million, primarily from the deconsolidation of the Copper Mountain Solar 3 project. Net future payments under these contractual commitments are expected to decrease by $504 million in 2014 and $40 million in 2015.

Cameron LNG Liquefaction Export Facility Project

Construction and Development Project

In March 2014, Cameron LNG entered into an engineering, procurement and construction contract with a joint venture consisting of CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation, to construct the Cameron liquefaction project in Hackberry, Louisiana. The scope of work under this contract includes the engineering, procurement, construction, commissioning and startup of three liquefaction trains with an aggregate nameplate capacity of approximately 13.5 million tonnes per year of LNG and related infrastructure and facilities necessary for the integration of the liquefaction trains with the existing LNG receipt terminal. The construction contract is a lump-sum, date certain turnkey agreement, with a cost of approximately $6 billion as of the execution date. The lump-sum price may be adjusted based on the occurrence of well-defined events, such as change orders issued by Cameron LNG, and the occurrence of other events where an adjustment to the lump-sum price is customary for lump-sum, date certain turnkey engineering, procurement and construction agreements.

As of September 30, 2014, Cameron LNG had issued three limited notices to proceed under the contract, authorizing up to $374.7 million of expenditures. After completing the formation of the Cameron LNG joint venture on October 1, 2014 as we discuss in Note 13, on October 9, 2014, the Cameron LNG joint venture issued the full notice to proceed under the contract to construct the Cameron liquefaction project. This allowed the contractor to proceed with all items of the work under the contract. The issuance of the full notice to proceed supersedes the three previously issued limited notices to proceed.

Guarantees

On August 6, 2014, Cameron LNG entered into finance documents for senior secured financing for the Cameron liquefaction project. We discuss the financing and related Sempra Energy guarantees in Note 13.

Subsequent Event

As we discuss in Note 13, on October 1, 2014, Sempra Natural Gas and its project partners completed the formation of the Cameron LNG joint venture for their investment in the development, construction and operation of the natural gas liquefaction export facility. As of that date, Sempra Natural Gas will account for its investment in the joint venture under the equity method. We discuss the joint venture formation in Note 13.

NUCLEAR INSURANCE

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

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $9.7 million of retrospective premiums based on overall member claims. Edison, on behalf of itself and the minority owners of SONGS (including SDG&E), has placed NEIL on notice of claims under both the property damage and outage insurance policies as a result of SONGS’ Units 2 and 3 outages in early 2012 and the resultant plant closure in June 2013.

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.

DEPARTMENT OF ENERGY (DOE) NUCLEAR FUEL DISPOSAL

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

We provide additional information about SONGS in Note 9.

NOTE 12. SEGMENT INFORMATION

We have six separately managed reportable segments, as follows:

1.	SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.

2.	SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

3.	Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru. In June 2013, we sold our interests in two Argentine utilities, which we discuss further in Note 4 above.

Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane and ethane systems, a natural gas distribution utility, electric generation facilities (including wind), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.

5.	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation asset, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States.

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

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

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

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

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,								Nine months ended September 30,
	2014				2013				2014				2013
REVENUES
SDG&E	$	1,233	44	%	$	1,063	42	%	$	3,283	40	%	$	3,066	39	%
SoCalGas		855	30			807	32			2,857	35			2,694	34
Sempra South American Utilities		379	14			364	14			1,147	14			1,119	14
Sempra Mexico		234	8			188	7			621	7			519	7
Sempra Renewables		10	―			25	1			25	―			76	1
Sempra Natural Gas		252	9			212	8			748	9			683	9
Adjustments and eliminations		1	―			―	―			(1)	―			(2)	―
Intersegment revenues(1)		(149)	(5)			(108)	(4)			(392)	(5)			(303)	(4)
Total	$	2,815	100	%	$	2,551	100	%	$	8,288	100	%	$	7,852	100	%
INTEREST EXPENSE
SDG&E	$	51			$	50			$	152			$	147
SoCalGas		17				17				50				52
Sempra South American Utilities		7				8				24				20
Sempra Mexico		5				―				13				5
Sempra Renewables		2				5				3				22
Sempra Natural Gas		25				34				90				80
All other		63				60				178				182
Intercompany eliminations		(26)				(37)				(92)				(95)
Total	$	144			$	137			$	418			$	413
INTEREST INCOME
SDG&E	$	―			$	―			$	―			$	1
Sempra South American Utilities		4				3				10				11
Sempra Mexico		1				―				2				1
Sempra Renewables		―				7				―				14
Sempra Natural Gas		24				26				87				57
All other		(1)				2				―				1
Intercompany eliminations		(22)				(33)				(84)				(70)
Total	$	6			$	5			$	15			$	15
DEPRECIATION AND AMORTIZATION
SDG&E	$	134	46	%	$	126	44	%	$	395	46	%	$	367	44	%
SoCalGas		109	37			100	35			321	37			280	34
Sempra South American Utilities		14	5			14	5			41	5			44	5
Sempra Mexico		16	6			16	5			47	5			47	6
Sempra Renewables		1	―			5	2			4	―			20	3
Sempra Natural Gas		17	6			20	7			50	6			60	7
All other		1	―			5	2			8	1			10	1
Total	$	292	100	%	$	286	100	%	$	866	100	%	$	828	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	65			$	84			$	217			$	147
SoCalGas		44				38				110				107
Sempra South American Utilities		26				16				59				50
Sempra Mexico		13				16				37				44
Sempra Renewables		(16)				9				(35)				(8)
Sempra Natural Gas		(31)				(4)				(22)				35
All other		(30)				(42)				(75)				(48)
Total	$	71			$	117			$	291			$	327

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2014				2013				2014				2013
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables		$	7			$	(10)			$	18			$	(12)
Sempra Natural Gas			15				13				44				33
Total		$	22			$	3			$	62			$	21
Earnings (losses) recorded net of tax:
Sempra South American Utilities		$	(2)			$	―			$	(4)			$	(14)
Sempra Mexico			9				8				26				27
Total		$	7			$	8			$	22			$	13
EARNINGS (LOSSES)
SDG&E(2)		$	157	45	%	$	129	44	%	$	379	44	%	$	285	40	%
SoCalGas(3)			98	28			102	34			256	30			266	37
Sempra South American Utilities			32	9			39	13			109	13			110	15
Sempra Mexico			63	18			39	13			139	16			96	13
Sempra Renewables			17	5			37	13			63	7			56	8
Sempra Natural Gas			26	8			(7)	(2)			39	4			55	8
All other			(45)	(13)			(43)	(15)			(121)	(14)			(149)	(21)
Total		$	348	100	%	$	296	100	%	$	864	100	%	$	719	100	%
										Nine months ended September 30,
										2014				2013
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E										$	790	34	%	$	679	38	%
SoCalGas											764	33			521	29
Sempra South American Utilities											126	5			120	7
Sempra Mexico											262	11			280	16
Sempra Renewables											174	8			119	7
Sempra Natural Gas											192	8			65	3
All other											12	1			1	―
Total										$	2,320	100	%	$	1,785	100	%
										September 30, 2014				December 31, 2013
ASSETS
SDG&E										$	15,975	41	%	$	15,377	41	%
SoCalGas											9,954	26			9,147	25
Sempra South American Utilities											3,463	9			3,531	10
Sempra Mexico											3,404	9			3,246	9
Sempra Renewables											1,379	3			1,219	3
Sempra Natural Gas											6,617	17			7,200	19
All other											1,141	3			838	2
Intersegment receivables											(2,951)	(8)			(3,314)	(9)
Total										$	38,982	100	%	$	37,244	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra South American Utilities										$	(7)			$	(3)
Sempra Mexico											427				379
Sempra Renewables											871				707
Sempra Natural Gas											342				329
All other											72				73
Total										$	1,705			$	1,485
(1)	Revenues for reportable segments include intersegment revenues of:
	$2 million, $17 million, $23 million and $107 million for the three months ended September 30, 2014; $7 million, $51 million, $68 million and $266 million for the nine months ended September 30, 2014; $3 million, $17 million, $23 million and $65 million for the three months ended September 30, 2013; and $7 million, $48 million, $68 million and $180 million for the nine months ended September 30, 2013 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends and call premium on preferred stock for 2013.
(3)	After preferred dividends.

NOTE 13. SUBSEQUENT EVENT

SEMPRA NATURAL GAS

Cameron LNG Holdings Joint Venture

On August 6, 2014, Sempra Natural Gas and its project partners, comprised of affiliates of GDF SUEZ S.A., Mitsui & Co., Ltd., and Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha), provided their respective final investment decision with respect to the investment in the development, construction and operation of the natural gas liquefaction export facility at the terminal in Hackberry, Louisiana, owned by Cameron LNG, LLC (Cameron LNG). The Cameron liquefaction project utilizes Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 billion cubic feet (Bcf) per day. The Cameron liquefaction project is comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.5 million tonnes per annum (Mtpa) of LNG, with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Commercial operation of all three trains is expected to commence in 2018, with the first year of full operations in 2019. The effective date of the Cameron LNG joint venture, Cameron LNG Holdings, LLC (Cameron LNG Holdings), among Sempra Energy and its project partners occurred on October 1, 2014 after satisfaction of various conditions, including receipt of final regulatory approval and satisfaction of conditions precedent to the first disbursement of the project financing.

In 2013, Sempra Natural Gas signed 20-year liquefaction and regasification tolling capacity agreements with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. which subscribe the full nameplate capacity of the facility. Each tolling agreement is for 4.5 Mtpa of capacity to enable 4.0 Mtpa of LNG export. Also in 2013, Sempra Natural Gas signed agreements totaling 1.45 Bcf per day of firm natural gas transportation service to Cameron LNG on the Cameron Interstate Pipeline with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.

Our equity in Cameron LNG Holdings was derived from our contribution of Cameron LNG to the joint venture at its historical carrying value. Each of the partners were issued indirect equity interests in Cameron LNG in an aggregate of 49.8 percent. Cameron LNG thereby ceased to be wholly owned or controlled by Sempra Natural Gas, which retained a 50.2 percent of Cameron LNG. As of the October 1, 2014 effective date, Sempra Natural Gas will account for its investment in Cameron LNG Holdings under the equity method. Sempra Energy did not recognize a gain or loss related to the contribution of Cameron LNG to the joint venture.

The following table summarizes the deconsolidation of the Cameron liquefaction project:

DECONSOLIDATION OF SUBSIDIARY
(Dollars in millions)
	Cameron LNG, LLC
	October 1, 2014
Cash	$	(6)
Other current assets		(11)
Property, plant and equipment, net		(1,022)
Other assets		(30)
Accounts payable and accrued expenses		93
Equity method investment upon deconsolidation	$	(976)

Joint Venture Financing

General

On August 6, 2014, Cameron LNG also 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 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 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 type with the lenders of the type participating in the Cameron LNG financing. On August 6, 2014, Sempra Energy entered into a completion agreement in favor of HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG Holdings’ creditors. Pursuant to this completion agreement, Sempra Energy has severally guaranteed 50.2 percent of Cameron LNG Holdings’ senior debt obligations under the Loan Facility Agreements, or a maximum principal amount of $3.7 billion. Completion guarantees for the remaining 49.8 percent of Cameron LNG Holdings’ senior secured financing have been provided by the other project partners. The occurrence of the effectiveness of the Cameron LNG Holdings joint venture on October 1, 2014 was a condition precedent to first disbursement of funds under the Loan Facility Agreements, and the Sempra Energy completion guarantee of 50.2 percent of the Cameron LNG Holdings financing also became effective upon effectiveness of the Cameron LNG Holdings joint venture. Sempra Energy’s completion agreement and guarantee will terminate upon financial completion of the Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. Financial completion is scheduled for the second half of 2019.

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 per annum over LIBOR following financial completion of the project. The Loan Facility Agreements require Cameron LNG 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.

Mandatory Prepayments

Cameron LNG also must make mandatory prepayments of all loans made under the Loan Facility Agreements under certain circumstances, including: upon receipt of certain insurance proceeds and expropriation compensation; upon receipt of certain performance liquidated damages under Cameron LNG’s engineering, procurement and construction contract for the liquefaction terminal; in connection with the loss of its tolling agreements or export permits that result in a reduction of Cameron LNG’s debt service coverage ratios below a specified threshold; if it becomes unlawful in any applicable jurisdiction for a lender to fund or maintain its loans; or in connection with any mandatory prepayment of senior notes outstanding (if any).

The loans under the NEXI Covered Loan Facility Agreement and the loans held by JBIC under the JBIC Loan Facility Agreement are subject to certain additional mandatory prepayments that would be triggered if the Japanese sponsors fail to maintain certain ownership interests in Cameron LNG, if Cameron LNG’s Japanese tolling customers do not hold commitments for a certain quantum of nameplate capacity at the liquefaction terminal or if the aggregate annual contracted LNG commitments by Cameron LNG’s tolling customers to Japanese LNG buyers fall below a certain minimum threshold under certain circumstances.

Events of Default

Cameron LNG’s Loan Facility Agreements and related finance documents also 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; 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 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’s financing and a potential demand on Sempra Energy’s guarantee.

Security

To support Cameron LNG’s obligations under the Loan Facility Agreements and related finance documents, Cameron LNG has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all Cameron LNG’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 by Sempra Energy and the other project partners.

The security trustee under Cameron LNG’s financing can demand that a payment be made by Sempra Energy under its guarantee 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 (taking into account cure periods) in the event of a failure by Cameron LNG 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).

Terminal Services Agreement

At September 30, 2014, Cameron LNG had a terminal services agreement with one customer that required the customer to pay capacity reservation and usage fees to use its Cameron LNG facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG’s engineering, procurement and construction contractor in October 2014, we expect this termination date to occur during the first quarter of 2017.

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

You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto contained in this Form 10-Q, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and the Notes thereto contained in our 2013 Annual Report on Form 10-K (Annual Report) and “Risk Factors” contained in our Annual Report.

OVERVIEW

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

This report includes information for the following separate registrants:

§	Sempra Energy and its consolidated entities

SDG&E

SoCalGas

References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. All references to “Sempra International” and “Sempra U.S. Gas & Power,” and to their respective principal segments, are not intended to refer to any legal entity with the same or similar name.

In the first quarter of 2013, a Sempra Energy subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), completed a private offering in the U.S. and outside of Mexico and concurrent public offering in Mexico of common stock. IEnova is a separate legal entity, formerly known as Sempra México, S.A. de C.V., comprised primarily 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. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA. We discuss the offerings and IEnova further in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Below are summary descriptions of our operating units and their reportable segments.

SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS

CALIFORNIA UTILITIES
	MARKET	SERVICE TERRITORY
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E) A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution	§ Provides electricity to 3.4 million consumers (1.4 million meters) § Provides natural gas to 3.2 million consumers (0.9 million meters)	Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS) A regulated public utility; infrastructure supports natural gas distribution, transmission and storage	§ Residential, commercial, industrial, utility electric generation and wholesale customers § Covers a population of 21.3 million (5.8 million meters)	Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International or Sempra U.S. Gas & Power operating units described below.

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

SEMPRA INTERNATIONAL
	MARKET	GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES Infrastructure supports electric transmission and distribution	§ Provides electricity to approximately 640,000 customers in Chile and 996,000 customers in Peru	§ Chile § Peru
SEMPRA MEXICO Develops, owns and operates, or holds interests in: § natural gas transmission pipelines and propane and ethane systems § a natural gas distribution utility § electric generation facilities, including wind § a terminal for the import of liquefied natural gas (LNG) § marketing operations for the purchase of LNG and the purchase and sale of natural gas	§ Natural gas § Wholesale electricity § Liquefied natural gas	§ Mexico

SEMPRA U.S. GAS & POWER
	MARKET	GEOGRAPHIC REGION
SEMPRA RENEWABLES Develops, owns, operates, or holds interests in renewable energy generation projects	§ Wholesale electricity	§ U.S.A.
SEMPRA NATURAL GAS Develops, owns and operates, or holds interests in: § natural gas pipelines and storage facilities § natural gas distribution utilities § a terminal in the U.S. for the import and export of LNG and sale of natural gas § marketing operations § a natural gas-fired electric generation asset	§ Wholesale electricity § Natural gas § Liquefied natural gas	§ U.S.A.

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

§	Overall results of our operations and factors affecting those results

§	Our segment results

§	Significant changes in revenues, costs and earnings between periods

Our earnings increased by $52 million (18%) to $348 million in the three months ended September 30, 2014, while diluted earnings per share increased by $0.20 per share (17%) to $1.39 per share. For the nine months ended September 30, 2014, our earnings increased by $145 million (20%) to $864 million, while diluted earnings per share increased by $0.56 per share (19%) to $3.45 per share.

Due to the delay in the issuance of a final decision in the California Utilities’ 2012 General Rate Case (GRC), which was issued by the California Public Utilities Commission (CPUC) in May 2013 and effective retroactive to January 1, 2012, the California Utilities recorded incremental earnings of $77 million ($52 million at SDG&E and $25 million at SoCalGas) in the second quarter of 2013 from the retroactive impact for 2012. We provide additional information on the 2012 GRC in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

The net increase in our earnings and diluted earnings per share for the three-month period was primarily due to the following increases (decreases), by segment:

SDG&E

§	$10 million favorable resolution of prior years’ income tax items in 2014 compared to a $5 million unfavorable resolution in 2013

§	$10 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC, net of higher non-refundable operating costs

Sempra Mexico

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in July 2014

§	$14 million allowance for funds used during construction (AFUDC) in 2014 related to equity associated with construction of the natural gas pipeline in Sonora

§	$(6) million decrease in Sempra Mexico’s earnings for earnings attributable to noncontrolling interests at IEnova following its March 2013 offerings of 18.9 percent of IEnova common stock

Sempra Renewables

§	$(24) million in gains from the 2013 sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2

Sempra Natural Gas

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

Parent and Other

§	$(8) million income tax expense in 2014 for planned repatriation of current year foreign earnings

The net increase in our earnings and diluted earnings per share for the nine-month period ended September 30, 2014 was primarily impacted by the following increases (decreases), by segment:

SDG&E

$119 million charge in the second quarter of 2013 for loss from plant closure associated with SDG&E’s investment in San Onofre Nuclear Generating Station (SONGS), compared to a $(9) million charge in 2014 to adjust the total loss from plant closure based on a proposed settlement agreement filed with the CPUC, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein

§	$19 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs

§	$(52) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC

§	$(10) million lower earnings from electric transmission operations primarily due to lower Federal Energy Regulatory Commission (FERC)-authorized return on equity

SoCalGas

§	$27 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs

§	$(25) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC

Sempra Mexico

§	$34 million AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in July 2014

§	$(16) million decrease in Sempra Mexico’s earnings for earnings attributable to noncontrolling interests at IEnova following its March 2013 offerings of 18.9 percent of IEnova common stock

Sempra Renewables

§	$(24) million in gains from the 2013 sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2

§	$16 million gain from the sale of a 50-percent equity interest in Copper Mountain Solar 3 in the first quarter of 2014

Sempra Natural Gas

§	$(44) million gain on the sale of one 625-megawatt (MW) block of Sempra Natural Gas’ 1,250-MW Mesquite Power natural gas-fired power plant in the first quarter of 2013

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

Parent and Other

§	$63 million income tax expense in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings

§	$(32) million income tax expense in 2014 for planned repatriation of current year foreign earnings

The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2014				2013				2014				2013
California Utilities:
SDG&E(1)		$	157	45	%	$	129	44	%	$	379	44	%	$	285	40	%
SoCalGas(2)			98	28			102	34			256	30			266	37
Sempra International:
Sempra South American Utilities			32	9			39	13			109	13			110	15
Sempra Mexico			63	18			39	13			139	16			96	13
Sempra U.S. Gas & Power:
Sempra Renewables			17	5			37	13			63	7			56	8
Sempra Natural Gas			26	8			(7)	(2)			39	4			55	8
Parent and other(3)			(45)	(13)			(43)	(15)			(121)	(14)			(149)	(21)
Earnings		$	348	100	%	$	296	100	%	$	864	100	%	$	719	100	%
(1)	After preferred dividends and call premium on preferred stock for 2013.
(2)	After preferred dividends.
(3)	Includes after-tax interest expense ($37 million and $36 million for the three months ended September 30, 2014 and 2013, respectively, and $106 million and $109 million for the nine months ended September 30, 2014 and 2013, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

SEGMENT RESULTS

The following section is a discussion of earnings (losses) by Sempra Energy segment, as presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

[graph1.gif]

Due to the delay in the issuance of a final decision in the California Utilities’ 2012 GRC, which was issued by the CPUC in May 2013 and effective retroactive to January 1, 2012, the California Utilities recorded the retroactive impact for full-year 2012 in the second quarter of 2013, resulting in incremental earnings of $77 million ($52 million at SDG&E and $25 million at SoCalGas) for the nine months ended September 30, 2013. We provide additional information on the 2012 GRC in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

SDG&E

Our SDG&E segment recorded earnings of:

§	$157 million in the three months ended September 30, 2014

§	$129 million in the three months ended September 30, 2013 ($134 million before preferred dividends and call premium)

§	$379 million for the first nine months of 2014

§	$285 million for the first nine months of 2013 ($292 million before preferred dividends and call premium)

The increase in earnings of $28 million (22%) in the three months ended September 30, 2014 was primarily due to:

§	$10 million favorable resolution of prior years’ income tax items in 2014 compared to a $5 million unfavorable resolution in 2013;

§	$10 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC, net of higher non-refundable operating costs; and

§	$8 million favorable impact on the effective tax rate in 2014 compared to unfavorable impact in 2013, primarily due to updates for forecasted deductions for the full year; offset by

§	$4 million lower earnings from electric transmission operations primarily due to lower FERC-authorized return on equity.

The increase in earnings of $94 million (33%) in the first nine months of 2014 was primarily due to:

§	$119 million charge in the second quarter of 2013 for loss from plant closure associated with SDG&E’s investment in SONGS, compared to a $9 million charge in 2014 to adjust the total loss from plant closure, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein;

§	$19 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs; and

§	$10 million favorable resolution of prior years’ income tax items in 2014 compared to a $5 million unfavorable resolution in 2013; offset by

§	$52 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; and

§	$10 million lower earnings from electric transmission operations primarily due to lower FERC-authorized return on equity.

SoCalGas

Our SoCalGas segment recorded earnings of:

§	$98 million in the three months ended September 30, 2014 (both before and after preferred dividends)

§	$102 million in the three months ended September 30, 2013 (both before and after preferred dividends)

§	$256 million for the first nine months of 2014 ($257 million before preferred dividends)

§	$266 million for the first nine months of 2013 ($267 million before preferred dividends)

The decrease in earnings of $4 million (4%) in the three months ended September 30, 2014 was primarily due to:

§	$4 million insurance recovery in 2013 of previously expensed costs; and

§	$3 million favorable resolution of prior years’ income tax items in 2013; offset by

§	$3 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC, net of higher non-refundable operating costs.

The decrease in earnings of $10 million (4%) in the first nine months of 2014 was primarily due to:

§	$25 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC;

§	$7 million favorable resolution of prior years’ income tax items in 2013;

§	$5 million write-off in 2014 of certain costs incurred associated with the Pipeline Safety Enhancement Plan (PSEP) that were disallowed for recovery in the final PSEP decision (as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein); and

§	$4 million insurance recovery in 2013 of previously expensed costs; offset by

§	$27 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

[graph2.gif]

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:

§	$32 million in the three months ended September 30, 2014

§	$39 million in the three months ended September 30, 2013

§	$109 million for the first nine months of 2014

§	$110 million for the first nine months of 2013

The decrease in earnings of $7 million (18%) in the three months ended September 30, 2014 was primarily due to:

§	$8 million higher income tax expense, including $6 million related to Chilean tax reform as we discuss below under “Income Taxes – Chilean Tax Reform;” and

§	$4 million lower earnings from foreign currency effects; offset by

§	$5 million higher earnings from operations mainly due to an increase in volume and lower costs.

The decrease in earnings of $1 million (1%) in the first nine months of 2014 was primarily due to:

§	$12 million lower earnings from foreign currency effects;

§	$9 million higher income tax expense, including $6 million related to Chilean tax reform; and

§	$5 million higher interest expense mainly in Chile related to inflationary effect on local bonds; offset by

§	$13 million higher earnings from operations mainly due to an increase in volume, primarily from customer growth, and lower costs; and

§	$11 million equity losses related to our investments in two Argentine natural gas utility holding companies that were sold in 2013.

Sempra Mexico

Our Sempra Mexico segment recorded earnings of:

§	$63 million in the three months ended September 30, 2014

§	$39 million in the three months ended September 30, 2013

§	$139 million for the first nine months of 2014

§	$96 million for the first nine months of 2013

The increase in earnings of $24 million (62%) in the three months ended September 30, 2014 was primarily due to:

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in July 2014;

§	$14 million AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora;

§	$6 million higher earnings from operations at our Mexicali power plant in 2014; and

§	$3 million lower income tax expense primarily due to the effects from foreign currency and translation of deferred tax balances; offset by

§	$15 million earnings attributable to noncontrolling interests at IEnova in 2014 compared to $9 million in 2013; and

§	$5 million unfavorable translation effect primarily on Peso-denominated receivables.

The increase in earnings of $43 million (45%) in the first nine months of 2014 was primarily due to:

§	$34 million AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora;

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in July 2014;

§	$12 million higher earnings from operations mainly due to prior year’s scheduled major maintenance and improved results at our Mexicali power plant; and

§	$6 million lower income tax expense including the effects from foreign currency and inflation; offset by

§	$34 million earnings attributable to noncontrolling interests at IEnova in 2014 compared to $18 million in 2013; and

§	$5 million higher interest expense.

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

(Dollars in millions)

[graph3.gif]

Sempra Renewables

Our Sempra Renewables segment recorded earnings of:

§	$17 million in the three months ended September 30, 2014

§	$37 million in the three months ended September 30, 2013

§	$63 million for the first nine months of 2014

§	$56 million for the first nine months of 2013

The decrease in earnings of $20 million (54%) in the three months ended September 30, 2014 was primarily due to:

§	$24 million in gains from the 2013 sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2; and

§	$2 million lower earnings attributable to our solar assets, primarily resulting from the third-quarter 2013 sales of equity interests noted above; offset by

§	$6 million higher deferred income tax benefits from projects placed in service in 2014.

The increase in earnings of $7 million (13%) in the first nine months of 2014 was primarily due to:

§	$16 million gain from the sale of a 50-percent equity interest in Copper Mountain Solar 3 in the first quarter of 2014; and

§	$16 million higher deferred income tax benefits, including the benefits of projects placed in service in 2014 and a $5 million reduction of benefits in 2013 as a result of Treasury Grant sequestration; offset by

§	$24 million in gains from the 2013 sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2.

Sempra Natural Gas

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

§	$26 million in the three months ended September 30, 2014

§	$(7) million in the three months ended September 30, 2013

§	$39 million for the first nine months of 2014

§	$55 million for the first nine months of 2013

The increase in earnings of $33 million in the three months ended September 30, 2014 was primarily due to:

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

§	$5 million higher net intercompany interest income; and

§	$4 million higher earnings, primarily from LNG marketing operations, due to the impact of higher natural gas prices in 2014; offset by

§	$7 million lower results from gas storage operations and natural gas marketing activities.

The decrease in earnings of $16 million (29%) in the first nine months of 2014 was primarily due to:

§	$44 million gain in 2013 on the sale of a 625-MW block of its Mesquite Power plant, net of related expenses; and

§	$12 million lower results from gas storage operations and natural gas marketing activities; offset by

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

§	$8 million higher net intercompany interest income; and

§	$7 million lower operating costs at the Mesquite Power plant, primarily depreciation due to the classification of the remaining 625-MW block as an asset held for sale.

Parent and Other

Losses for Parent and Other were

§	$45 million in the three months ended September 30, 2014

§	$43 million in the three months ended September 30, 2013

§	$121 million for the first nine months of 2014

§	$149 million for the first nine months of 2013

The increase in losses of $2 million (5%) in the three months ended September 30, 2014 was primarily due to:

§	$8 million income tax expense in 2014 for planned repatriation of current year foreign earnings; offset by

§	$4 million lower investment net losses on dedicated assets in support of our executive retirement and deferred compensation plans.

The decrease in losses of $28 million (19%) in the first nine months of 2014 was primarily due to:

§	$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings; and

§	$5 million higher investment net gains on dedicated assets in support of our executive retirement and deferred compensation plans; offset by

§	$32 million income tax expense in 2014 for planned repatriation of current year foreign earnings; and

§	$8 million higher net interest expense.

CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in the specific line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.

Utilities Revenues

Our utilities revenues include

Natural gas revenues at:

SDG&E

SoCalGas

§	Sempra Mexico’s Ecogas México, S. de R.L. de C.V. (Ecogas)

§	Sempra Natural Gas’ Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas)

Electric revenues at:

SDG&E

§	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Condensed Consolidated Statements of Operations.

