San Diego Gas & Electric 10-Q 2007 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C.  20549
FORM 10-Q
	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	June 30, 2007
	Commission file number	1-3779
SAN DIEGO GAS & ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
	California	95-1184800
	(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
8326 Century Park Court, San Diego, California 92123
(Address of principal executive offices) (Zip Code)
(619) 696-2000
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

					Yes	X		No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer	[     ]	Accelerated filer			[     ]		Non-accelerated filer				[  X  ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
				Yes					No	X
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common stock outstanding:			Wholly owned by Enova Corporation

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may," "could," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements.

Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional and national economic, competitive, political, legislative and regulatory conditions and developments; actions by the California Public Utilities Commission, the California State Legislature, the California Department of Water Resources, the Federal Energy Regulatory Commission and other environmental and regulatory bodies in the United States; capital markets conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; the availability of natural gas and liquefied natural gas; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory, environmental and legal decisions and requirements; the status of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; the resolution of litigation; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission.

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CONSOLIDATED INCOME

			Three months ended							Six months ended
			June 30,							June 30,
(Dollars in millions)				2007			2006				2007			2006
				(unaudited)
Operating revenues
	Electric		$	518		$	557		$		988		$	1,034
	Natural gas			141			107				380			352
		Total operating revenues		659			664				1,368			1,386
Operating expenses
	Cost of electric fuel and purchased power			163			153				312			363
	Cost of natural gas			86			55				234			209
	Other operating expenses			188			218				366			377
	Depreciation and amortization			75			80				150			147
	Franchise fees and other taxes			36			33				75			66
		Total operating expenses		548			539				1,137			1,162
Operating income				111			125				231			224
Other income (expense), net				(2	)		11				2			13
Interest income				1			(8	)			2			(4	)
Interest expense				(23	)		(24	)			(47	)		(46	)
Income before income taxes				87			104				188			187
Income tax expense				35			38				73			73
Net income				52			66				115			114
Preferred dividend requirements				1			1				2			2
Earnings applicable to common shares			$	51		$	65		$		113		$	112

See Notes to Condensed Consolidated Financial Statements.

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SAN DIEGO GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

			June 30,			December 31,
(Dollars in millions)			2007			2006
			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	42		$	9
	Accounts receivable – trade			187			206
	Accounts receivable – other			31			26
	Interest receivable			--			15
	Due from unconsolidated affiliates			29			24
	Income taxes receivable			--			25
	Deferred income taxes			69			41
	Inventories			105			97
	Regulatory assets arising from fixed-price contracts
		and other derivatives		48			83
	Other regulatory assets			48			69
	Other			63			71
		Total current assets		622			666
Other assets:
	Due from unconsolidated affiliate			5			5
	Deferred taxes recoverable in rates			291			318
	Regulatory assets arising from fixed-price contracts
		and other derivatives		331			353
	Regulatory assets arising from pensions and other
	postretirement benefit obligations			218			220
	Other regulatory assets			50			59
	Nuclear decommissioning trusts			728			702
	Sundry			101			72
		Total other assets		1,724			1,729
Property, plant and equipment:
	Property, plant and equipment			7,877			7,495
	Less accumulated depreciation and amortization			(2,181	)		(2,095	)
		Property, plant and equipment, net		5,696			5,400
Total assets			$	8,042		$	7,795

See Notes to Condensed Consolidated Financial Statements.

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SAN DIEGO GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

				June 30,			December 31,
(Dollars in millions)				2007			2006
				(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Short-term debt			$	30		$	72
	Accounts payable				206			273
	Due to unconsolidated affiliates				14			5
	Income taxes payable				2			--
	Regulatory balancing accounts, net				305			165
	Fixed-price contracts and other derivatives				53			83
	Customer deposits				50			47
	Mandatorily redeemable preferred securities				14			3
	Current portion of long-term debt				33			66
	Other				227			287
			Total current liabilities		934			1,001
Long-term debt					1,645			1,638
Deferred credits and other liabilities:
	Customer advances for construction				35			38
	Pension and other postretirement benefit obligations,      net of plan assets				244			249
	Deferred income taxes				500			520
	Deferred investment tax credits				30			31
	Regulatory liabilities arising from removal obligations				1,333			1,311
	Asset retirement obligations				517			462
	Fixed-price contracts and other derivatives				334			353
	Mandatorily redeemable preferred securities				--			14
	Deferred credits and other				195			184
			Total deferred credits and other liabilities		3,188			3,162
Minority interest					164			--
Commitments and contingencies (Note 8)
Shareholders' equity:
	Preferred stock not subject to mandatory redemption				79			79
	Common stock (255 million shares authorized;
		117 million shares outstanding; no par value)			1,138			1,138
	Retained earnings				908			796
	Accumulated other comprehensive income (loss)				(14	)		(19	)
			Total shareholders' equity		2,111			1,994
Total liabilities and shareholders' equity				$	8,042		$	7,795

See Notes to Condensed Consolidated Financial Statements.

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SAN DIEGO GAS & ELECTRIC COMPANY

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

						Six months ended
						June 30,
(Dollars in millions)							2007			2006
								(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income						$	115		$	114
	Adjustments to reconcile net income to net cash provided
		by operating activities:
					Depreciation and amortization			150			147
					Deferred income taxes and investment tax credits			(24	)		(168	)
					Non-cash rate reduction bond expense			25			28
					Other			--			(1	)
	Net changes in working capital components							113			(41	)
	Changes in other assets							9			3
	Changes in other liabilities							(3	)		(10	)
					Net cash provided by operating activities			385			72
CASH FLOWS FROM INVESTING ACTIVITIES
	Expenditures for property, plant and equipment							(305	)		(723	)
	Purchases of nuclear decommissioning trust assets							(298	)		(298	)
	Proceeds from sales by nuclear decommissioning trusts							300			299
	Increase in loans to affiliates, net							--			(1	)
	Proceeds from sales of assets							2			1
				Net cash used in investing activities				(301	)		(722	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Capital contribution							--			200
	Increase (decrease) in short-term debt, net							(42	)		21
	Issuance of long-term debt							--			250
	Payments on long-term debt							(33	)		(33	)
	Redemptions of preferred stock							(3	)		(3	)
	Preferred dividends paid							(2	)		(2	)
	Other							--			(2	)
			Net cash provided by (used in) financing activities					(80	)		431
Increase (decrease) in cash and cash equivalents								4			(219	)
Cash and cash equivalents, January 1								9			236
Cash assumed in connection with FIN 46(R) consolidation								29			--
Cash and cash equivalents, June 30							$	42		$	17