The California Utilities

The current regulatory framework for SoCalGas and SDG&E permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The regulatory framework also permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in the next year through rates.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:

UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
		Three months ended				Nine months ended
		September 30,				September 30,
		2014		2013		2014		2013
Electric revenues:
SDG&E		$	1,133	$	970	$	2,892	$	2,685
Sempra South American Utilities			354		334		1,072		1,034
Eliminations and adjustments			(2)		(2)		(7)		(6)
	Total		1,485		1,302		3,957		3,713
Natural gas revenues:
SoCalGas			855		807		2,857		2,694
SDG&E			100		93		391		381
Sempra Mexico			23		21		82		72
Sempra Natural Gas			17		17		84		79
Eliminations and adjustments			(17)		(17)		(53)		(50)
	Total		978		921		3,361		3,176
Total utilities revenues		$	2,463	$	2,223	$	7,318	$	6,889
Cost of electric fuel and purchased power:
SDG&E		$	441	$	315	$	1,036	$	776
Sempra South American Utilities			239		222		725		685
	Total	$	680	$	537	$	1,761	$	1,461
Cost of natural gas:
SoCalGas		$	237	$	209	$	1,066	$	966
SDG&E			39		36		165		157
Sempra Mexico			16		15		56		47
Sempra Natural Gas			6		5		33		25
Eliminations and adjustments			(5)		(4)		(12)		(13)
	Total	$	293	$	261	$	1,308	$	1,182

Sempra Energy Consolidated

Electric Revenues

During the three months ended September 30, 2014, our electric revenues increased by $183 million (14%) to $1.5 billion primarily due to:

§	$163 million increase at SDG&E, which included

□	$126 million increase in cost of electric fuel and purchased power, which we discuss below, and

□	$12 million increase in authorized revenues from 2014 attrition; and

§	$20 million increase at Sempra South American Utilities, primarily due to higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power increased by $143 million (27%) to $680 million in the three months ended September 30, 2014 due to:

§	$126 million increase at SDG&E, which we discuss below; and

§	$17 million increase at our South American utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

During the nine months ended September 30, 2014, our electric revenues increased by $244 million (7%) to $4.0 billion primarily due to:

§	$207 million increase at SDG&E, which included

□	$260 million increase in cost of electric fuel and purchased power, which we discuss below,

□	$30 million increase in authorized revenues from 2014 attrition, and

□	$15 million higher authorized revenue from electric transmission, offset by

□	$61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012, and

□	$45 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$38 million increase at Sempra South American Utilities, primarily due to higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power increased by $300 million (21%) to $1.8 billion in the nine months ended September 30, 2014 due to:

§	$260 million increase at SDG&E, which we discuss below; and

§	$40 million increase at our South American utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.

Natural Gas Revenues

During the three months ended September 30, 2014, Sempra Energy’s natural gas revenues increased by $57 million (6%) to $978 million, and the cost of natural gas increased by $32 million (12%) to $293 million. The increase in natural gas revenues included

§	increases in cost of natural gas sold at SoCalGas and SDG&E, as we discuss below; and

§	$13 million increase in authorized revenues from 2014 attrition at SoCalGas.

During the first nine months of 2014, Sempra Energy’s natural gas revenues increased by $185 million (6%) to $3.4 billion, and the cost of natural gas increased by $126 million (11%) to $1.3 billion. The increase in natural gas revenues included

§	increases in cost of natural gas sold at SoCalGas and SDG&E, as we discuss below;

§	$45 million increase in authorized revenues from 2014 attrition at the California Utilities;

§	$30 million higher recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$24 million higher revenues from the advanced metering infrastructure project at SoCalGas; offset by

§	$30 million favorable impact on the California Utilities’ 2013 revenues from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012.

We discuss the changes in natural gas revenues and the cost of natural gas individually for SDG&E and SoCalGas below.

SDG&E: Electric Revenues and Cost of Electric Fuel and Purchased Power

The table below shows electric revenues for SDG&E for the nine-month periods ended September 30, 2014 and 2013. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in cost, electric revenues recorded during a period are impacted by customer billing cycles causing a difference between customer billings and recorded or authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
		Nine months ended September 30, 2014			Nine months ended September 30, 2013
Customer class		Volumes	Revenue		Volumes	Revenue
Residential		5,501	$	1,042	5,645	$	962
Commercial		5,245		1,048	5,110		815
Industrial		1,556		251	1,485		192
Direct access(1)		2,761		150	2,681		110
Street and highway lighting		66		11	65		9
		15,129		2,502	14,986		2,088
CAISO shared transmission revenue - net(2)				137			210
Other revenues				144			130
Balancing accounts				109			257
Total(3)			$	2,892		$	2,685
(1)	The Direct Access (DA) program, which offered all customers the option to purchase their electric commodity services from a third-party Energy Service Provider (ESP) instead of continuing to receive these services from SDG&E, was implemented in 1998 and suspended in 2001. In 2009, Senate Bill 695 required the CPUC to develop a process and rules for a limited re-opening of DA to be phased in over a period of time. In 2010, the CPUC adopted the process and rules for the limited re-opening of DA for non-residential customers under a 4-year phase-in schedule.
(2)	California Independent System Operator (CAISO).
(3)	Includes sales to affiliates of $6 million in both 2014 and 2013.

For the three months ended September 30, 2014, SDG&E’s electric revenues increased by $163 million (17%) to $1.1 billion compared to the corresponding period of 2013 primarily due to:

§	$126 million increase in cost of electric fuel and purchased power primarily due to the incremental purchase of renewable energy at higher prices; and

§	$12 million increase in authorized revenues from 2014 attrition.

In the first nine months of 2014, SDG&E’s electric revenues increased by $207 million (8%) to $2.9 billion primarily due to:

§	$260 million increase in cost of electric fuel and purchased power, including

□	an increase in purchased power primarily due to the incremental purchase of renewable energy at higher prices, offset by

□	a decrease in cost of electric fuel primarily due to planned outages at SDG&E-owned generation facilities;

§	$30 million increase in authorized revenues from 2014 attrition; and

§	$15 million higher authorized revenue from electric transmission; offset by

§	$61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012; and

§	$45 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

We do not include in the Condensed Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts in 2013 that were allocated to SDG&E by the California Department of Water Resources. However, we do include the associated volumes and distribution revenues in the table above. We provide further discussion of these contracts in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas

The tables below show natural gas revenues for SDG&E and SoCalGas for the nine-month periods ended September 30, 2014 and 2013. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
		Natural Gas Sales			Transportation			Total
Customer class		Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Nine months ended September 30, 2014:
Residential		21	$	241	―	$	―	21	$	241
Commercial and industrial		11		83	6		8	17		91
Electric generation plants(1)		―		―	19		1	19		1
		32	$	324	25	$	9	57		333
Other revenues										31
Balancing accounts										27
Total(2)									$	391
Nine months ended September 30, 2013:
Residential		24	$	245	―	$	1	24	$	246
Commercial and industrial		11		74	7		9	18		83
Electric generation plants		―		―	19		12	19		12
		35	$	319	26	$	22	61		341
Other revenues										30
Balancing accounts										10
Total(2)									$	381
(1)	Lower electric generation plants revenue in 2014 compared to 2013 is due to refunds of previous overcollections to adjust forecasted rates to actual.
(2)	Includes sales to affiliates of $2 million in both 2014 and 2013.

During the three months ended September 30, 2014, SDG&E’s natural gas revenues increased by $7 million (8%) to $100 million, while the cost of natural gas sold increased by $3 million (8%) to $39 million. The increase in revenues was primarily due to:

§	higher cost of natural gas sold, offset by lower sales volume, as we discuss below; and

§	$3 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

SDG&E’s average cost of natural gas for the three months ended September 30, 2014 was $5.65 per thousand cubic feet (Mcf) compared to $4.85 per Mcf for the corresponding period in 2013, a 16-percent increase of $0.80 per Mcf, resulting in higher revenues and cost of $5 million. The increase in the cost of natural gas sold was offset by lower sales volumes, which resulted in lower revenues and cost of $2 million.

During the nine months ended September 30, 2014, SDG&E’s natural gas revenues increased by $10 million (3%) to $391 million, and the cost of natural gas increased by $8 million (5%) to $165 million. The increase in revenues was primarily due to:

§	higher cost of natural gas sold, offset by lower demand, as we discuss below; and

§	$6 million increase in authorized revenues from 2014 attrition; offset by

§	$5 million favorable impact from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012.

SDG&E’s average cost of natural gas for the nine months ended September 30, 2014 was $5.52 per Mcf compared to $4.45 per Mcf for the corresponding period in 2013, a 24-percent increase of $1.07 per Mcf, resulting in higher revenues and cost of $32 million. The increase in the cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $24 million.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
		Natural Gas Sales			Transportation			Total
Customer class		Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Nine months ended September 30, 2014:
Residential		139	$	1,564	2	$	10	141	$	1,574
Commercial and industrial		68		563	220		197	288		760
Electric generation plants		―		―	156		32	156		32
Wholesale		―		―	109		18	109		18
		207	$	2,127	487	$	257	694		2,384
Other revenues										74
Balancing accounts										399
Total(1)									$	2,857
Nine months ended September 30, 2013:
Residential		167	$	1,566	2	$	6	169	$	1,572
Commercial and industrial		74		510	218		180	292		690
Electric generation plants		―		―	158		35	158		35
Wholesale		―		―	123		20	123		20
		241	$	2,076	501	$	241	742		2,317
Other revenues										76
Balancing accounts										301
Total(1)									$	2,694
(1)	Includes sales to affiliates of $51 million in 2014 and $48 million in 2013.

During the three months ended September 30, 2014, SoCalGas’ natural gas revenues increased by $48 million (6%) to $855 million, and the cost of natural gas sold increased by $28 million (13%) to $237 million. The revenue increase included

§	an increase in the market price of natural gas purchased, offset by lower demand, as we discuss below;

§	$13 million increase in authorized revenues from 2014 attrition; and

§	$2 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

SoCalGas’ average cost of natural gas for the three months ended September 30, 2014 was $4.75 per Mcf compared to $3.91 per Mcf for the corresponding period in 2013, a 21-percent increase of $0.84 per Mcf, resulting in higher revenues and cost of $42 million. The increase in the average cost of natural gas sold was offset by lower sales volumes, which resulted in lower revenues and cost of $14 million.

During the nine months ended September 30, 2014, SoCalGas’ natural gas revenues increased by $163 million (6%) to $2.9 billion, and the cost of natural gas sold increased by $100 million (10%) to $1.1 billion. The revenue increase included

§	an increase in the market price of natural gas purchased, offset by lower demand, as we discuss below;

§	$39 million increase in authorized revenues from 2014 attrition;

§	$30 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$24 million higher revenues from the advanced metering infrastructure project; offset by

§	$25 million favorable impact from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012.

For the first nine months of 2014, SoCalGas’ average cost of natural gas was $5.15 per Mcf compared to $4.01 per Mcf for the corresponding period in 2013, a 28-percent increase of $1.14 per Mcf, resulting in higher revenues and cost of $235 million. The increase in the average cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $135 million.

Other Utilities: Revenues and Cost of Sales

Revenues generated by Chilquinta Energía and Luz del Sur are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. The bases for the tariffs do not meet the requirement necessary for treatment under applicable accounting principles generally accepted in the United States of America (U.S. GAAP) for regulatory accounting. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

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

The table below summarizes natural gas and electric revenues for our utilities outside of California for the nine-month periods ended September 30, 2014 and 2013:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)
	Nine months ended September 30, 2014			Nine months ended September 30, 2013
	Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico — Ecogas	18	$	82	18	$	72
Sempra Natural Gas:
Mobile Gas (including transportation)	29		66	29		64
Willmut Gas	2		18	2		15
Total	49	$	166	49	$	151

Electric Sales (million kilowatt hours):
Sempra South American Utilities:
Luz del Sur	5,458	$	642	5,221	$	585
Chilquinta Energía	2,192		394	2,127		405
	7,650		1,036	7,348		990
Other service revenues			36			44
Total		$	1,072		$	1,034

Energy-Related Businesses: Revenues and Cost of Sales

The table below shows revenues and cost of sales for our energy-related businesses:

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
		Three months ended				Nine months ended
		September 30,				September 30,
		2014		2013		2014		2013
Energy-related businesses revenues:
Sempra South American Utilities		$	25	$	30	$	75	$	85
Sempra Mexico			211		167		539		447
Sempra Renewables			10		25		25		76
Sempra Natural Gas			235		195		664		604
Intersegment revenues, adjustments and eliminations(1)			(129)		(89)		(333)		(249)
Total energy-related businesses revenues		$	352	$	328	$	970	$	963
Cost of natural gas, electric fuel and purchased power(2):
Sempra South American Utilities		$	3	$	―	$	10	$	―
Sempra Mexico			108		72		272		189
Sempra Renewables			―		―		―		3
Sempra Natural Gas			179		134		473		378
Adjustments and eliminations(1)			(127)		(86)		(328)		(245)
Total cost of natural gas, electric fuel
and purchased power		$	163	$	120	$	427	$	325
Other cost of sales(2):
Sempra South American Utilities		$	17	$	23	$	50	$	63
Sempra Mexico			4		3		9		18
Sempra Natural Gas			23		22		69		69
Adjustments and eliminations(1)			(2)		(1)		(6)		(6)
Total other cost of sales		$	42	$	47	$	122	$	144
(1)	Includes eliminations of intercompany activity.
(2)	Excludes depreciation and amortization, which are shown separately on the Condensed Consolidated Statements of Operations.

During the three months ended September 30, 2014, revenues from our energy-related businesses increased by $24 million (7%) to $352 million. The increase included

§	$44 million higher revenues at Sempra Mexico primarily due to higher natural gas and power prices and volumes; and

§	$40 million increase at Sempra Natural Gas mainly from the favorable impact of higher natural gas prices in 2014 from its LNG marketing operations, offset by lower revenues from its natural gas marketing activities; offset by

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

§	$15 million lower revenues at Sempra Renewables mainly due to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in the third quarter of 2013.

During the three months ended September 30, 2014, the cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $43 million (36%) to $163 million primarily due to:

§	$45 million increase at Sempra Natural Gas primarily due to higher natural gas costs and volumes; and

§	$36 million increase at Sempra Mexico primarily due to higher natural gas costs and volumes; offset by

§	$41 million primarily from higher intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

For the first nine months of 2014, revenues from our energy-related businesses increased by $7 million (1%) to $970 million. The increase included

§	$92 million higher revenues at Sempra Mexico primarily due to higher natural gas and power prices and volumes; and

§	$60 million increase at Sempra Natural Gas mainly from the favorable impact of higher natural gas prices in 2014 from its LNG marketing operations, offset by lower revenues from its natural gas marketing activities; offset by

§	$84 million primarily from higher intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico; and

§	$51 million lower revenues at Sempra Renewables mainly due to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in the third quarter of 2013.

For the first nine months of 2014, the cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $102 million (31%) to $427 million primarily due to:

§	$95 million increase at Sempra Natural Gas primarily due to higher natural gas costs and volumes; and

§	$83 million increase at Sempra Mexico primarily due to higher natural gas costs and volumes; offset by

§	$83 million primarily from higher intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

Operation and Maintenance

Sempra Energy Consolidated

Our operation and maintenance expenses increased by $28 million (4%) to $726 million in the three months ended September 30, 2014 and decreased by $31 million (1%) to $2.1 billion in the first nine months of 2014. The changes in both periods were primarily attributable to SDG&E and SoCalGas, which we discuss below.

SDG&E

For the three months ended September 30, 2014, SDG&E’s operation and maintenance expenses increased by $10 million (4%) to $276 million primarily due to:

§	$6 million higher litigation expense;

§	$5 million higher operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs); and

§	$3 million higher expenses associated with CPUC-authorized refundable programs, including $13 million due to lower operation and maintenance expenses at SONGS, for which all costs incurred are fully recovered in revenue (refundable program expenses); offset by

§	$4 million decrease at Otay Mesa VIE.

In the first nine months of 2014, SDG&E’s operation and maintenance expenses decreased by $68 million (8%) to $784 million primarily due to:

§	$45 million lower expenses associated with CPUC-authorized refundable programs, including $48 million due to lower operation and maintenance expenses at SONGS, for which all costs incurred are fully recovered in revenue (refundable program expenses);

§	$20 million decrease at Otay Mesa VIE; and

§	$10 million lower operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs); offset by

§	$7 million higher litigation expense.

SoCalGas

For the three months ended September 30, 2014, SoCalGas’ operation and maintenance expenses increased by $12 million (4%) to $326 million primarily due to:

§	$7 million insurance recovery in 2013 of previously expensed cost;

§	$5 million higher operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs); and

§	$2 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).

In the first nine months of 2014, SoCalGas’ operation and maintenance expenses increased by $32 million (3%) to $968 million primarily due to:

§	$30 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); and

§	$7 million insurance recovery in 2013 of previously expensed cost; offset by

§	$2 million lower operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs).

Plant Closure (Loss) Adjustment

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California. SONGS’ Units 2 and 3 were shut down in early 2012 due to steam generator issues, and, in June 2013, Southern California Edison, the majority owner and operator of SONGS, made a decision to permanently retire these two units. In the second quarter of 2013, SDG&E recorded a pretax charge of $200 million, which represents the portion of SDG&E’s investment in SONGS and associated costs that management estimated may not be recovered in rates based on prior CPUC precedent. In the first quarter of 2014, SDG&E recorded a $13 million favorable adjustment to adjust the total loss from plant closure (in addition to the amount recorded in 2013), based on a proposed settlement agreement filed with the CPUC. We discuss SONGS further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

Gain on Sale of Equity Interests and Assets

Gain on sale of equity interests and assets in the nine months ended September 30, 2013 included the $74 million gain ($44 million after-tax) from the sale of one 625-MW block of the Mesquite Power natural gas-fired power plant (in the first quarter).

Also included in this line item are gains on the sale of 50-percent equity interests in 2014 and 2013 as follows:

2014:

§	$19 million ($14 million after-tax) for the first phase of the Energía Sierra Juárez project (in the third quarter)

§	$27 million ($16 million after-tax) for Copper Mountain Solar 3 (in the first quarter)

2013:

§	$36 million ($22 million after-tax) for Mesquite Solar 1 (in the third quarter)

§	$4 million ($2 million after-tax) for Copper Mountain Solar 2 (in the third quarter)

Equity Earnings, Before Income Tax

For the three months and nine months ended September 30, 2014, equity earnings, before income tax, increased by $19 million and $41 million, respectively.

The increase for the three-month period was primarily attributable to:

§	$7 million equity earnings in 2014 compared to $10 million equity losses in 2013 from investments at Sempra Renewables, including Mesquite Solar 1, the California solar partnership and Flat Ridge 2; and

§	$2 million higher equity earnings from the Rockies Express investment at Sempra Natural Gas.

The increase for the first nine months of 2014 was primarily attributable to:

§	$18 million equity earnings in 2014 compared to $12 million equity losses in 2013 from investments at Sempra Renewables, including Mesquite Solar 1, the California solar partnership, Fowler Ridge 2 Wind Farm and Copper Mountain Solar 2; and

§	$11 million higher equity earnings from Rockies Express.

Other Income, Net

Sempra Energy Consolidated

For the three months and nine months ended September 30, 2014, other income, net, increased by $13 million and $39 million, respectively, including $14 million and $34 million, respectively, of AFUDC related to equity in 2014 associated with construction of the Sonora natural gas pipeline at Sempra Mexico. Construction on the first segment of the Sonora Pipeline was completed in October 2014.

Income Taxes

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

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
		Three months ended September 30,
		2014				2013
Sempra Energy Consolidated	$	71	16	%	$	117	27	%
SDG&E		65	28			84	38
SoCalGas		44	31			38	27
		Nine months ended September 30,
		2014				2013
Sempra Energy Consolidated	$	291	24	%	$	327	30	%
SDG&E		217	35			147	33
SoCalGas		110	30			107	29

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended September 30, 2014 was mainly due to a lower effective tax rate, primarily from:

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

§	higher income tax benefit from Mexican currency translation and inflation adjustments; and

§	favorable adjustments to prior years’ income tax items in 2014; offset by

§	$8 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru.

In the first nine months of 2014, the decrease in income tax expense was due to a lower effective tax rate, offset by higher pretax income. The lower effective income tax rate was primarily due to:

§	$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings in Note 5 of the Notes to Condensed Consolidated Financial Statements herein; and

§	$25 million tax benefit due to the release in 2014 of Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments; offset by

§	$32 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru; and

a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that may no longer be recoverable from customers in rates pursuant to the proposed settlement agreement to resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS outage that we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

As noted in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report, we have planned to repatriate a portion of current earnings beginning in 2014 from our subsidiaries in Mexico and Peru. Currently, all repatriated earnings from January 1, 2014 forward (reduced for previously taxed income) are subject to U.S. income tax (with credits for foreign income taxes), and repatriation from Peru is subject to local country withholding tax. Because any repatriation would only be from earnings in 2014 and later years, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2013. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted on a full year basis are factored into the forecasted effective tax rate and their impact is recognized proportionately over the year. Items that cannot be reliably forecasted are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.

Due to the extension of bonus depreciation, Sempra Energy, SDG&E and SoCalGas generated large U.S. federal net operating losses (NOLs) in 2011 and 2012. We discuss further the impact of NOLs on Sempra Energy, SDG&E and SoCalGas in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Chilean Tax Reform

The 2014 Chilean Tax Reform Bill (Tax Reform Bill) became effective on September 29, 2014. Taxpayers have an option of being taxed under two approaches. For the approach that we intend to select, the corporate income tax rates will increase gradually, between 2014 and 2017, from 21 percent to 27 percent. To reflect the impact of the change in tax law, we remeasured our Chilean deferred tax balances, which resulted in an additional $6 million of deferred tax expense that was recorded in the third quarter of 2014. The Tax Reform Bill also imposes a tax on earnings distributed to non-Chilean shareholders. However, since Sempra Energy intends to indefinitely reinvest the cumulative Chilean earnings, there is no impact from the Tax Reform Bill’s shareholder level income tax.

SDG&E

The decrease in SDG&E’s income tax expense in the three months ended September 30, 2014 was mainly due to a lower effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2014 compared to unfavorable adjustments in 2013; and

§	lower unfavorable impact on our effective tax rate in 2014 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; offset by

§	lower deductions for self-developed software expenditures.

The increase in SDG&E’s income tax expense in the nine months ended September 30, 2014 was due to higher pretax income and a higher effective tax rate. The higher effective tax rate was primarily due to:

§	the $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS discussed above;

§	lower exclusions from taxable income of the equity portion of AFUDC; and

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

§	favorable adjustments to prior years’ income tax items in 2014 compared to unfavorable adjustments in 2013.

SoCalGas

The increase in SoCalGas’ income tax expense in the three months ended September 30, 2014 was mainly due to a higher effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2013; and

§	lower deductions for self-developed software expenditures.

The increase in SoCalGas’ income tax expense in the nine months ended September 30, 2014 was mainly due to a higher effective tax rate, primarily from:

§	favorable adjustments to prior years’ income tax items in 2013; offset by

§	higher deductions for certain repairs expenditures that are capitalized for financial statement purposes.

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

Our Mexican subsidiaries have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes.

The fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar, with regard to Mexican monetary assets and liabilities, and Mexican inflation are subject to Mexican income tax and thus may expose us to fluctuations in our income tax expense. The income tax expense of Sempra Mexico is impacted by these factors. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage these exposures.

For Sempra Energy Consolidated, the impacts related to the factors described above are as follows:

MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
(Dollars in millions)
		Three months ended				Nine months ended
		September 30,				September 30,
		2014		2013		2014		2013
Income tax benefit (expense) on currency exchange
	rate movement of monetary assets and liabilities	$	4	$	1	$	4	$	(6)
Translation of non-U.S. deferred income tax balances			5		―		5		―
Income tax expense on inflation			―		―		(1)		―
	Total impact included in Income Tax Benefit (Expense)		9		1		8		(6)
After-tax (losses) gains on Mexican peso exchange rate
	instruments (included in Other Income, Net)		(4)		―		(4)		4
Net impacts on Sempra Energy Condensed
	Consolidated Statements of Operations	$	5	$	1	$	4	$	(2)

Equity Earnings, Net of Income Tax

In the nine months ended September 30, 2014, equity earnings of unconsolidated subsidiaries, net of income tax, increased primarily due to $11 million equity losses in 2013 related to our investments in two Argentine natural gas utility holding companies, as we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements herein.

Earnings Attributable to Noncontrolling Interests

Sempra Energy Consolidated

Earnings attributable to noncontrolling interests were $35 million for the three months ended September 30, 2014 compared to $22 million for the same period in 2013. The net change of $13 million included

§	$7 million increase in earnings attributable to noncontrolling interest at Otay Mesa VIE; and

§	$6 million increase in earnings attributable to noncontrolling interests of IEnova.

Earnings attributable to noncontrolling interests were $76 million for the nine months ended September 30, 2014 compared to $41 million for the same period in 2013. The net change of $35 million included

§	$19 million increase in earnings attributable to noncontrolling interest at Otay Mesa VIE; and

§	$16 million increase in earnings attributable to noncontrolling interests of IEnova.

Earnings

We discuss variations in earnings by segment above in “Segment Results.”

CAPITAL RESOURCES AND LIQUIDITY

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. In addition, we may meet our cash requirements through the issuance of securities, including short-term and long-term debt securities, distributions from our equity method investments and project financing.

Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities, expiring in March 2017. At Sempra Energy and the California Utilities, the agreements are syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders. No single lender has greater than a 7-percent share in any agreement. The table below shows the amount of available funds on these credit facilities at September 30, 2014:

AVAILABLE FUNDS AT SEPTEMBER 30, 2014
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)		$	667	$	33	$	25
Available unused credit(2)			2,878		558		658
(1)	Amounts at Sempra Energy Consolidated include $591 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below.
(2)	Available credit is the total available on Sempra Energy's, Sempra Global's and the California Utilities' credit facilities that we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $658 million for each utility and a combined total of $877 million. SDG&E's available funds reflect commercial paper outstanding of $100 million supported by the line. Some of Sempra Energy's subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $875 million at September 30, 2014. Available unused credit on these lines totaled $630 million at September 30, 2014.

Sempra Energy Consolidated

We believe that these available funds and cash flows from operations, distributions from equity method investments and securities issuances, and project financing and partnering in joint ventures, will be adequate to fund operations, including to:

§	finance capital expenditures

§	meet liquidity requirements

§	fund shareholder dividends

§	fund new business acquisitions or start-ups

§	repay maturing long-term debt

In September and March 2014, SoCalGas publicly offered and sold $500 million and $250 million of 3.15-percent and 4.45-percent notes maturing in 2024 and 2044, respectively. In June 2014, Sempra Energy publicly offered and sold $500 million of 3.55-percent notes maturing in 2024. In 2013, Sempra Energy and SDG&E publicly offered and sold debt securities totaling $500 million and $450 million, respectively, maturing in 2023. In 2013, Sempra Mexico issued debt securities totaling $408 million U.S. dollar equivalent maturing in 2018 and 2023. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact certain of our Sempra International and Sempra U.S. Gas & Power businesses before we would reduce funds necessary for the ongoing needs of our utilities. We continuously monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.

In addition to capital expenditures and changes in publicly traded securities and commercial paper borrowings, large investing and financing cash items contributing to the $237 million net decrease in Sempra Energy Consolidated cash and cash equivalents at September 30, 2014 compared to December 31, 2013 included increases (decreases) in cash of:

§	$(450) million common dividends paid

§	$(109) million for acquisition of a 50-percent equity interest in four solar projects in May 2014

§	$66 million cash proceeds from the sale of a 50-percent equity interest in Copper Mountain Solar 3 in March 2014, net of $2 million cash sold

§	$84 million in net proceeds from a construction loan related to Copper Mountain Solar 3 in March 2014; the loan was deconsolidated upon the sale. We discuss the Copper Mountain Solar 3 transactions further in Notes 3 and 6 of the Notes to Condensed Consolidated Financial Statements herein

§	$24 million cash proceeds from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind generation project in July 2014, net of $2 million cash sold

§	$82 million proceeds from a construction loan related to the Energía Sierra Juárez project in June 2014; the loan was deconsolidated upon the sale. We discuss the Energía Sierra Juárez transactions further in Notes 3 and 6 of the Notes to Condensed Consolidated Financial Statements herein

At September 30, 2014, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $591 million. As we discuss in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report, we plan to repatriate a portion of current earnings beginning in 2014 from certain of our non-U.S. subsidiaries in Mexico and Peru. Because this potential repatriation would only be from earnings since January 1, 2014, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2013. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. Changes in asset values, which are dependent on the activity in the equity and fixed income markets, have not affected the trust funds’ abilities to make required payments, but along with a number of other factors such as changes to discount rates, assumed rates of returns and regulations, may impact funding requirements for pension and other postretirement benefit plans and the nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.

We discuss our principal credit agreements more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, temporarily finance capital expenditures, and fund new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary source of short-term debt funding in the first nine months of 2014.

California Utilities

SDG&E and SoCalGas expect that available funds, cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements.