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION
		Interest payments, net of amounts capitalized	$	43	$	41
		Income tax payments, net of refunds	$	43	$	206

SUPPLEMENTAL SCHEDULE OF NONCASH
	INVESTING ACTIVITY
		Decrease in accounts payable from investments
			in property, plant and equipment	$	(39	)	$	(11	)

See Notes to Condensed Consolidated Financial Statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

Principles of Consolidation

This Quarterly Report on Form 10-Q is that of San Diego Gas & Electric Company (SDG&E or the company). SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy, a California-based Fortune 500 holding company. The accompanying financial statements are the Condensed Consolidated Financial Statements of SDG&E and its subsidiary, SDG&E Funding LLC, and Otay Mesa Energy Center LLC (OMEC LLC), which is being consolidated beginning in the second quarter of 2007 as discussed in Note 3.

Sempra Energy also indirectly owns all of the common stock of Southern California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively referred to as the Sempra Utilities.

Basis of Presentation

The Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (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. 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.

Information in this Quarterly Report should be read in conjunction with the Annual Report on Form 10-K for the year ended December 31, 2006 (the Annual Report) and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007.

The company’s significant accounting policies are described in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The same accounting policies are followed for interim reporting purposes, except for the adoption of new accounting standards as discussed in Note 2.

Other operating expenses include operating and maintenance costs, and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, and outside services.

SDG&E accounts for the economic effects of regulation on utility operations in accordance with Statement of Financial Accounting Standards (SFAS)71, Accounting for the Effects of Certain Types of Regulation.

NOTE 2. NEW ACCOUNTING STANDARDS

Pronouncements that have recently become effective that are relevant to the company and/or have had or may have a significant effect on the company's financial statements are described below.

SFAS 157, "Fair Value Measurements" (SFAS 157): SFAS 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances. The company applies recurring fair value measurements to certain assets and liabilities, primarily nuclear decommissioning trusts and commodity and other derivatives.

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SFAS 157: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 6), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or block discount when measuring instruments traded in an actively quoted market at fair value, and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred. SFAS 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

The provisions of SFAS 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under Emerging Issues Task Force (EITF) Issue No. 02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, (2) existing hybrid financial instruments measured initially at fair value using the transaction price, and (3) blockage factor discounts. Adjustments to these items required under SFAS 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

Although this statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, early adoption may be elected if the reporting entity has not yet issued financial statements for the fiscal year, including interim period financial statements. The company elected to early-adopt SFAS 157 in the first quarter of 2007. There was no transition adjustment as a result of the company's adoption of SFAS 157. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note 6.

SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115" (SFAS 159): SFAS 159 allows measurement at fair value of eligible financial assets and liabilities that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in current earnings at each subsequent reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between the different measurement attributes the company elects for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. The company is in the process of evaluating the application of the fair value option and the effect on its financial position and results of operation s.

Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48): FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS 109, Accounting for Income Taxes. FIN 48 addresses how an entity should recognize, measure, classify and disclose in its financial statements uncertain tax positions that it has taken or expects to take in an income tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Additionally, the FASB issued FASB Staff Position (FSP) FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 which amends FIN 48 to provide guid ance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The company's implementation of FIN 48 as of January 1, 2007 was consistent with the guidance in this FSP.

The company adopted the provisions of FIN 48 on January 1, 2007. As a result, the company recognized a $1 million decrease in retained earnings. Including this adjustment, the company had unrecognized tax benefits of $40 million as of January 1, 2007. Of this amount, $36 million related to tax positions that, if

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recognized, would decrease the effective tax rate; however, $26 million related to tax positions that would increase the effective tax rate in subsequent years. There were no material changes to the company’s unrecognized tax benefit amounts as of June 30, 2007.

It is reasonably possible that the company’s unrecognized tax benefits could decrease by up to $6 million within the next 12 months due to the expiration of statutes of limitations on tax assessmentsand by up to $7 million due to the potential resolution of federal income tax refund claims with the Internal Revenue Service.

Effective January 1, 2007, the company’s policy is to recognize accrued interest and penalties on accrued tax balances as components of tax expense. Prior to the adoption of FIN 48, the company accrued interest expense and penalties as components of tax expense and interest income as a component of interest income.

As of January 1, 2007, the company had accrued a total of $7 million of interest expense. There was no material change to the company’s accrued interest expense as of June 30, 2007. The company had no accrued penalties as of either January 1, 2007 or June 30, 2007. Amounts accrued for interest expense associated with income taxes are included in income tax expense on the Statements of Consolidated Income and in various income tax balances on the Consolidated Balance Sheets.

The company is subject to U.S. federal income tax as well as income tax of state jurisdictions. The company is no longer subject to examination by U.S. federal and major state tax jurisdictions for years before 2002. Federal and major state income tax returns from 2002 through the present are currently open to examination.

In addition, the company has filed federal and state refund claims for tax years back to 1989. The pre-2002 tax years are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these years.

NOTE 3. OTAY MESA ENERGY CENTER LLC

FIN 46 (revised December 2003),Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46(R)), requires an enterprise to consolidate a variable interest entity (VIE), as defined in FIN 46(R), if the company is the primary beneficiary of a VIE’s activities.

The company has entered into a 10-year power purchase agreement with OMEC LLC for power generated at the Otay Mesa Energy Center (OMEC), a 573-megawatt (MW) generating facility under construction in San Diego by OMEC LLC, which is expected to commence commercial operations in mid-2009. Under the terms of the agreement, SDG&E will purchase all of the power produced from the plant to serve its energy customers, and will supply natural gas to fuel the power plant. The agreement also provides SDG&E the option to purchase the plant at the end of the contract term in 2019, or upon earlier termination of the purchase power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, OMEC LLC has the right, under certain circumstances, to require SDG&E to purchase the plant at a predetermined price. As defined in FIN 46(R), OMEC LLC is a VIE, of which the company is the primary beneficiary. In accordance with FIN 46(R), the company consolidated OMEC LLC beginning in the second quarter of 2007.