In October 2014, SoCalGas declared and paid $100 million in common dividends. In 2013, SoCalGas declared and paid $50 million in common dividends. As a result of the increase in SoCalGas’ capital investment programs over the next few years, and the increase in SoCalGas’ authorized common equity weighting as approved by the CPUC in the cost of capital proceeding, SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations, or may be temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

In October 2014, SDG&E declared and paid $100 million in common dividends. On the same date, SDG&E also declared $100 million in common dividends payable on December 23, 2014. As a result of SDG&E’s large capital investment program over the past few years, SDG&E did not pay common dividends to Sempra Energy in 2013. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E has resumed the declaration and payment of dividends on its common stock in 2014.

SDG&E uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power and the amount billed to customers in rates. Primarily as a result of delays in the CPUC issuing final decisions on SDG&E’s ERRA-related filings, as of September 30, 2014, SDG&E’s ERRA balance is undercollected by $489 million. In February 2014, the CPUC issued a decision granting SDG&E authority to increase rates to recover an ERRA Trigger revenue requirement of $221 million, which rate increase was effective on April 1, 2014 and will continue through December 31, 2015. In May 2014, the CPUC issued a final decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $242 million, which rate increase was effective on August 1, 2014. With these rate changes, and assuming that actual energy resource costs incurred approximate what was assumed in the proposed 2014 ERRA revenue requirement, management expects the undercollected balance in ERRA to decrease between now and the end of 2015. We discuss the ERRA Trigger and the status of the ERRA filings further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and provide information on how the increasing undercollected balance in ERRA has impacted SDG&E in our discussion of “Cash Flows From Operating Activities” below.

Sempra South American Utilities

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

Sempra Mexico

We expect projects in Mexico to be funded through a combination of available funds, funds internally generated by the Mexico businesses, securities issuances, project financing and partnering in joint ventures. In June and August 2014, IEnova entered into two three-year term, corporate revolving credit facility agreements providing $200 million and $100 million, respectively, to finance working capital and for other general corporate purposes. IEnova drew down $40 million in July 2014 and $105 million in August 2014 from the first facility. In June 2014, Sempra Mexico also entered into a $240 million loan to finance the construction of the first phase of Energía Sierra Juárez, as we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. The loan agreement provides for a $31.7 million letter of credit facility. Sempra Mexico also entered into a separate, Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project. In June 2014, Sempra Mexico drew down $82 million from the loan. In July 2014, Sempra Mexico sold a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold. Sempra Mexico’s interest in Energía Sierra Juárez is now accounted for under the equity method, and the $82 million of long-term debt was deconsolidated at the time of sale, as we discuss in Notes 3 and 4 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Renewables

We expect Sempra Renewables to require funds for the development of and investment in renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales. The Sempra Renewables projects have planned in-service dates through 2016. In March 2014, Sempra Renewables received a $356 million construction loan related to Copper Mountain Solar 3, as we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. Copper Mountain Solar 3 made an initial draw-down on the loan of $97 million. Later in March 2014, Sempra Renewables sold a 50-percent equity interest in Copper Mountain Solar 3 to Consolidated Edison Development (ConEdison Development). Sempra Renewables’ interest in Copper Mountain Solar 3 is now accounted for under the equity method and its long-term debt was deconsolidated upon the sale. Sempra Renewables received $66 million in net cash from the sale. In May 2014, Sempra Renewables invested $109 million to become a 50-percent partner with ConEdison Development in four solar projects in California (the California solar partnership), as we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Natural Gas

We expect Sempra Natural Gas to require funding for the development and expansion of its portfolio of projects, which may be financed through a combination of operating cash flow and funding from the parent. In January 2014, management approved a plan to sell the remaining 625-MW block of the Mesquite Power plant. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining block of the Mesquite Power plant to ArcLight Capital Partners, LLC. We anticipate the sale will close late in 2014 or early in 2015, subject to customary regulatory approvals and the assignment of an associated 25-year power sales contract to the buyer. Sempra Natural Gas also plans to develop a natural gas liquefaction export facility at its Cameron LNG terminal. The majority of the liquefaction project is project-financed for 16 years 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), with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. On October 1, 2014, the effective date of the formation of the joint venture, we contributed our share of equity to the joint venture through the contribution of Cameron LNG at its historical value. We also expect to contribute our share of cash generated from the first two liquefaction trains as each achieves commercial operations in 2018. As of October 1, 2014, Sempra Natural Gas will begin accounting for its investment in the joint venture under the equity method.

On August 6, 2014, Sempra Energy and the project partners, comprised of affiliates of GDF SUEZ S.A., Mitsui & Co., Ltd., and Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha (NYK)), executed the project financing documents. Under the financing agreements, Sempra Energy signed a completion guarantee for 50.2 percent of the debt, which corresponds to $3.7 billion of the total $7.4 billion principal amount of the debt committed under the financing agreements. The project financing and completion guarantee became effective on October 1, 2014, the effective date of the joint venture formation. The completion guarantee will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. The completion guarantee is anticipated to be terminated in the second half of 2019.

We discuss the Cameron LNG joint venture further in Notes 11 and 13 of the Notes to Condensed Consolidated Financial Statements herein.

Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash or other acceptable collateral to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when the fair value of the contract with our counterparty exceeds established thresholds. We have neither collateral posted nor owed to counterparties at September 30, 2014 pursuant to these requirements.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2014		2014 Change				Nine months ended September 30, 2013
Sempra Energy Consolidated	$	1,661	$	331	25	%	$	1,330
SDG&E		821		312	61			509
SoCalGas		596		109	22			487

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy increased in 2014 primarily due to:

$243 million increase in net undercollected regulatory balancing accounts in 2014 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $344 million increase in 2013. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below;

$243 million decrease in accounts receivable in 2014 compared to an $85 million decrease in 2013; the 2014 decrease was mainly due to a $292 million decrease at SoCalGas, primarily due to colder than normal weather in the fourth quarter of 2013 resulting in higher customers’ account receivable balances as of December 31, 2013 being collected in early 2014;

§	$52 million increase in accounts payable in 2014 compared to a $99 million decrease in 2013, mainly due to a decrease in 2013 related to natural gas purchased at SoCalGas; and

§	a $79 million decrease in settlement payments and associated legal fees for wildfire claims at SDG&E in 2014 compared to 2013; offset by

§	$211 million increase in inventory in 2014 compared to an $87 million increase in 2013; the 2014 increase was mainly due to a $153 million increase at SoCalGas, primarily due to higher storage volume and higher gas prices; and

§	$48 million higher income tax payments in 2014 compared to 2013, primarily due to an $81 million tax payment by IEnova related to Mexican tax reform legislation passed in December 2013.

SDG&E

Cash provided by operating activities at SDG&E increased in 2014 primarily due to:

$38 million increase in net undercollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to a $213 million increase in 2013. The impact of the change in the regulatory balancing accounts on cash provided by operating activities was primarily due to:

□	$121 million decrease in 2014 in the undercollected balance for amounts collected related to the adoption of the 2012 GRC compared to an increase in the undercollected balance in 2013 of $145 million, offset by

□	$33 million increase in 2014 in the undercollected balance for electric transmission compared to a $28 million decrease in the undercollected balance in 2013, and

□	$33 million increase in 2014 in the undercollected natural gas transportation balancing accounts compared to a $28 million decrease in the undercollected balance in 2013;

§	a $79 million decrease in settlement payments and associated legal fees for wildfire claims in 2014 compared to 2013; and

§	a $46 million decrease in accrued compensation and benefits in 2013.

SoCalGas

Cash provided by operating activities at SoCalGas increased in 2014 primarily due to:

$292 million decrease in accounts receivable in 2014 compared to a $192 million decrease in 2013, primarily due to colder than normal weather in the fourth quarter of 2013 resulting in higher customers’ account receivable balances as of December 31, 2013 being collected in early 2014 compared to warmer than normal weather in the fourth quarter of 2012 resulting in lower customers’ account receivable balances as of December 31, 2012 being collected in early 2013;

§	$14 million decrease in accounts payable in 2014 compared to a $110 million decrease in 2013;

§	$57 million higher net income, adjusted for noncash items included in earnings, in 2014 compared to 2013; and

§	$47 million lower income tax payments in 2014 compared to 2013; offset by

§	$205 million increase in net undercollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to $130 million decrease in net overcollected balances in 2013, primarily due to:

□	$229 million increase in 2014 in the undercollected balance associated with the fixed cost balancing accounts compared to an increase of $105 million in 2013, and

□	$22 million increase in 2013 in the overcollected balance associated with the advanced metering infrastructure balancing account, offset by

□	$39 million decrease in 2014 in the undercollected balance related to the retroactive application of the 2012 GRC compared to a $39 million increase in 2013; and

$153 million increase in inventory in 2014 compared to a $26 million increase in 2013, primarily due to higher volume of natural gas added to storage in 2014 as compared to 2013 as a result of colder than normal weather in the fourth quarter of 2013, which left a lower volume of natural gas in storage at the end of 2013 compared to the end of 2012, combined with higher gas prices in 2014.

The table below shows the contributions to pension and other postretirement benefit plans.

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Nine months ended September 30, 2014
			Other
	Pension		Postretirement
	Benefits		Benefits
Sempra Energy Consolidated	$	95	$	14
SDG&E		28		12
SoCalGas		39		―

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Nine months ended						Nine months ended
	September 30, 2014		2014 Change				September 30, 2013
Sempra Energy Consolidated	$	(2,466)	$	1,565	174	%	$	(901)
SDG&E		(796)		118	17			(678)
SoCalGas		(1,045)		541	107			(504)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2014 primarily due to:

§	$535 million increase in capital expenditures;

§	$371 million of proceeds received in 2013 from Sempra Natural Gas’ sale of a 625-MW block of its Mesquite Power plant;

§	$185 million invested in Sempra Renewables’ joint venture partnerships in 2014, as we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements herein;

§	$238 million U.S. Treasury grant proceeds received in 2013;

§	$74 million higher proceeds in 2013 from sales of equity interests in wind and solar projects at Sempra Mexico and Sempra Renewables, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein; and

§	$71 million in loans from IEnova to its joint venture with PEMEX.

SDG&E

Cash used in investing activities at SDG&E increased in 2014 primarily due to a $111 million increase in capital expenditures.

SoCalGas

Cash used in investing activities at SoCalGas increased in 2014 due to:

§	$298 million increase in advances to Sempra Energy; and

§	$243 million increase in capital expenditures.

ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS

The amounts and timing of capital expenditures are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC and the FERC. However, in 2014, we expect to make annual capital expenditures and investments of approximately $3.2 billion. These expenditures include

§	$2.2 billion at the California Utilities for capital projects and plant improvements ($1.1 billion at each of SDG&E and SoCalGas)

§	$1.0 billion at our other subsidiaries for capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects

The California Utilities’ 2014 planned capital expenditures and investments include

§	$610 million for improvements to SDG&E’s natural gas and electric distribution systems

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

§	$120 million at SDG&E for substation expansions (transmission)

§	$90 million for SDG&E’s electric generation plants and equipment

§	$880 million for improvements to SoCalGas’ distribution, transmission and storage systems, and for pipeline safety

§	$220 million for SoCalGas’ advanced metering infrastructure

§	$20 million for SoCalGas’ other natural gas projects

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

In 2014, the expected capital expenditures and investments of approximately $1 billion (excluding amounts expended by joint ventures and net of anticipated project financing and joint venture structures as noted below) at our other subsidiaries include

Sempra South American Utilities

§	approximately $150 million to $200 million for capital projects in South America (approximately $100 million to $150 million in Peru and approximately $50 million in Chile)

Sempra Mexico

§	approximately $300 million to $350 million for capital projects in Mexico, net of project financing, including approximately $300 million for the development of the Sonora Pipeline project developed solely by Sempra Mexico

Sempra Renewables

The following amounts are net of anticipated project financing undertaken by Sempra Renewables, and exclude expenditures within joint venture structures:

§	approximately $250 million for the development of renewable projects, including

□	approximately $100 million for investment in Copper Mountain Solar 3, a 250-MW solar project located near Boulder City, Nevada

□	approximately $100 million for investment in the California solar partnership with ConEdison Development that we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements herein

□	approximately $50 million for investment in the 75-MW Broken Bow 2 Wind project in Custer County, Nebraska

Sempra Natural Gas

§	approximately $180 million for development of LNG and natural gas transportation and storage projects, net of anticipated joint venture partner reimbursements

Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of AFUDC related to debt, but exclude the portion of AFUDC related to equity. At Sempra Mexico, the amounts also exclude AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	Nine months ended				Nine months ended
	September 30, 2014		2014 Change		September 30, 2013
Sempra Energy Consolidated	$	572	$	415	$	157
SDG&E		(19)		(268)		249
SoCalGas		447		498		(51)

Sempra Energy Consolidated

Cash provided by financing activities at Sempra Energy increased in 2014 primarily due to:

$1.7 billion higher issuances of debt, including an increase in issuances of long-term debt of $620 million ($1.7 billion in 2014 compared to $1.1 billion in 2013) and an increase in commercial paper and other short-term debt with maturities greater than 90 days of $1 billion ($1.4 billion increase in 2014 compared to $350 million in 2013); offset by

§	$574 million net proceeds received in 2013 from the sale of noncontrolling interests at Sempra Mexico;

$401 million higher payments on debt, including higher payments of long-term debt of $444 million ($1.1 billion in 2014 compared to $688 million in 2013), offset by lower payments of commercial paper and other short-term debt with maturities greater than 90 days of $43 million ($713 million in 2014 compared to $756 million in 2013);

§	$111 million decrease in short-term debt in 2014 compared to an $81 million increase in 2013; and

§	$56 million higher distributions to noncontrolling interests in 2014.

SDG&E

The change in cash from financing activities at SDG&E was primarily due to:

§	$350 million lower issuance of long-term debt in 2014; and

§	$59 million decrease in short-term debt in 2014; offset by

§	$161 million lower payments on long-term debt in 2014.

SoCalGas

At SoCalGas, financing activities were a net source of cash in 2014 compared to a use of cash in 2013, primarily due to:

§	$747 million net proceeds from the issuance of long-term debt in 2014; and

§	$50 million common dividends paid in 2013; offset by

§	$250 million payment of long-term debt in 2014; and

§	$42 million decrease in short-term debt in 2014.

COMMITMENTS

We discuss significant changes to contractual commitments at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first nine months of 2014. In January 2014, Moody’s increased SDG&E’s and SoCalGas’ unsecured debt rating to A1 with a stable outlook.