The company’s Condensed Consolidated Financial Statements as of June 30, 2007, include the following amounts, in millions of dollars, associated with OMEC LLC:

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Cash and cash equivalents	$	29
Other current assets		3
Total current assets		32
Property, plant, and equipment		144
Sundry		16
Total assets	$	192
Accounts payable	$	21
Long-term debt		7
Minority interest		164
Total liabilities and shareholders’ equity	$	192

OMEC LLC has a project finance credit facility with third party lenders that provides for up to $377 million for the construction of the OMEC. The credit facility is structured as a construction loan, converting to a term loan upon commercial operation of the plant, and is secured by the assets of OMEC LLC. The loan matures in April 2019. Borrowings under the facility bear interest at rates varying with market rates. OMEC LLC had no outstanding borrowings under this facility at June 30, 2007. In addition, OMEC LLC has entered into interest-rate swap agreements to moderate its exposure to interest-rate changes on this facility.

NOTE 4. OTHER FINANCIAL DATA

Asset Retirement Obligations

The company’s asset retirement obligations, as defined in SFAS 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143, are discussed in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. Following are the changes in asset retirement obligations for the six months ended June 30, 2007 and 2006:

(Dollars in millions)	2007			2006
Balance as of January 1*	$	483		$	463
Accretion expense		17			15
Payments		(10	)		(6	)
Revision to estimated cash flows**		44			--
Balance as of June 30*	$	534		$	472

  *  The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets.

**  The revision is due to an increase in the present value of estimated liabilities for the San Onofre Nuclear       Generating Station (SONGS) decommissioning costs.

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Pension and Other Postretirement Benefits

The following tables provide the components of benefit costs for the three months and six months ended June 30:

		Pension Benefits						Other Postretirement Benefits
		Three months ended June 30,						Three months ended June 30,
(Dollars in millions)			2007			2006			2007			2006
Service cost		$	5		$	3		$	1		$	1
Interest cost			12			10			2			2
Expected return on assets			(10	)		(10	)		(1	)		--
Amortization of:
	Prior service cost		--			--			1			1
	Actuarial loss		1			--			--			--
Regulatory adjustment			1			1			1			(1	)
Total net periodic benefit cost		$	9		$	4		$	4		$	3

		Pension Benefits						Other Postretirement Benefits
		Six months ended June 30,						Six months ended June 30,
(Dollars in millions)			2007			2006			2007			2006
Service cost		$	11		$	6		$	3		$	2
Interest cost			24			21			4			4
Expected return on assets			(22	)		(21	)		(2	)		(1	)
Amortization of:
	Prior service cost		1			1			2			2
	Actuarial loss		1			1			--			--
Regulatory adjustment			(5	)		(3	)		1			(1	)
Total net periodic benefit cost		$	10		$	5		$	8		$	6

The company expects to contribute $43 million to its pension plan and $16 million to its other postretirement benefit plans in 2007. For the six months ended June 30, 2007, the company made contributions of $8 million and $8 million to the pension plan and other postretirement benefit plans, respectively, including $8 million and $4 million, respectively, for the three months ended June 30, 2007.

Capitalized Interest

The company recorded $1 million and $3 million of capitalized interest for thethree months andsix months ended June 30, 2007, respectively, including the debt-related portion of allowance for funds used during construction. The company recorded $1 million and $2 million of capitalized interest for thethree months and six months ended June 30, 2006,respectively, including the debt-related portion of allowance for funds used during construction.

Other Income (Expense), Net

Other Income (Expense), Net consists of the following:

		Three months ended					Six months ended
		June 30,					June 30,
(Dollars in millions)		2007			2006		2007			2006
Regulatory interest, net		$	(4	)	$	8	$	(7	)	$	6
Allowance for equity funds used during construction			3			2		8			4
Sundry, net			(1	)		1		1			3
	Total	$	(2	)	$	11	$	2		$	13

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Comprehensive Income

The following is a reconciliation of net income to comprehensive income.

	Three months ended				Six months ended
	June 30,				June 30,
(Dollars in millions)	2007		2006		2007		2006
Net income	$	52	$	66	$	115	$	114
Net actuarial gain*		5		--		5		--
Comprehensive income	$	57	$	66	$	120	$	114

*Net of tax expense of $4 million for both the three months and six months ended June 30, 2007.

NOTE 5. DEBT AND CREDIT FACILITIES

Committed Lines of Credit

SDG&E and its affiliate,SoCalGas, have a combined $600 million five-year syndicated revolving credit facility expiring in 2010, under which each utility individually may borrow up to $500 million, subject to a combined borrowing limit for both utilities of $600 million. At June 30, 2007, the company had no outstanding borrowings under this facility.The facility provides support for $30 million of commercial paper outstanding at June 30, 2007.

Additional information concerning this credit facility is provided in the Annual Report.

Weighted Average Interest Rate

The company's weighted average interest rate on the total short-term debt outstanding was 5.35 percent at June 30, 2007.

Interest-Rate Swaps

The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing.

Cash flow hedges

In September 2004, SDG&E entered into interest-rate swaps to exchange the floating rates on its $251 million Chula Vista Series 2004 bonds maturing from 2034 through 2039 for fixed rates. The swaps expire in 2009. The fair value of these swaps at both June 30, 2007 and December 31, 2006 was $3 million. For the six months ended June 30, 2007 and 2006, pretax income arising from the ineffective portion of interest-rate cash flow hedges was a negligible amount and $2 million, respectively, and was recorded in Other Income (Expense), Net on the Statements of Consolidated Income. There were no balances in Accumulated Other Comprehensive Income (Loss) at June 30, 2007 and December 31, 2006 related to interest-rate cash flow hedges.

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NOTE 6. FINANCIAL INSTRUMENTS

Interest-Rate Swaps

The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. The company's interest-rate swap to hedge cash flows is discussed in Note 5.

Energy Contracts

The use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments allow the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. The company records transactions for natural gas and electric energy contracts in Cost of Natural Gas and Cost of Electric Fuel and Purchased Power, respectively,on the Statements of Consolidated Income. On the Consolidated Balance Sheets, the company records corresponding regulatory assets and liabilities relating to unrealized gains and losses from these derivative instruments to the extent derivative gains and losses associated with these derivative instruments will be payable or recoverable in future rates.

Adoption of SFAS 157

Effective January 1, 2007, the company early-adopted SFAS 157 as discussed in Note 2, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS 157, the company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the company utilizes valuati on techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The company is able to classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of

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these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the company performs an analysis of all instruments subject to SFAS 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs. During the first six months of 2007, the company had no significant level 3 recurring measurements.