Our credit ratings may affect the rates at which borrowings bear interest and of commitment fees on available unused credit. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

FACTORS INFLUENCING FUTURE PERFORMANCE

CALIFORNIA UTILITIES

Overview

The California Utilities’ operations have historically provided relatively stable earnings and liquidity.

The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss in various sections of this report and below. We discuss certain regulatory matters below and in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Joint Matters

Natural Gas Pipeline Operations Safety Assessments

Pending the outcome of the various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur incremental expense and capital investment associated with its natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, Pacific Gas and Electric Company (PG&E) and Southwest Gas filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. In their 2011 filing with the CPUC, the California Utilities estimated the total cost for Phase 1 of the two-phase plan to be $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E) over the 10-year period of 2012 to 2022. As a result of on-going review since this original filing, the California Utilities have been able to eliminate over two hundred miles of pipeline from the testing scope and have revised their total estimated cost for Phase 1 to $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery. The costs that are the subject of these plans were outside the scope of the 2012 General Rate Case proceedings concluded in 2013.

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

§	approved the utilities’ model for implementing PSEP;

§	approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and

§	established the criteria to determine the amounts that would not be eligible for cost recovery, including:

▢	certain costs incurred or to be incurred searching for pipeline test records,

▢	the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and

▢	any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

In July 2014, the CPUC Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In early August 2014, the California Utilities filed their response to the application for rehearing objecting to the assertions by the ORA and TURN. The CPUC is not obligated to act on the application for rehearing by a certain date. The California Utilities are continuing to implement PSEP in accordance with the June 2014 decision.

If the CPUC were to decide as part of any future reasonableness review that rate recovery not be allowed for certain gas pipeline safety costs incurred by SDG&E and SoCalGas, or if the CPUC were to decide in favor of the ORA/TURN joint application for rehearing, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects in implementing the PSEP.

We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

Safety Enforcement

California Senate Bill (SB) 291, enacted in October 2013, requires the CPUC to develop and implement a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegating citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. SB 291 requires the CPUC to implement the enforcement program for gas safety by July 1, 2014 and for electric safety by January 1, 2015. In exercising the citation authority, the CPUC staff will take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation, and the degree of culpability. The CPUC is planning to adopt an administrative limit on the maximum monetary penalty that may be set by the CPUC staff.

In May 2014, the CPUC initiated a rulemaking proceeding to develop the necessary enforcement programs pursuant to the requirements of SB 291. We expect a CPUC decision on the electric safety enforcement program in the fourth quarter of 2014 and a CPUC decision making further refinements to the electric and gas safety enforcement programs in 2015.

In December 2011, the CPUC adopted a gas safety citation program whereby natural gas distribution companies can be fined by CPUC staff for violations of the CPUC’s safety standards or federal standards. Each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. In September 2013, the CPUC’s safety and enforcement division issued its Standard Operating Procedures setting forth its principles and management process for the natural gas safety citation program.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees total approximately $2.4 billion, which is in excess of the $1.1 billion of liability insurance coverage and the approximately $824 million recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. At September 30, 2014, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $371 million in Other Regulatory Assets (long-term), of which $357 million is related to CPUC-regulated operations and $14 million is related to FERC-regulated operations, for costs incurred and the estimated settlement of pending claims. However, SDG&E’s cash flow may be materially adversely affected by timing differences between the resolution of claims and recoveries in rates, which may extend over a number of years. In addition, recovery in rates will require future regulatory approval, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations.

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

Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E will record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at September 30, 2014, the resulting after-tax charge against earnings would have been up to approximately $210 million. In addition, in periods following any such conclusion by SDG&E that recovery is no longer probable, Sempra Energy’s and SDG&E’s earnings will be adversely impacted by increases in the estimated costs to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information concerning these matters in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SONGS

We discuss regulatory and other matters related to SONGS in the Notes to Condensed Consolidated Financial Statements herein as follows:

In Note 9:

§	SONGS Outage and Retirement

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

§	Nuclear Regulatory Commission Proceedings

§	Nuclear Decommissioning and Funding

§	Nuclear Decommissioning Trusts

In Note 11:

§	Lawsuit Against Mitsubishi Heavy Industries, Ltd.

§	Nuclear Insurance

§	Department of Energy Nuclear Fuel Disposal

We also discuss SONGS in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in the Rim Rock wind farm project. SDG&E and the project developer are in dispute regarding whether all conditions precedent in the contribution agreement have been achieved by the developer of the project. As a result, SDG&E has not made the investment, and the project developer and SDG&E are in dispute regarding SDG&E’s contractual obligation to invest in the project, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Electric Rate Reform – State of California Assembly Bill 327

In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This new law restores the authority to establish electric residential rates for electric utility companies in California to the CPUC and removes the rate caps established in AB 1X adopted in early 2001 during California’s energy crisis, as well as SB 695 adopted in 2009. Additionally, the bill provides the CPUC the authority to adopt up to a $10.00 monthly fixed charge for all non-CARE (California Alternative Rates for Energy) residential customers and up to a $5.00 monthly fixed charge for CARE customers. Beginning January 1, 2016, the maximum allowable fixed charge may be adjusted by no more than the annual percentage increase in the Consumer Price Index for the prior calendar year. In February 2014, SDG&E filed comprehensive proposals with the CPUC that provide a roadmap to reforming electric residential rate design beginning in 2015 and continuing through 2018, consistent with the provisions of AB 327. We expect a CPUC decision in the first half of 2015.

In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing net energy metering (NEM) program, pursuant to the provisions of AB 327, which require the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of Senate Bill 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of 1 megawatt or less may choose to participate in the NEM program. Under NEM, customer-generators receive a full retail-rate bill credit for the power they generate that is fed back to the utility’s power grid during times when the customer’s generation exceeds their own energy usage.

Meaningful rate reform is necessary to ensure that SDG&E is authorized to recover its costs in providing services to NEM customers due to, among other issues, the increased power supply from renewable energy sources and the growth in distributed and local power generation. If the CPUC fails to reform SDG&E’s rate structures to allow it to recover costs associated with the services provided to NEM customers and maintain competitive and affordable electric rates for all customers by adopting both fixed and variable rate components, such failure could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects. For additional discussion, see “Risk Factors” in the Annual Report.

Industry Developments and Capital Projects

We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect the California Utilities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA INTERNATIONAL

As we discuss in “Cash Flows From Investing Activities,” our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in “Capital Resources and Liquidity” herein and in the “Capital Resources and Liquidity” and “Factors Influencing Future Performance” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Sempra South American Utilities

Overview

In April 2011, Sempra South American Utilities increased its investment in two utilities in South America, Chilquinta Energía and Luz del Sur. In connection with our increased interests in these utilities, Sempra Energy has $854 million in goodwill on its Condensed Consolidated Balance Sheet at September 30, 2014. Goodwill is subject to impairment testing, annually and under other potential circumstances, which may cause its fair value to vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. We discuss the acquisition in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra South American Utilities is also expected to provide earnings from construction projects when completed and from other investments, but will require substantial funding for these investments.

Sempra South American Utilities has historically provided relatively stable earnings and liquidity, and its performance will depend primarily on the ratemaking and regulatory process, environmental regulations, foreign currency rate fluctuations and economic conditions.

Revenues at Chilquinta Energía are based on tariffs set by the National Energy Commission (Comisión Nacional de Energía, or CNE) every four years. Rates for four-year periods related to distribution and sub-transmission are reviewed separately on an alternating basis every two years. In late 2011, Chilquinta Energía initiated the process to establish its distribution rates for the period from November 2012 to October 2016. This process was completed in November 2012, with rates published in April 2013, and tariff adjustments going into effect retroactively from November 2012. This resulted in a 3.2 percent decrease in rates.

In April 2013, the CNE completed the process to establish sub-transmission rates for the period January 2011 to December 2014, with tariff adjustments going into effect retroactively from January 2011. This resulted in immaterial changes in rates. The review process for sub-transmission rates for the period of January 2015 to December 2018 is expected to be completed during the second quarter of 2015, with tariff adjustment going into effect in January 2015. However, there is a proposal in the congress that will grant the energy commission the right to extend, for one time only, the current sub-transmission period to December 2015, which approval is expected before year-end.

The next reviews are scheduled to be completed, with tariff adjustments also going into effect, in January 2015 for sub-transmission, and again for distribution in November 2016.

Luz del Sur serves primarily regulated customers in Peru and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN). The rates are reviewed and adjusted every four years. OSINERGMIN’s final distribution rate setting resolution for the 2013-2017 period was published in October 2013 and went into effect on November 1, 2013. There was no material change in the rates.

In September 2014, tax reform legislation was passed in Chile. The main amendments established in the tax reform include, among others, a gradual increase in the corporate income tax rate and the introduction of two options to pay the secondary tax (shareholder tax) on corporate profits (either immediate payment of tax or deferment of tax until earnings are distributed) with different impacts to the total income tax burden. We discuss this tax reform above in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes.”

Santa Teresa

Luz del Sur is in the final stages of construction of Santa Teresa, a 100-MW hydroelectric power plant in Peru’s Cusco region. It is now scheduled to be completed in the first half of 2015.

Transmission Projects

Chilquinta Energía. Chilquinta Energía has entered into two 50-percent owned joint ventures, Eletrans S.A. and Eletrans II S.A., with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct transmission lines in Chile.

In May 2012, Eletrans S.A. was awarded two 220-kilovolt (kV) transmission lines in Chile. The transmission lines will extend 150 miles, and we estimate the projects will cost approximately $150 million in total and be completed in 2016 and 2017.

In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 70 miles, and we estimate the projects will cost approximately $80 million and be completed in 2018.

The projects will be financed by the joint venture partners. Other financing may be pursued upon completion of the projects.

Luz del Sur. Luz del Sur has received regulatory approval for an amended transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima. We estimate that the project will cost approximately $150 million and be in service in 2016 and 2017 as portions are completed. Once in operation, the capitalized cost will earn the regulated return for 30 years. The project will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.

Sempra Mexico

Overview

Sempra Mexico is expected to provide earnings from construction projects when completed and from other investments. We expect projects in Mexico to be funded through a combination of available funds (the proceeds from IEnova’s debt and equity offerings in early 2013), funds internally generated by the Mexico businesses, securities issuances, project financing, and partnering in joint ventures. We discuss the debt offering further in Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report.

In March 2013, Sempra Mexico sold common shares of IEnova in a private placement in the U.S. and outside of Mexico and, concurrently, in a registered public offering in Mexico, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein. The shares sold represent approximately 18.9 percent of the ownership interests in IEnova, which reduce our earnings from Sempra Mexico and have a dilutive effect on our earnings per share. The earnings attributable to IEnova’s noncontrolling interests were $34 million for the nine months ended September 30, 2014.

In June and August 2014, IEnova entered into three-year term corporate revolving credit facility agreements for $200 million and $100 million, respectively, to finance working capital and for other general corporate purposes. IEnova drew down $40 million in July 2014 and $105 million in August 2014 from the first facility. We discuss the credit facilities further in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

We discuss the impact of Mexican tax reform in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Pipeline Projects

In October 2012, Sempra Mexico was awarded two contracts by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) to build and operate an approximately 500-mile pipeline network (Sonora Pipeline) to transport natural gas from the U.S.-Mexico border south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa along the Gulf of California. The network will be comprised of two segments that will interconnect to the U.S. interstate pipeline system. We estimate it will cost approximately $1 billion. The first segment of the project, approximately 300 miles, was completed in October 2014, and we expect to complete the remaining segment in the second half of 2016. The capacity is fully contracted by CFE under two 25-year contracts denominated in U.S. dollars.

In December 2012, through its joint venture with PEMEX, the Mexican state-owned oil company, Sempra Mexico executed an ethane transportation services agreement with PEMEX to construct and operate an approximately 140-mile pipeline (Ethane Pipeline) to transport ethane from Tabasco, Mexico to Veracruz, Mexico. We estimate it will cost approximately $330 million and be funded by the joint venture without additional capital contributions from the partners. It is expected to be completed in the first half of 2015. PEMEX has fully contracted the capacity under a 21-year contract denominated in U.S. dollars.

In January 2013, PEMEX announced that the first phase of the Los Ramones pipeline project was assigned to and will be developed by our joint venture with PEMEX. The project is a 70-mile natural gas pipeline (Los Ramones I) from the northern portion of the state of Tamaulipas bordering the United States to Los Ramones in the Mexican state of Nuevo León. The capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate. The project is scheduled to begin operations at the end of 2014.

In addition, in 2014, our joint venture with PEMEX and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 275 miles and two compression stations, which will connect with the first phase of Los Ramones and run to the vicinity of San Luis Potosi, with an estimated cost of approximately $1.3 billion to $1.5 billion. Our joint venture with PEMEX has a 50-percent interest in the project. In June 2014, the project executed an engineering, procurement and construction contract with a consortium formed by Arendal, S. de R.L. de C.V., Construtora Norberto Odebrecht S.A., and Techint, S.A. de C.V., and in July 2014, the project issued the full notice to proceed. We expect expenditures for the project to be funded by the joint venture’s cash flows from operations and project financing, plus additional contributions from its partners. Any additional contributions from partners will depend on the amount of project financing obtained. The pipeline’s capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate.

Energía Sierra Juárez

In April 2011, SDG&E entered into a 20-year contract for up to 155 MW of renewable power supplied from the first phase of Sempra Mexico’s Energía Sierra Juárez wind generation project in Baja California, Mexico. The contract was approved by the CPUC in March 2012 and by the FERC in July 2012. In October 2013, Sempra Mexico issued full notice to proceed to the construction contractor.

In June 2014, the Energía Sierra Juárez wind project entered into an 18-year, $240 million loan to project finance the construction and drew down $82 million from the loan, as we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. The loan agreement also provides for a $31.7 million letter of credit facility. Energía Sierra Juárez also entered into a separate Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project.

In July 2014, after obtaining the required regulatory approvals in Mexico and the U.S., we consummated the sale of a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. for $24 million, net of $2 million cash sold, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. Upon consummation of the sale, the indebtedness under the credit facilities was deconsolidated.

SEMPRA U.S. GAS & POWER

Sempra Renewables

Overview

Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with utilities. The renewable energy projects have planned in-service dates through 2016. These projects require construction financing, which may come from a variety of sources including operating cash flow, project financing, funds from the parent, partnering in joint ventures and, potentially, other forms of equity sales. The varying costs of these alternative financing sources impact the projects’ returns.

Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as Renewables Portfolio Standards (RPS). Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions.

Copper Mountain Solar

Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. When fully developed, the project will be capable of producing up to approximately 550 MW of solar power; it is being developed in multiple phases as power sales become contracted. Copper Mountain Solar is comprised of four separate projects. Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, which includes the 10-MW facility previously referred to as El Dorado Solar. PG&E has contracted for all of the solar power at Copper Mountain Solar 1 for 20 years.

Copper Mountain Solar 2 began construction in December 2011 and will total 150 MW when completed. Copper Mountain Solar 2 is divided into two phases, with the first phase of 92 MW placed in service in November 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at Copper Mountain Solar 2 for 25 years. In July 2013, we completed the sale of 50 percent of our equity in Copper Mountain Solar 2 to ConEdison Development as we discuss in Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements in the Annual Report and Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Copper Mountain Solar 3 started construction in March 2013 and will total 250 MW when completed. Copper Mountain Solar 3 will be placed in service as each of the ten blocks of solar panels is installed and is planned to be entirely in service in 2015. The cities of Los Angeles and Burbank have contracted for all of the solar power at Copper Mountain Solar 3 for 20 years. In addition to solar power, the power sales agreement provides the cities of Los Angeles and Burbank the option to purchase the Copper Mountain Solar 3 facility at years 10, 15 and 20 of the contract term, or upon earlier termination of the agreement. In March 2014, we completed the sale of 50 percent of our equity in Copper Mountain Solar 3 to ConEdison Development, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

In July 2014, Sempra Renewables signed a 20-year power sale agreement with Southern California Edison for all of the solar power from Copper Mountain Solar 4 beginning in 2020. We expect Copper Mountain Solar 4 to be in service in 2016, marketing its output prior to the commencement of the power sale agreement. Copper Mountain Solar 4 will total 94 MW when completed. The power sale agreement is subject to approval by the CPUC.

Mesquite Solar

Mesquite Solar is a photovoltaic generation facility under development by Sempra Renewables in Maricopa County, Arizona. If fully developed, the project will be capable of producing up to approximately 700 MW of solar power. Construction on the first phase (Mesquite Solar 1) of 150 MW was completed in December 2012. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years. In September 2013, we completed the sale of 50 percent of our equity in Mesquite Solar 1 to ConEdison Development as we discuss in Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements in the Annual Report and Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Broken Bow 2 Wind Project

In September 2013, Sempra Renewables acquired the rights to develop the Broken Bow 2 Wind project in Custer County, Nebraska. Sempra Renewables began construction on the 75-MW wind farm in 2013, and we achieved commercial operation in October 2014. Nebraska Public Power District has contracted for all of the wind energy from the project for 25 years. In October 2014, Sempra Renewables completed a private offering of an aggregate of $72 million in principal amount of 4.82-percent fixed-rate notes maturing in 2039. Proceeds from this offering were used to finance this project. Sempra Renewables intends to operate the project within the framework of a joint venture.

California Solar Partnership with ConEdison Development

In May 2014, Sempra Renewables and ConEdison Development consummated an agreement to partner in four solar projects in California. The joint venture includes ConEdison Development’s CED California Holdings, LLC portfolio, which consists of the 50-MW Alpaugh 50, the 20-MW Alpaugh North and the 20-MW White River 1 facilities in Tulare County, and the 20-MW Corcoran 1 facility in Kings County. The renewable power from all of the projects has been sold under long-term contracts. Sempra Renewables and ConEdison Development each own a 50-percent interest in the four fully operating solar facilities. We discuss the joint venture further in Note 4 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Natural Gas

Mesquite Power Natural Gas-Fired Plant

In June 2011, Sempra Natural Gas entered into a 25-year power contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada. The contract was expanded to a total of 271 MW in February 2013. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power from its Mesquite Power plant or other sources delivered to the Palo Verde hub beginning in January 2015.

In February 2013, Sempra Natural Gas completed the sale of one 625-MW block of its Mesquite Power plant to the Salt River Project Agricultural Improvement and Power District for $371 million in cash. Sempra Natural Gas retained ownership of the second 625-MW block of the Mesquite Power plant that will support the contract with the participating SPPR Group members.

In January 2014, management approved a plan to market and sell the remaining 625-MW block of the plant. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining 625-MW block of the Mesquite Power plant and SPPR contract to ArcLight Capital Partners, LLC. We anticipate the sale will close late in 2014 or early in 2015, subject to customary regulatory approvals and assignment of the contract with the SPPR Group to the buyer. We discuss the plan to sell the second 625-MW block of Mesquite Power in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Rockies Express

Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (Rockies Express), a partnership that operates a natural gas pipeline, the Rockies Express Pipeline (REX), which links the Rocky Mountains region to the upper Midwest and the eastern United States. All of REX’s original capacity sales provide for west-to-east service. Sempra Rockies Marketing, a subsidiary of Sempra Natural Gas, has an agreement for such capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013. Contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express.

In November 2013, FERC issued a decision ruling that east-to-west service offerings within a single REX rate zone would not result in potential rate reductions under provisions in the original customers’ west-to-east contracts (“most favored nation” provisions). In December 2013, certain west-to-east customers sought rehearing of that decision. The triggering of these provisions would result in significantly reduced revenue to REX from these west-to-east contracts.

In April 2014, prior to the launching of an open season, Rockies Express had secured binding financial commitments with four shippers totaling 1.2 billion cubic feet (Bcf) per day of capacity for east-to-west transportation services at a rate of $0.50 per dekatherm for a term of twenty years originating at or near Clarington, Ohio. We expect the capacity to be in service by mid-2015. In June 2014, Rockies Express finished constructing the Seneca lateral, an initial 0.25 Bcf per day capacity project that connects natural gas production sources in Ohio to REX, with further plans to expand the lateral’s capability to 0.6 Bcf per day of capacity by the end of 2014. The lateral is fully contracted through September 2021. Rockies Express has also conducted a non-binding open season to assess interest in further expansion of its facilities for east-to-west service. Further expansion of east-to-west capacity would require additional capital investment.

Our carrying value in Rockies Express at September 30, 2014 is $342 million. We recorded noncash, after-tax impairment charges totaling $239 million in 2012 to write down our investment in the partnership. We discuss our investment in Rockies Express and the impairment charges in Notes 4 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Storage

Our natural gas storage assets include operational and development assets at Bay Gas in Alabama and Mississippi Hub in Mississippi, as well as our development project, LA Storage in Louisiana. LA Storage could be positioned to support LNG export from Cameron and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values.

Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at Bay Gas and Mississippi Hub, replacement sales contract rates could be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. In addition, our LA Storage development project may be unable to attract cash flow commitments sufficient to support further investment, or unable to extend its FERC construction permit beyond its expiration date of June 2015. These market conditions could result in the need to perform recovery testing of our recorded asset values. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent excess book value over fair value is indicated, an impairment charge would be required to be recorded. The book value of our equity in natural gas storage assets at September 30, 2014 is $1.3 billion, excluding intercompany loans to the projects totaling $200 million.

After placing additional capacity in service at Bay Gas and Mississippi Hub in June 2014, Sempra Natural Gas has 42 Bcf of operational working natural gas storage capacity (20 Bcf at Bay Gas and 22 Bcf at Mississippi Hub). Sempra Natural Gas may, over the long term, develop as much as 76 Bcf of total storage capacity at all of its facilities.

Sempra Natural Gas’ natural gas storage facilities and projects include

Bay Gas, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Natural Gas owns 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.

§	Mississippi Hub, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.

§	LA Storage, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.

Cameron Liquefaction Project

The Cameron liquefaction project will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. In January 2012, the Department of Energy (DOE) approved Cameron LNG’s application for authorization to export LNG to Free Trade Agreement countries.

In 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. to develop a natural gas liquefaction export facility at the Cameron LNG terminal. The Cameron liquefaction project is comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.5 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Upon receipt of all necessary permitting and regulatory approvals, construction commenced in 2014, which should allow us to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $7 billion, which includes the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, and excludes capitalized interest and other financing costs. The majority of the incremental investment will be project-financed and the balance provided by the project partners through the joint-venture agreements we discuss below. We discuss the construction contract further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. The total cost of the facility, including the cost of our original facility plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion.

In May 2013, we signed a joint venture agreement with affiliates of GDF SUEZ S.A., Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha (NYK)), and Mitsui & Co., Ltd. each to acquire 16.6 percent indirect equity in Cameron LNG, and for Sempra Energy to retain a 50.2-percent indirect interest in the joint venture. As we discuss below, on October 1, 2014, we contributed our share of equity to the joint venture through the contribution of Cameron LNG. We also expect to contribute our share of cash generated from each liquefaction train as it comes on line. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash.

The commercial development agreements executed in 2012 bind the parties to fund certain development costs, including design, permitting and engineering, as well as to negotiate in good faith 20-year tolling agreements, based on agreed-upon key terms outlined in the commercial development agreements. In May 2013, we signed 20-year liquefaction and regasification tolling capacity agreements with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. which subscribe the full nameplate capacity of the facility. Each tolling agreement is for 4.5 Mtpa of capacity to enable 4.0 Mtpa of LNG export.

In June and November 2013, Sempra Natural Gas signed agreements totaling 1.45 Bcf per day of firm natural gas transportation service to Cameron LNG on the Cameron Interstate Pipeline (subject to effectiveness of the liquefaction and regasification tolling capacity agreements) with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.

On February 11, 2014, the DOE issued an order (Order) granting Cameron LNG, LLC conditional authorization to export from its Cameron liquefaction project approximately 1.7 Bcf per day of domestically produced LNG to countries with which the United States does not have agreements for free trade in natural gas (Non-Free Trade Agreement). The conditional authorization granted in the Order is for a term of 20 years commencing on the earlier of the date of first commercial export or seven years from the date of the Order. Under the terms of the Order, Cameron LNG is authorized to export LNG either on its own behalf or as agent for the customers of the project. In September 2014, the DOE granted the final authorization.

In March 2014, we signed an engineering, procurement and construction (EPC) contract with a joint venture between CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation. The joint venture issued full notice to proceed to the contractor in October 2014. We discuss this contract further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On April 30, 2014, FERC issued the Final Environmental Impact Statement for the project, which concludes that the project would not result in significant environmental impacts, after taking into account mitigation requirements that will be implemented by the Cameron LNG joint venture. On June 19, 2014, Cameron LNG received an order from the FERC authorizing the siting, construction and operation of the three-train liquefaction facility. In the same order, the FERC also authorized Cameron Interstate Pipeline’s 21-mile, 42-inch natural gas pipeline expansion, new compressor station and ancillary equipment that will provide natural gas transportation to the Cameron LNG facility. On July 9, 2014, the FERC issued its initial authorization to commence site preparation activities at the Cameron LNG site.

On August 6, 2014, Sempra Energy and the project partners provided their respective final investment decision with respect to the joint venture. The effective date of the Cameron LNG joint venture, Cameron LNG Holdings, LLC (Cameron LNG Holdings), among Sempra Energy and its project partners occurred on October 1, 2014 after satisfaction of various conditions, including receipt of final regulatory approval and satisfaction of conditions precedent to the first disbursement of the project financing. Beginning from the October 1, 2014 joint venture effective date, Cameron LNG is no longer wholly owned or controlled by Sempra Energy, and is owned 50.2 percent by Sempra Energy and 49.8 percent by the project partners. As of October 1, 2014, Sempra Energy will account for its investment in the joint venture under the equity method.

Also on August 6, 2014, Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG project. Also on August 6, 2014, Sempra Energy entered into a completion guarantee under which Sempra Energy has severally guaranteed 50.2 percent of the debt, or a maximum of $3.7 billion. The project financing and completion guarantee became effective October 1, 2014, the effective date of the joint venture formation, and will terminate upon financial completion of the project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantee to be terminated in the second half of 2019.

At September 30, 2014, Cameron LNG had a terminal services agreement with one customer that required the customer to pay capacity reservation and usage fees to use its Cameron LNG facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG’s EPC contractor on October 9, 2014, we expect this termination date to occur during the first quarter of 2017.

Cameron LNG Holdings is pursuing potential growth projects for the Cameron LNG facility. Under the Cameron LNG financing agreements, expansion of the Cameron LNG facilities beyond the first three trains are subject to certain restrictions and conditions. These restrictions include, among others, certain timing restrictions on expansions of the projects unless appropriate prior consent is obtained from lenders.

We discuss the deconsolidation of Cameron LNG and Sempra Energy’s project financing obligations and guarantee further in Note 13 of the Notes to Condensed Consolidated Financial Statements herein.

RBS Sempra Commodities

In three separate transactions in 2010 and one in early 2011, we and The Royal Bank of Scotland plc (RBS), our partner in the RBS Sempra Commodities joint venture, sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $73 million at September 30, 2014 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities under “Other Litigation” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership. We provide additional information in Note 4 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

OTHER SEMPRA ENERGY MATTERS

We discuss Chilean tax reform in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” herein, and the impacts of the American Taxpayer Relief Act of 2012, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 and the Mexican tax reform legislation passed in December 2013 on our income tax expense, earnings and cash flows in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in the Annual Report.

We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss foreign currency rate risk further under “Foreign Currency Rate Risk” in Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below. North American natural gas prices, which affect profitability at Sempra Renewables and Sempra Natural Gas, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability. However, management expects that future export capability at Sempra Natural Gas’ Cameron LNG facility would benefit from lower gas prices in North America compared to other regions.

In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.

Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

NEW ACCOUNTING STANDARDS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

INTEREST RATE RISK

The table below shows the nominal amount and the one-year Value at Risk (VaR) for long-term debt at September 30, 2014 and December 31, 2013:

NOMINAL AMOUNT AND ONE-YEAR VALUE AT RISK OF LONG-TERM DEBT(1)
(Dollars in millions)
		Sempra Energy
		Consolidated				SDG&E				SoCalGas
		Nominal		One-Year		Nominal		One-Year		Nominal		One-Year
		Debt		VaR(2)		Debt		VaR(2)		Debt		VaR(2)
At September 30, 2014:
	California Utilities fixed-rate	$	6,049	$	396	$	4,136	$	267	$	1,913	$	129
	California Utilities variable-rate		327		11		327		11		―		―
	All other, fixed-rate and variable-rate		5,967		238		―		―		―		―
At December 31, 2013:
	California Utilities fixed-rate	$	5,464	$	531	$	4,051	$	407	$	1,413	$	124
	California Utilities variable-rate		335		15		335		15		―		―
	All other, fixed-rate and variable-rate		6,211		308		―		―		―		―
(1)	Excluding commercial paper classified as long-term debt, capital lease obligations and interest rate swaps, and before reductions/increases for unamortized discount/premium.
(2)	After the effects of interest rate swaps.

We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.

FOREIGN CURRENCY RATE RISK

We discuss our foreign currency exposure at our Mexican subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes – Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity” herein. At September 30, 2014, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2013.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.