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2007. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company's 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.

Recurring Fair Value Measures			At fair value as of June 30, 2007
(Dollars in millions)			Level 1		Level 2		Level 3		Total
Assets:
	Commodity derivatives	$	13	$	15	$	--	$	28
	Nuclear decommissioning trusts		575		145		--		720
	Other derivatives		--		3		--		3
	Total	$	588	$	163	$	--	$	751
Liabilities:
	Commodity derivatives	$	1	$	11	$	--	$	12

Nuclear decommissioning trusts reflect the assets of the company's nuclear decommissioning trusts, excluding cash balances, as discussed in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. Commodity derivatives include commodity derivative positions entered into to manage customer price exposures, and other derivatives include interest-rate management instruments.

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a nonrecurring basis as of June 30, 2007. The fair value measures classified as level 3 are calculated based on discounted expected future cash flows.

Nonrecurring Fair Value Measures			At fair value as of June 30, 2007
(Dollars in millions)			Level 1		Level 2		Level 3		Total
Assets:
	OMEC*	$	--	$	8	$	155	$	163
Liabilities:
	OMEC*	$	--	$	--	$	28	$	28
	Asset retirement obligations**		--		--		45		45
	Total	$	--	$	--	$	73	$	73

* Consolidation of OMEC LLC as discussed in Note 3.

 ** Update to SONGS decommissioning and other costs as discussed in Note 4.

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NOTE 7. REGULATORY MATTERS

Power Procurement and Resource Planning

Otay Mesa Energy Center

In October 2006, SDG&E, Calpine Corporation (Calpine), OMEC LLC, a wholly owned subsidiary of Calpine, and other Calpine affiliates, entered into an agreement, approved in September 2006 by the California Public Utilities Commission (CPUC), for SDG&E to purchase all of the power produced from OMEC, a 573-MW generating facility to be constructed by OMEC LLC in the Otay Mesa area of SDG&E's service territory, with SDG&E supplying all of the natural gas to fuel the power plant. The agreement provides SDG&E the option to purchase the plant at the end of the contract term in 2019, or upon earlier termination of the purchase power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, OMEC LLC has the right, under certain circumstances, to require SDG&E to purchase the plant at a predetermined price. The CPUC also approved an additional financi al return to SDG&E to compensate it for the effect on its financial ratios from the requirement to consolidate OMEC LLC in accordance with FIN 46(R), as discussed in Note 3. Remaining conditions precedent in the agreement were favorably resolved in the second quarter of 2007. OMEC is expected to be in commercial operation by mid-2009, and annual capacity payments by SDG&E are estimated to be $70 million.

Sunrise Powerlink

In December 2005, SDG&E filed an application with the CPUC, amended in August 2006, proposing the construction of the Sunrise Powerlink, a 500-kV transmission line between the San Diego region and the Imperial Valley that is estimated to cost $1.3 billion and be able to deliver 1,000 MW by mid-2010. SDG&E and the Imperial Irrigation District (IID) have entered into a Memorandum of Agreement (MOA) to build the project, subject to the negotiation of a definitive agreement. If the IID participates in the project in accordance with the MOA, SDG&E's share of the project is estimated to be $1 billion.

During 2006, SDG&E reached several milestones, including the California Independent System Operator's (ISO) Board of Governors finding the project necessary to meet the demand for electricity in the region, the CPUC's Energy Division deeming the application complete and the company sponsoring public participation hearings on the project. The company submitted supplemental filings on July 20 and 25, 2007, with updated information. The ALJ is expected to rule shortly on a schedule for completion of the Phase I hearings.

Phase II of the hearings is expected to address environmental issues associated with the project, including alternative route proposals. Prior to Phase II, the CPUC is expected to issue a draft Environmental Impact Report (EIR) and Environmental Impact Study (EIS) for public comment and hold additional public participation hearings. This report, originally scheduled to be issued in August 2007, is now expected in January 2008. A final EIR/EIS is now scheduled to be issued by June 2008.

Given this revised timeline, the Sunrise Powerlink transmission line, if approved by the CPUC, will not be operational by the mid-2010 target date estimated in the company's original filing.

Renewable Energy

California Senate Bill 107 (SB 107), enacted in September 2006, requires California's investor-owned utilities (IOUs), including the company, to achieve a 20-percent renewable energy portfolio by 2010.

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SDG&E presently has executed renewable energy contracts to supply approximately 13 percent of its projected retail demand by the end of 2010, however, the deliverability of a substantial portion of these supplies is dependent upon SDG&E's proposed Sunrise Powerlink transmission line being approved and operational.

As a result of the revised Sunrise Powerlink EIR/EIS timeline, as discussed above, the Sunrise Powerlink transmission line, if approved, will not be in operation by mid-2010. In addition to the availability of adequate transmission infrastructure, SDG&E's ability to meet the requirements of SB 107 are highly dependent upon many other factors, including timely governmental approvals of contracted renewable energy projects, the renewable project developers' ability to obtain project financing, and successful development and implementation of the renewable energy technologies.

Consequently, the company believes it is unlikely that it will be able to deliver 20 percent of its projected retail demand from renewable energy sources by the end of 2010. Subject to flexible compliance measures to be implemented by the CPUC as required by SB 107, the company's failure to attain the 20-percent goal in 2010, or in any subsequent year, could subject it to a CPUC-imposed penalty of 5 cents per kilowatt hour of renewable energy under-delivery up to a maximum penalty of $25 million per year. The company cannot determine if it will be subject to a penalty and believes the conditions under which any penalty would be applied would be subject to the flexible compliance measures and the CPUC's review of the circumstances for under-delivery.

Greenhouse Gas Regulation

Additional legislation was enacted in 2006, including Assembly Bill 32 and Senate Bill 1368 (SB 1368), mandating cuts in greenhouse gas emissions, which could affect costs and growth at SDG&E. Any cost impact is expected to be recoverable through rates. The CPUC's adoption of an interim Greenhouse Gas Emissions Performance Standard in January 2007 implements SB 1368 by prohibiting IOUs from entering into new, or renewing existing, long-term (five years or longer) contracts for electricity from base-loaded sources that emit more carbon dioxide than a modern natural gas plant (1,100 pounds of carbon dioxide per MW-hour).

Long-term Procurement Plan

SDG&E filed its long-term procurement plan (LTPP) with the CPUC in December 2006, including a ten-year energy resource plan that details its expected portfolio of energy resources over the planning horizon of 2007 - 2016. The LTPP incorporates the renewable energy and greenhouse gas emissions performance standards established by the CPUC and by SB 107 and SB 1368. SDG&E's LTPP identifies, among other details, the need for additional generation resources beginning in 2010, including a baseload plant in 2012. The LTPP also indicates that SDG&E has an option to acquire in 2011, at net book value on the date of acquisition, theEl Dorado power plant, a 480-MW generating facility owned by Sempra Generation, a business unit of Sempra Energy. A CPUC decision on the LTPP is expected to be issued by the end of 2007.

Electric Transmission Formula Rate

On May 18, 2007, the FERC authorized an increase of 9.5 percent for SDG&E's annual electric transmission revenues effective July 1, 2007. This equates to an estimated annualized revenue increase in 2008 of $18 million in excess of the prior authorized amount. SDG&E will recover its annual transmission cost of service at a return on equity (ROE) of 11.35 percent, an increase from the current

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authorized ROE of 11.25 percent, and renew SDG&E's annual transmission formula rate, with only slight modifications from the current formula, for six years from July 1, 2007 through August 31, 2013.

General Rate Case

In April 2007, the company filed an amendment to its original 2008 General Rate Case application (2008 GRC) as filed in December 2006 with the CPUC. The 2008 GRC application, as amended, establishes the authorized margin requirements and the ratemaking mechanisms by which those margin requirements would change annually effective in 2008 through 2013 (2008 GRC rate period). The amended 2008 GRC request represents an increase in the company’s annual authorized margin of $230 million, as compared to 2007 authorized margin.

As part of the General Rate Case process, applications are subject to review and testimony by various groups representing the interests of ratepayers and other constituents. In early July 2007, the CPUC’s Division of Ratepayer Advocates (DRA) submitted testimony to the CPUC proposing, among other things, reductions to SDG&E’s requested margin requirements by $145 million. In addition, the DRA proposed a 5-year term as the applicable 2008 GRC rate period as compared to the 6-year term proposed by the company. Testimony submitted to the CPUC by certain other advocacy groups proposes, among other things, additional reductions in the requested margin requirements beyond those proposed by the DRA.

On July 20, 2007, the company submitted rebuttal testimony to the CPUC responding to the DRA's and other advocacy groups’ testimonies. Public hearings on the 2008 GRC are now scheduled to be held in early August 2007 and are expected to last up to three weeks. A final decision is expected early in 2008, with an effective date retroactive to January 1, 2008.

Cost of Capital Proceeding

The company filed an application with the CPUC in May 2007 seeking to update its cost of capital, authorized ROE and debt/equity ratios. SDG&E is requesting, among other things, an 11.60 percent ROE (compared to its current ROE of 10.70 percent), to be effective in 2008. SDG&E also seeks to maintain its current capital structure of 49 percent common equity, 5.75 percent preferred stock and 45.25 percent debt. Evidentiary hearings are scheduled to begin in August 2007, with a final CPUC decision expected by the end of 2007.

Utility Ratemaking Incentive Awards

Performance-Based Regulation (PBR) and demand-side management awards are not included in the company's earnings until CPUC approval of each award is received.

In May 2007, the CPUC approved SDG&E's Gas PBR Year 13 activities and the resulting $2 million shareholder award, recognized in earnings in the second quarter of 2007.In July 2007, SDG&E received approval of its 2006 Operational PBR shareholder award of $9 million, which will be included in the company's earnings in the third quarter of 2007.

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NOTE 8. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

At June 30, 2007, the company's reserves for litigation matters were $57million, of which $55million related to settlements reached in January 2006 to resolve certain litigation arising out of the 2000 - 2001 California energy crisis. The uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving legal matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversely affect the company's business, cash flows, results of operations and financial condition.

Continental Forge Settlement

The litigation that is the subject of the January 2006 settlements is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge class-action and individual antitrust and unfair competition lawsuits in California and Nevada alleged that Sempra Energy and the Sempra Utilities unlawfully sought to control natural gas and electricity markets and claimed damages in excess of $23 billion after applicable trebling.

The San Diego County Superior Court entered a final order approving the settlement of the Continental Forge class-action litigation as fair and reasonable in July 2006. The California Attorney General, the Department of Water Resources (DWR), the Utility Consumers Action Network and one class member have filed notices of appeal of the final order. The Nevada Clark County District Court entered an order approving the Nevada class-action settlement in September 2006. Both the California and Nevada settlements must be approved for either settlement to take effect, but Sempra Energyis permitted to waive this condition. The settlements are not conditioned upon approval by the CPUC, the DWR, or any other governmental or regulatory agency to be effective.

To settle the California and Nevada litigation, Sempra Energy agreed to make cash payments in installments aggregating $377 million, of which $347 million relates to the Continental Forge and California class action price reporting litigation and $30 million relates to the Nevada antitrust litigation. The Los Angeles City Council had not previously voted to approve the City of Los Angeles' participation in the January 2006 California settlement. On March 26, 2007, Sempra Energy and the Sempra Utilities entered into a separate settlement agreement with the City of Los Angeles resolving all of its claims in the Continental Forge litigation in return for the payment of $8.5 million on April 25, 2007. This payment was made in lieu of the $12 million payable in eight annual installments that the City of Los Angeles was to receive as part of the January 2006 California settlement.

Additional consideration for the January 2006 California settlement includes an agreement that Sempra LNG would sell to the Sempra Utilities, subject to CPUC approval, regasified LNG from its LNG terminal being constructed in Baja California, Mexico, for a period of 18 years at the California border index price minus $0.02 per million British thermal units (MMBtu). The Sempra Utilities agreed to seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and SoCalGas' underground natural gas storage system and filed for approval at the CPUC in July 2006. In addition, Sempra Generation voluntarily would reduce the price that it charges for power and limit the places at which it would deliver power under its contract with the DWR. Based on the expected contractual volumes of power to be delivered, t his discount would have potential value aggregating $300 million over the contract's then remaining six-year term. As a result of recording the price discount of the DWR contract in 2005, subsequent earnings reported on the DWR contract reflect original rather than discounted power prices. The price reductions would be offset by any amounts in excess of a $150 million

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threshold up to the full amount of the price reduction that Sempra Generation is ordered to pay or incurs as a monetary award, any reduction in future revenues or profits, or any increase in future costs in connection with arbitration proceedings involving the DWR contract.

Under the terms of the January 2006 California settlement, $83 million was paid in August 2006 and an additional $83 million will be paid in August 2007. Of the remaining amounts, $25.8 million is to be paid on the closing date of the January 2006 settlements, which will take place after the resolution of all appeals, and $24.8 million will be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date, as adjusted for the City of Los Angeles settlement. Under the terms of the City of Los Angeles settlement, $8.5 million was paid on April 25, 2007. The reserves recorded for the California and Nevada settlements in 2005 fully provide for the present value of both the cash amounts to be paid in the settlements and the price discount to be provided on electricity to be delivered under the DWR contract. A portion of the reserves was discounted at 7 percent, the rate specified for prepayments in the set tlement agreement. For payments not addressed in the agreement and for periods from the settlement date through the estimated date of the first payment, 5 percent was used to approximate the company’s average cost of financing.

Other Natural Gas Cases

In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in the U.S. District Court in Nevada against major natural gas suppliers, including Sempra Energy, the Sempra Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The lawsuit alleged a conspiracy to eliminate competition, prevent the construction of natural gas pipelines to serve Nevada and other Western states, and to manipulate natural gas pipeline capacity and supply and the data provided to price indices, as well as breach of contract. The U.S. District Court dismissed the case in November 2004, determining that the FERC had exclusive jurisdiction to resolve the claims. After oral argument in February 2007, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court of Appeals) took plaintiffs' appeal under submission.

Apart from the claims settled in connection with the Continental Forge settlement, there remain pending 13 state antitrust actions that have been coordinated in San Diego Superior Court against Sempra Energy, the Sempra Utilities and Sempra Commodities and other, unrelated energy companies,alleging that energy prices were unlawfully manipulated by the reporting of artificially inflated natural gas prices to trade publications and by entering into wash trades and churning transactions. On July 11, 2007, the Superior Court stayed both the entire proceeding against all defendants on federal preemption and filed rate grounds pending the Ninth Circuit Court of Appeals' decision in the Sierra Pacific case described above and the portion of the proceeding involving all but four of the 13 individual plaintiffs who brought actions against the company because they are class members in the Continental Forge settlement class described above.

Pending in federal court are five cases against Sempra Energy, Sempra Commodities, the Sempra Utilities and various other companies, which make similar allegations to those in the state proceedings, four of which also include conspiracy allegations similar to those made in the Continental Forge litigation. The Federal District Court dismissed four of these actions as preempted under federal law. The remaining case, which includes conspiracy allegations, has been stayed. In February 2007, the Ninth Circuit Court of Appeals heard oral argument and took plaintiffs' appeals under submission.

Electricity Cases

Various antitrust lawsuits, which seek class-action certification, allege that numerous entities, including Sempra Energy and certain subsidiaries, including SDG&E, that participated in the wholesale electricity

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markets unlawfully manipulated those markets. Collectively, these lawsuits allege damages against all defendants (including Sempra Energy and its named subsidiaries) in an aggregate amount in excess of $16 billion (before trebling). In January 2003, the federal court dismissed one of these lawsuits, filed by the Snohomish County, Washington Public Utility District, on the grounds that the claims were subject to the filed rate doctrine and preempted by the Federal Power Act. In September 2004, the Ninth Circuit Court of Appeals affirmed the district court's ruling and in June 2005, the U.S. Supreme Court declined to review the decision. The company believes that this decision serves as a precedent for the dismissal of all other lawsuits against the Sempra Energy companies claiming manipulation of the electricity markets.

FERC Refund Proceedings

The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and ISO markets by various electric suppliers. In December 2002, a FERC Administrative Law Judge (ALJ) issued preliminary findings indicating that the PX and ISO owe power suppliers $1.2 billion for the October 2, 2000 through June 20, 2001 period (the $3 billion that the California PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of the preliminarily determined competitive market clearing prices). In March 2003, the FERC adopted its ALJ's findings, but changed the calculation of the refund by basing it on a different estimate of natural gas prices, which would increase the refund obligations from $1.8 billion to more than $3 billion for the same time period.

Various parties appealed the FERC's order to the Ninth Circuit Court of Appeals. In August 2006, the Court of Appeals held that the FERC had properly established October 2, 2000 through June 20, 2001 as the refund period and had properly excluded certain bilateral transactions between sellers and the DWR from the refund proceedings. However, the court also held that the FERC erred in excluding certain multi-day transactions from the refund proceedings. Finally, while the court upheld the FERC's decision not to extend the refund proceedings to the summer period (prior to October 2, 2000), it found that the FERC had erred in not considering other remedies, such as disgorgement of profits, for tariff violations that are alleged to have occurred prior to October 2, 2000. The Court of Appeals remanded the matter to the FERC for further proceedings.

SDG&E has been awarded $159 million through June 30, 2007, in settlement of certain claims against electricity suppliers related to the 2000 - 2001 California energy crisis. The net proceeds of these settlements are for the benefit of ratepayers and for the payment of third party fees associated with the recovery of these claims. Of that amount, all monies have been received by SDG&E except for $12 million related to settlements which have been approved by the FERC and are pending disbursement of funds in the third quarter of 2007.

Nuclear Insurance

SDG&E and the other owners of SONGS have insurance to respond to nuclear liability claims related to SONGS. The insurance provides coverage of $300 million, the maximum amount available. In addition, the Price-Anderson Act provides for up to $10.5 billion of secondary financial protection. Should any of the licensed/commercial reactors in the United States experience a nuclear liability loss which exceeds the $300 million insurance limit, all utilities owning nuclear reactors could be assessed to provide the secondary financial protection. SDG&E's total share would be up to $40 million, subject to an annual maximum assessment of $6 million, unless a default were to occur by any other SONGS owner. In the event the secondary financial protection limit were insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

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SDG&E and the other owners of SONGS have $2.75 billion of nuclear property, decontamination and debris removal insurance and up to $490 million for outage expenses and replacement power costs incurred because of accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks and $2.8 million per week for up to 110 additional weeks, after a waiting period of 12 weeks. The insurance is provided through a mutual insurance company, through which insured members are subject to retrospective premium assessments (up to $8.6 million in SDG&E's case).

The nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts (as defined by the Terrorism Risk Insurance Act) of terrorism-related SONGS losses, including replacement power costs. There are industry aggregate limits of $300 million for liability claims and $3.24 billion for property claims, including replacement power costs, for non-certified acts of terrorism. These limits are the maximum amount to be paid to members who sustain losses or damages from these non-certified terrorist acts. For certified acts of terrorism, the individual policy limits stated above apply.

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ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" contained in the company's 2006 Annual Report on Form 10-K (Annual Report).

RESULTS OF OPERATIONS

Revenues and Cost of Sales

Electric revenues decreased for the six months ended June 30, 2007 compared to the corresponding period in 2006, primarily due to lower cost of electric fuel and purchased power and refundable costs, offset by higher authorized revenues. Electric revenues decreased for the three months ended June 30, 2007 due to lower refundable costs in 2007 and the favorable resolution of certain regulatory issues in 2006, including San Onofre Nuclear Generating Station (SONGS), offset by higher cost of electric fuel and purchased power and higher authorized revenues in 2007. During the three months and six months ended June 30, 2007, natural gas revenues increased compared to the corresponding periods in 2006, primarily as a result of higher cost of natural gas and higher authorized revenues.

Under the current regulatory framework, the cost of natural gas purchased for customers and the variations in that cost are passed through to customers on a substantially concurrent basis. However, SDG&E's natural gas procurement performance-based regulation mechanism allows the company to share in the savings or costs from buying natural gas for customers below or above market-based monthly benchmarks. Further discussion is provided in Notes 1 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.

The tables below summarize the electric and natural gas volumes and revenues by customer class for the six month periods ended June 30.

Electric Distribution and Transmission

(Volumes in millions of kilowatt-hours, dollars in millions)

	2007					2006
	Volumes		Revenue			Volumes		Revenue
Residential		3,592		$	461		3,534		$	387
Commercial		3,353			396		3,225			309
Industrial		1,068			106		1,070			76
Direct access		1,494			54		1,654			65
Street and highway lighting		52			6		51			5
		9,559			1,023		9,534			842
Balancing accounts and other					(35	)				192
Total				$	988				$	1,034

Although commodity costs associated with long-term contracts allocated to SDG&E from the Department of Water Resources (DWR) (and the revenues to recover those costs) are not included in the Statements of Consolidated Income, the associated volumes and distribution revenues are included in the above table.

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Natural Gas Sales, Transportation and Exchange

(Volumes in billion cubic feet, dollars in millions)

								Transportation
			Natural Gas Sales					and Exchange					Total
			Volumes		Revenue			Volumes		Revenue			Volumes		Revenue
2007:
	Residential			20		$	263		--		$	--		20		$	263
	Commercial and industrial			9			96		3			4		12			100
	Electric generation plants			--			1		25			18		25			19
				29		$	360		28		$	22		57			382
	Balancing accounts and other																(2	)
		Total														$	380
2006:
	Residential			20		$	264		--		$	--		20		$	264
	Commercial and industrial			9			105		3			4		12			109
	Electric generation plants			--			1		29			20		29			21
				29		$	370		32		$	24		61			394
	Balancing accounts and other																(42	)
		Total														$	352

Income Taxes

Income tax expense was$73 million for each of the six month periods ended June 30, 2007 and 2006, and the effective income tax rates was 39 percent for each of the six month periods ended June 30, 2007 and 2006.

Income tax expense was$35 million and $38 million for the three months ended June 30, 2007 and 2006, respectively, and the effective income tax rates were 40 percent and 37 percent, respectively.

The decrease in expense for the three months ended June 30, 2007 was due primarily to lower pretax income offset by a higher effective tax rate. The higher effective tax rate was due to the favorable resolution of prior years' income tax issues in 2006.

Net Income

Net income for SDG&E increased by $1 million (1%) in the six months ended June 30, 2007 to $115 million and decreased by $14 million (21%) in the three months ended June 30, 2007 to $52 million. The increase for the six months ended June 30, 2007 was primarily due to increases in 2007 from higher electric generation earnings of $8 million, primarily from Palomar, an increase of $8 million in the amount that authorized revenues exceeded operating costs and higher electric transmission earnings of $5 million, offset by the favorable resolution of certain regulatory and tax issues and an adjustment to the California energy crisis litigation reserves, which increased 2006 net income by $16 million, and lower Performance-Based Regulation (PBR) awards of $2 million in 2007. The decrease for the three months ended June 30, 2007 was primarily due to $16 million in benefits in 2006 from the favorable resolution of certain regulatory and tax issues an d an adjustment to the litigation reserves, and lower PBR awards of $2 million in 2007, offset by $7 million higher electric transmission earnings in 2007.

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CAPITAL RESOURCES AND LIQUIDITY

At June 30, 2007, the company had $42 million in unrestricted cash and $470 million in available unused credit on its committed line which is shared with SoCalGas and which is discussed more fully in Note 5 of the Notes to Condensed Consolidated Financial Statements. Management believes thatthese amounts and cash flows from operationsandsecurity issuances will be adequate to finance capital expenditures and meet liquidity requirements and other commitments. Management continues to regularly monitor the company's ability to finance the needs of its operating, investing and financing activities in a manner consistent with its intention to maintain strong, investment-quality credit ratings.

In connection with the purchase of the Palomar generating plant in 2006, the company received a $200 million capital contribution from Sempra Energy. As a result of the company's projected capital expenditure program, dividends to Sempra Energy have been suspended to increase SDG&E's equity, and the level of future common dividends may be affected during periods of increased capital expenditures.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities increased by $313 million (435%) to $385 million for 2007. The change was primarily due to an increase in overcollected regulatory balancing accounts of $141 million in 2007, compared to a decrease of $13 million in 2006, and $163 million higher net income tax payments in 2006.

For the six months ended June 30, 2007,the company made contributions of $8 million and $8 million to the pension and other postretirement benefit plans, respectively.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities decreased by $421 million (58%) to $301 million for 2007 primarily due to the purchase of the Palomar generating plant in 2006.

Significant capital expenditures in 2007 are expected to include $600million for additions to the company's natural gas and electric distribution and generation systems. These expenditures are expected to be financed by cash flows from operations and security issuances.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash provided by (used in) financing activities was $(80) million and $431 million for the six months ended June 30, 2007 and 2006, respectively. The change was primarily due to the issuance of $250 million in long-term debt and a $200 million capital contribution from Sempra Energy, both in 2006.

COMMITMENTS

At June 30, 2007, there were no significant changes to the commitments that were disclosed in the Annual Report, except for increases of $452 million, $44 million, and $24 million, respectively, related to new power purchase contracts, the increase in present value of liabilities for future costs of SONGS decommissioning from revisions to estimated cash flows, and other commitments. The future payments under these contractual commitments are expected to be $68 million for 2007, $80 million for 2008, $74 million for 2009, $33 million for 2010, $33 million for 2011, and $232 million thereafter.

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FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the company will depend primarily on the ratemaking and regulatory process, electric and natural gas industry restructuring, and the changing energy marketplace. Performance will also depend on the successful completion of capital projects which are discussed in various places in this report. These factors are discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.

Litigation

Note 8 of the Notes to Condensed Consolidated Financial Statements herein and Note 11 of the Notes to Consolidated Financial Statements in the Annual Report describe litigation (primarily cases arising from the California energy crisis), the ultimate resolution of which could have a material adverse effect on future performance.

Industry Developments

Note7 of the Notes to Condensed Consolidated Financial Statements herein andNotes 9 and 10 of the Notes to Consolidated Financial Statements in the Annual Report describe electric and natural gas regulation and rates, and other pending proceedings and investigations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Certain accounting policies are viewed by management as critical because their application is the most relevant, judgmental and/or material to the company's financial position and results of operations, and/or because they require the use of material judgments and estimates.

The company's significant accounting policies are described in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. Significant accounting pronouncements that have recently become effective and may have a significant effect on the company’s accounting policies and estimates are described below and were adopted by the company effective January 1, 2007, as discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

Description	Assumptions & Approach Utilized	Effect if Different Assumptions Used
Fair Value Measurements
Statement of Financial Accounting Standards (SFAS) 157,Fair Value Measurements, was adopted by the company in the first quarter of 2007. SFAS 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not expand the use of fair value accounting in any new circumstances. SFAS 157: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 6 of the Notes to Condensed Consolidated Financial Statements herein), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or block discount when measuring instruments traded in an actively quoted market at fair value, and (4) requires costs related to acquiring instruments carried at fair value to be recognized as expense when incurred. The following assets and liabilities are recorded at fair value on a recurring basis as of June 30, 2007: (1) derivatives and (2) the assets of the company’s nuclear decommissioning trusts.	As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS 157, the company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities carried at fair value. The company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The company is able to classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the company performs an analysis of all instruments subject to SFAS 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs. During the first six months of 2007, the company had no significant level 3 recurring measurements.	The company's assessment of the significance of a particular input to the fair value measurements requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Generally, the company’s results of operations are not significantly impacted by the assets and liabilities accounted for at fair value because of the principles contained in SFAS 71,Accounting for the Effects of Certain Types of Regulations. There was no transition adjustment as a result of the company's adoption of SFAS 157. Additional information relating to fair value measurement is discussed in Notes 2 and 6 of the Notes to Condensed Consolidated Financial Statements herein.
Income Taxes
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48) clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements. FIN 48 addresses how an entity should recognize, measure, classify and disclose in its financial statements uncertain tax positions that it has taken or expects to take in an income tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.	For a position to qualify for benefit recognition under FIN 48, the position must have at least a “more likely than not” chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. If the company does not have a more likely than not position with respect to a tax position, then the company may not recognize any of the potential tax benefit associated with the position. A tax position that meets the “more likely than not” recognition shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon the effective resolution of the tax position.	Unrecognized tax benefits involve management judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect the company’s results of operations, financial position and cash flows. Additional information related to accounting for uncertainty in income taxes is discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have had or may have a significant effect on the company's financial statements are described in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no significant changes in the risk issues affecting the company subsequent to those discussed in the Annual Report.

As of June 30, 2007, the total Value at Risk of SDG&E's positions was not material.

ITEM 4.CONTROLS AND PROCEDURES

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's 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 company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the c ost-benefit relationship of other possible controls and procedures. In addition, the company consolidates a variable interest entity as defined in FIN 46(R) that it does not control or manage and consequently, its disclosure controls and procedures with respect to this entity are necessarily limited to oversight or monitoring controls that the company has implemented to provide reasonable assurance that the objectives of the company's disclosure controls and procedures as described above are met.

There have been no changes in the company's internal control over financial reporting during the company's most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting.

The company evaluates the effectiveness of its internal control over financial reporting based on the framework inInternal Control--Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures as of June 30, 2007, the end of the period covered by this report. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures were effective at the reasonable assurance level.

PART II - OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

On July 13, 2007, SDG&E, one of its employees, and an SDG&E contractor were convicted in a federal jury trial on criminal charges of environmental violations in connection with the 2000-2001 dismantlement of a natural gas storage facility. SDG&E was also convicted of a related charge of making a false statement to a government agency. SDG&E is subject to a maximum fine of $2 million. SDG&E intends to move for a new trial and, if a new trial is not granted, to appeal the verdicts.

Except as described above and in Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements herein, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses.

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ITEM 1A.RISK FACTORS

There have been no material changes from risk factors as previously disclosed in the company's 2006 Annual Report on Form 10-K.

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Proposal 1: Election of directors:

At the annual meeting of shareholders on May 30, 2007, shareholders elected three directors for a one-year term expiring in 2009. The name of each nominee and the number of shares voted for and withheld from the election of each director were as follows. There were no abstentions or broker non-votes.

Nominees	Votes For	Votes Withheld
Michael R. Niggli	116,583,358	200
Debra L. Reed	116,583,358	200
Mark A. Snell	116,583,358	200

Proposal 2: SDG&E to provide shareholders of voting stock the means (telephonic or otherwise) to vote their shares at the annual meetings:

	Votes
In favor	200
Opposed	116,583,358
Abstentions	0
Broker Non-Votes	0

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ITEM 6.EXHIBITS

Exhibit 12 - Computation of ratios

12.1   Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

Exhibit 31 -- Section 302 Certifications

31.1   Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2   Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Exhibit 32 -- Section 906 Certifications

32.1   Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.2   Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.

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SIGNATURE
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: August 2, 2007	By: /s/ Dennis V. Arriola
	Dennis V. Arriola Sr. Vice President and Chief Financial Officer

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