Under the supervision and with the participation of management, including the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2014, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, Sempra Energy, SDG&E and SoCalGas continue to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 9, 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in “Management's Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Annual Report.

ITEM 1A. RISK FACTORS

There have not been any material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

EXHIBIT 10 – MATERIAL CONTRACTS
Sempra Energy / San Diego Gas & Electric Company
10.1	Amendment No. 10 to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.

10.2	Amendment No. 11 to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.

10.3	Amendment No. 12 to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.

10.4	Amendment No. 8 to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.

10.5	Amendment No. 9 to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.

10.6	Amendment No. 10 to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 27, 2014.
EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1	Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
San Diego Gas & Electric Company
12.2	San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Southern California Gas Company
12.3	Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

San Diego Gas & Electric Company
31.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES
Sempra Energy:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SEMPRA ENERGY, (Registrant)

Date: November 4, 2014	By: /s/ Trevor I. Mihalik
	Trevor I. Mihalik Senior Vice President, Controller and Chief Accounting Officer

San Diego Gas & Electric Company:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)

Date: November 4, 2014	By: /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Southern California Gas Company:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)

Date: November 4, 2014	By: /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Exhibit 10.1

Exhibit 10.1

AMENDMENT NO. 10

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 10 made this 27^th day of August , 2014, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.12 of the Nuclear Facilities Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:

The third and fourth sentences of Section 4.05 shall be restated as follows:

The Committee, or upon written notice from the Committee, the Trustee, shall assume responsibility for employing independent certified public accountants to audit the financial statements not less frequently than annually, subject to the provisions contained in Section 6.05. The Company and the Committee shall have the right to object to any of the audited financial statements.

The second sentence of the introductory text of Article II shall be restated as follows:

No disbursement or payment may be made from the Master Trust for activities subject to NRC-jurisdiction under section 50.75 until written notice of the intention to make disbursement or payment has been made in accordance with 10 CFR 50.75(h)(1)(iv), or any subsequent NRC requirement.

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 10 upon the terms and conditions hereof and that the individual executing this Amendment No. 10 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

Exhibit 10.2

Exhibit 10.2

AMENDMENT NO. 11

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 11 made this 27^th day of August , 2014, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

NOW, THEREFORE, the Company and the Trustee agree as follows:

The last sentence of Section 3.02 shall be restated as follows:

“Appointments of Committee members may be for less than a five-year term in order to establish staggered membership terms among the members of the Committee.”

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 11 upon the terms and conditions hereof and that the individual executing this Amendment No. 11 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

Exhibit 10.3

Exhibit 10.3

AMENDMENT NO. 12

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 12 made this 27^th day of August , 2014, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

NOW, THEREFORE, the Company and the Trustee agree as follows:

Section 1.01, Definitions shall be amended by inserting the following language as section (1.1) after section (1):

“(1.1)

“Advance Withdrawal Certificate” shall mean a document properly completed and executed by one Authorized Representative of the Company and substantially in the form of Exhibit C-1 hereto.

Section 2.01, Payment of Nuclear Decommissioning Costs, of Article II shall be amended by inserting the following language as sections (4.1) and (4.2):

“(4.1)

Advance Withdrawals for Payment of Decommissioning Costs. An Authorized Representative may request disbursement of funds to pay expected Decommissioning Costs by submitting an Advance Withdrawal Certificate to the Trustee. Requests for advance withdrawals may be made up to one month before expected payments are made. Amounts withdrawn shall be deposited in an interest-bearing account. Interest earned in such account shall be used for paying Decommissioning Costs, and shall not benefit the Company. Any request for withdrawal of funds shall be accompanied by documentation supporting the amount of advance withdrawal, and shall take into account any unexpended, balance of funds previously disbursed. Any funds remaining in such account upon termination of the Master Trust shall be distributed pursuant to Section 2.11.”

“(4.2)

Documentation of Payment of Decommissioning Costs. Actual expenditures for Decommissioning Costs and a reconciliation of advance withdrawals with actual expenditures will be submitted to the CPUC quarterly.”

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 12 upon the terms and conditions hereof and that the individual executing this Amendment No. 12 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

QUALIFIED MASTER TRUST AGREEMENT

EXHIBIT C-1

ADVANCE WITHDRAWAL CERTIFICATE

The undersigned, Authorized Representative of Southern California Edison Company (Company), a California corporation, being duly authorized and empowered to execute and deliver this certificate, hereby certifies to the Trustee of the Southern California Edison Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust for San Onofre and Palo Verde Nuclear Generating Stations, pursuant to Section 2.01 of that certain Master Trust Agreement, dated _______________, as follows:

Within 30 days of the date of this certificate, there will be due and owing to the Company [all] or [a portion of] the cost of goods or services provided in connection with the decommissioning of [SONGS/Palo Verde] as evidenced by the Schedule with supporting exhibits attached as Exhibit 1 hereto;

All such amounts will constitute Decommissioning Costs; and

All conditions precedent to the making of this withdrawal and disbursement and the payment of the Company of the Decommissioning Costs set forth in any agreement between any third-party provider and the company have been fulfilled.

Accordingly, you are hereby authorized to withdraw $_______from the [SONGS Unit No. 1/SONGS Unit No. 2/SONGS Unit No. 3/Palo Verde Unit No. 1, Palo Verde Unit No. 2/Palo Verde Unit No. 3] Qualified Fund of the Master Trust in order to permit payment of such sum to be made to the Company for such purpose. You are further authorized to disburse such sum, once withdrawn, directly to the Company in the following manner: [DESCRIBE: CHECK, WIRE TRANSFER, ETC.] on or before __________________. Executed this _____ day of ______________.

SOUTHERN CALIFORNIA EDISON COMPANY

By____________________________________

Authorized Representative

By_____________________________________

Attest

Exhibit 10.4

Exhibit 10.4

AMENDMENT NO. 8

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 8 made this 27^th day of August , 2014, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.10 of the Nuclear Facilities Non-Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:

The third and fourth sentences of Section 4.05 shall be restated as follows:

The Committee, or upon written notice thereof, the Trustee, shall assume responsibility for employing independent certified public accountants to audit the financial statements not less frequently than annually, subject to the provisions contained in Section 6.05. The Company and the Committee shall have the right to object to any of the audited financial statements.

The second sentence of the introductory text of Article II shall be restated as follows:

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 8 upon the terms and conditions hereof and that the individual executing this Amendment No. 8 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

Exhibit 10.5

Exhibit 10.5

AMENDMENT NO. 9

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 9 made this 27^th day of August , 2014, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

NOW, THEREFORE, the Company and the Trustee agree as follows:

The last sentence of Section 3.02 shall be restated as follows:

“Appointments of Committee members may be for less than a five-year term in order to establish staggered membership terms among the members of the Committee.”

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 9 upon the terms and conditions hereof and that the individual executing this Amendment No. 9 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

Exhibit 10.6

Exhibit 10.6

AMENDMENT NO. 10

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

NOW, THEREFORE, the Company and the Trustee agree as follows:

Section 1.01, Definitions shall be amended by inserting the following language as section (1.1) after section (1):

“(1.1)

“Advance Withdrawal Certificate” shall mean a document properly completed and executed by one Authorized Representative of the Company and substantially in the form of Exhibit C-1 hereto.

Section 2.01, Payment of Nuclear Decommissioning Costs, of Article II shall be amended by inserting the following language as sections (4.1) and (4.2):

“(4.1)

“(4.2)

Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 10 upon the terms and conditions hereof and that the individual executing this Amendment No 10 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.


SAN DIEGO GAS & ELECTRIC COMPANY

By:	/s/ Robert Schlax
Date:	7/31/14
Attest:	/s/ Sylvia Jimenez


THE BANK OF NEW YORK MELLON

By:	/s/ Joseph G. Kirchmeier
Date:	7/29/14
Attest:	/s/ James Mahoney


CALIFORNIA PUBLIC UTILITIES COMMISSION

By:	/s/ Michelle Cooke for PAC
Date:	8/27/14
Attest:	/s/ Carol Mendiola

NON-QUALIFIED MASTER TRUST AGREEMENT

EXHIBIT C-1

ADVANCE WITHDRAWAL CERTIFICATE

The undersigned, Authorized Representative of Southern California Edison Company (Company), a California corporation, being duly authorized and empowered to execute and deliver this certificate, hereby certifies to the Trustee of the Southern California Edison Company Nuclear Facilities Non- Qualified CPUC Decommissioning Master Trust for San Onofre and Palo Verde Nuclear Generating Stations, pursuant to Section 2.01 of that certain Master Trust Agreement, dated _______________, as follows:

All such amounts will constitute Decommissioning Costs; and

Accordingly, you are hereby authorized to withdraw $_______from the [SONGS Unit No. 1/SONGS Unit No. 2/SONGS Unit No. 3/Palo Verde Unit No. 1, Palo Verde Unit No. 2/Palo Verde Unit No. 3] Non-Qualified Fund of the Master Trust in order to permit payment of such sum to be made to the Company for such purpose. You are further authorized to disburse such sum, once withdrawn, directly to the Company in the following manner: [DESCRIBE: CHECK, WIRE TRANSFER, ETC.] on or before __________________. Executed this _____ day of ______________.

SOUTHERN CALIFORNIA EDISON COMPANY

By____________________________________

Authorized Representative

By_____________________________________

Attest

Exhibit 12.1



EXHIBIT 12.1
SEMPRA ENERGY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)

													September 30,
			2009		2010		2011		2012		2013		2014
Fixed charges and preferred stock dividends:
Interest		$	455	$	492	$	549	$	601	$	620	$	470
Interest portion of annual rentals			2		3		2		2		2		2
Preferred dividends of subsidiaries (1)			13		11		10		6		6		1
Total fixed charges			470		506		561		609		628		473
Preferred dividends for purpose of ratio			-		-		-		-		-		-
Total fixed charges and preferred dividends for purpose of ratio		$	470	$	506	$	561	$	609	$	628	$	473
Earnings:
Pretax income from continuing operations before adjustment for income or loss from equity investees		$	977	$	1,078	$	1,747	$	1,255	$	1,399	$	1,148
Add:
Total fixed charges (from above)			470		506		561		609		628		473
Distributed income of equity investees			493		260		96		50		51		39
Less:
Interest capitalized			73		74		27		53		23		23
Preferred dividends of subsidiaries (1)			13		11		10		6		6		1
Total earnings for purpose of ratio		$	1,854	$	1,759	$	2,367	$	1,855	$	2,049	$	1,636
Ratio of earnings to combined fixed charges and preferred stock dividends			3.94		3.48		4.22		3.05		3.26		3.46

Ratio of earnings to fixed charges			3.94		3.48		4.22		3.05		3.26		3.46

(1)	In computing this ratio, “Preferred dividends of subsidiaries” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit 12.2



EXHIBIT 12.2
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)

													September 30,
			2009		2010		2011		2012		2013		2014
Fixed Charges and Preferred Stock Dividends:
Interest		$	118	$	153	$	193	$	220	$	231	$	179
Interest portion of annual rentals			1		1		1		1		1		1
Total fixed charges			119		154		194		221		232		180
Preferred stock dividends (1)			7		7		7		7		5		-
Combined fixed charges and preferred stock dividends for purpose of ratio		$	126	$	161	$	201	$	228	$	237	$	180
Earnings:
Pretax income from continuing operations		$	550	$	531	$	692	$	705	$	626	$	616
Total fixed charges (from above)			119		154		194		221		232		180
Less: Interest capitalized			4		1		1		-		-		-
Total earnings for purpose of ratio		$	665	$	684	$	885	$	926	$	858	$	796
Ratio of earnings to combined fixed charges and preferred stock dividends			5.28		4.25		4.40		4.06		3.62		4.42

Ratio of earnings to fixed charges			5.59		4.44		4.56		4.19		3.70		4.42

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit 12.3



EXHIBIT 12.3
SOUTHERN CALIFORNIA GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)

													September 30,
			2009		2010		2011		2012		2013		2014
Fixed Charges:
Interest		$	74	$	72	$	77	$	77	$	76	$	55
Interest portion of annual rentals			1		2		1		1		1		1
Total fixed charges			75		74		78		78		77		56
Preferred stock dividends (1)			2		2		2		2		2		1
Combined fixed charges and preferred stock dividends for purpose of ratio		$	77	$	76	$	80	$	80	$	79	$	57
Earnings:
Pretax income from continuing operations		$	418	$	463	$	431	$	369	$	481	$	367
Add: Total fixed charges (from above)			75		74		78		78		77		56
Less: Interest capitalized			1		1		1		1		1		-
Total earnings for purpose of ratio		$	492	$	536	$	508	$	446	$	557	$	423
Ratio of earnings to combined fixed charges and preferred stock dividends			6.39		7.05		6.35		5.58		7.05		7.42

Ratio of earnings to fixed charges			6.56		7.24		6.51		5.72		7.23		7.55

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Sempra Energy Ex 31.1

EXHIBIT 31.1

CERTIFICATION

I, Debra L. Reed, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 4, 2014

/s/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Sempra Energy Ex 31.2

EXHIBIT 31.2

CERTIFICATION

I, Joseph A. Householder, certify that:

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

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

November 4, 2014

/s/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

SDG&E Ex 31.3

EXHIBIT 31.3

CERTIFICATION

I, J. Walker Martin, certify that:

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

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

November 4, 2014

/s/ J. Walker Martin

J. Walker Martin

Chief Executive Officer

SDG&E Ex 31.4

EXHIBIT 31.4

CERTIFICATION

I, Robert M. Schlax, certify that:

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

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

November 4, 2014

/s/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

SCG Ex 31.5

EXHIBIT 31.5

CERTIFICATION

I, Dennis V. Arriola, certify that:

I have reviewed this report on Form 10-Q of Southern California Gas Company;

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

November 4, 2014

/s/ Dennis V. Arriola

Dennis V. Arriola

Chief Executive Officer

SCG Ex 31.6

EXHIBIT 31.6

CERTIFICATION

I, Robert M. Schlax, certify that:

I have reviewed this report on Form 10-Q of Southern California Gas Company;

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

November 4, 2014

/s/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

Sempra Energy Ex 32.1

Exhibit 32.1

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2014 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Sempra Energy Ex 32.2

Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:

(i)

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

SDG&E Ex 32.3

Exhibit 32.3

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ J. Walker Martin

J. Walker Martin

Chief Executive Officer

SDG&E Ex 32.4

Exhibit 32.4

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

SCG Ex 32.5

Exhibit 32.5

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ Dennis V. Arriola

Dennis V. Arriola

Chief Executive Officer

PE/SCG Ex 32.8

Exhibit 32.6

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 4, 2014

/s/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer