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SDG&E 3/31/2007 10-Q




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	March 31, 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

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

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.

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

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME


			Three months ended
			March 31,
(Dollars in millions)			2007			2006
				(unaudited)
Operating revenues
	Electric		$	470		$	477
	Natural gas			239			245
		Total operating revenues		709			722

Operating expenses
	Cost of electric fuel and purchased power			149			210
	Cost of natural gas			148			154
	Other operating expenses			178			159
	Depreciation and amortization			75			67
	Franchise fees and other taxes			39			33
		Total operating expenses		589			623

Operating income				120			99

Other income, net				4			2
Interest income				1			4
Interest expense				(24	)		(22	)
Income before income taxes				101			83

Income tax expense				38			35

Net income				63			48
Preferred dividend requirements				1			1
Earnings applicable to common shares			$	62		$	47

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS


			March 31,			December 31,
(Dollars in millions)			2007			2006
			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	43		$	9
	Accounts receivable – trade			209			206
	Accounts receivable – other			21			26
	Interest receivable			--			15
	Due from unconsolidated affiliates			18			24
	Income taxes receivable			--			25
	Deferred income taxes			45			41
	Inventories			74			97
	Regulatory assets arising from fixed-price contracts
		and other derivatives		54			83
	Other regulatory assets			50			69
	Other			46			71
		Total current assets		560			666

Other assets:
	Due from unconsolidated affiliate			5			5
	Deferred taxes recoverable in rates			292			318
	Regulatory assets arising from fixed-price contracts
		and other derivatives		339			353
	Regulatory assets arising from pensions and other
	postretirement benefit obligations			224			220
	Other regulatory assets			61			59
	Nuclear decommissioning trusts			710			702
	Sundry			82			72
		Total other assets		1,713			1,729

Property, plant and equipment:
	Property, plant and equipment			7,633			7,495
	Less accumulated depreciation and amortization			(2,149	)		(2,095	)
		Property, plant and equipment, net		5,484			5,400
Total assets			$	7,757		$	7,795

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS


				March 31,			December 31,
(Dollars in millions)				2007			2006
				(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Short-term debt			$	--		$	72
	Accounts payable				186			273
	Due to unconsolidated affiliates				1			5
	Income taxes payable				22			--
	Regulatory balancing accounts, net				266			165
	Fixed-price contracts and other derivatives				54			83
	Customer deposits				49			47
	Mandatorily redeemable preferred securities				14			3
	Current portion of long-term debt				49			66
	Other				254			287
			Total current liabilities		895			1,001

Long-term debt					1,638			1,638

Deferred credits and other liabilities:
	Customer advances for construction				36			38
	Pension and other postretirement benefit obligations, net of plan assets				254			249
	Deferred income taxes				495			520
	Deferred investment tax credits				31			31
	Regulatory liabilities arising from removal obligations				1,309			1,311
	Asset retirement obligations				510			462
	Fixed-price contracts and other derivatives				344			353
	Mandatorily redeemable preferred securities				--			14
	Deferred credits and other				190			184
			Total deferred credits and other liabilities		3,169			3,162

Commitments and contingencies (Note 7)

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				857			796
	Accumulated other comprehensive income (loss)				(19	)		(19	)
			Total shareholders' equity		2,055			1,994
Total liabilities and shareholders' equity				$	7,757		$	7,795

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS


						Three months ended
						March 31,
(Dollars in millions)							2007			2006
								(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income						$	63		$	48
	Adjustments to reconcile net income to net cash provided
			by operating activities:
				Depreciation and amortization				75			67
				Deferred income taxes and investment tax credits				(2	)		(9	)
				Non-cash rate reduction bond expense				14			15
				Other				(2	)		(2	)
	Net changes in working capital components							122			10
	Changes in other assets							3			5
	Changes in other liabilities							(7	)		(10	)
				Net cash provided by operating activities				266			124

CASH FLOWS FROM INVESTING ACTIVITIES
	Expenditures for property, plant and equipment							(157	)		(583	)
	Purchases of nuclear decommissioning trust assets							(211	)		(109	)
	Proceeds from sales by nuclear decommissioning trusts							213			109
	Decrease (increase) in loans to affiliates, net							14			(1	)
	Proceeds from sales of assets							2			--
				Net cash used in investing activities				(139	)		(584	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Capital contribution							--			200
	Increase (decrease) in short-term debt, net							(72	)		61
	Payments on long-term debt							(17	)		(17	)
	Redemptions of preferred stock							(3	)		(3	)
	Preferred dividends paid							(1	)		(1	)
					Net cash provided by (used in) financing activities			(93	)		240

Increase (decrease) in cash and cash equivalents								34			(220	)
Cash and cash equivalents, January 1								9			236
Cash and cash equivalents, March 31							$	43		$	16

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION
		Interest payments, net of amounts capitalized					$	7		$	9
		Income tax refunds, net					$	(35	)	$	(19	)

SUPPLEMENTAL SCHEDULE OF NONCASH
	INVESTING ACTIVITY
		Decrease in accounts payable from investments
				in property, plant and equipment			$	(32	)	$	(8	)

See Notes to Condensed Consolidated Financial Statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

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 Consolidated Financial Statements of SDG&E and its sole subsidiary, SDG&E Funding LLC.

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.

The 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).

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.

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 fair value measurements to certain assets and liabilities, primarily nuclear decommissioning trusts and commodity and other derivatives.

SFAS 157: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 5), (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 has 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 5.

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.

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 recognized, would decrease the effective tax rate; however, $26 million related to tax positions that would increase the effective tax rate in subsequent years.

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 a component 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. The company had not accrued any penalties as of January 1, 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 from 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. 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 three months ended March 31, 2007 and 2006:


(Dollars in millions)	2007			2006
Balance as of January 1*	$	483		$	463
Accretion expense		9			7
Payments		(5	)		(2	)
Revision to estimated cash flows**		44			--
Balance as of March 31*	$	531		$	468

* 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.

Pension and Other Postretirement Benefits

The following table provides the components of benefit costs for the three months ended March 31:



		Pension Benefits						Other Postretirement Benefits
(Dollars in millions)			2007			2006			2007			2006
Service cost		$	6		$	3		$	2		$	1
Interest cost			12			11			2			2
Expected return on assets			(12	)		(11	)		(1	)		(1	)
Amortization of:
	Prior service cost		1			1			1			1
	Actuarial loss		--			1			--			--
Regulatory adjustment			(6	)		(4	)		--			--
Total net periodic benefit cost		$	1		$	1		$	4		$	3

The company expects to contribute $45 million to its pension plan and $16 million to its other postretirement benefit plans in 2007. For the three months ended March 31, 2007, a negligible amount and $4 million of contributions were made to the pension and other postretirement benefit plans, respectively.

Capitalized Interest

The company recorded $2 million and $1 million of capitalized interest for the three months ended March 31, 2007 and 2006, respectively, including primarily the debt-related portion of allowance for funds used during construction.

Other Income, Net

Other Income, Net consists of the following:


		Three months ended
		March 31,
(Dollars in millions)		2007			2006
Allowance for equity funds used during construction		$	5		$	2
Regulatory interest, net			(3	)		(2	)
Sundry, net			2			2
	Total	$	4		$	2

Comprehensive Income

For the three months ended March 31, 2007 and 2006, respectively, comprehensive income was equal to net income.

NOTE 4. 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 March 31, 2007, the company had no outstanding borrowings under this facility.

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

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 March 31, 2007 and December 31, 2006 was $3 million. For the three months ended March 31, 2007 and 2006, pretax income arising from the ineffective portion of interest-rate cash flow hedges was $1 million and $3 million, respectively, and was recorded in Other Income, Net on the Statements of Consolidated Income. There were no balances in Accumulated Other Comprehensive Income (Loss) at March 31, 2007 and December 31, 2006, related to interest-rate cash flow hedges.

NOTE 5. 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 4.

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.

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 quarter 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 March 31, 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 March 31, 2007
(Dollars in millions)			Level 1		Level 2		Level 3		Total

Assets:
	Commodity derivatives	$	8	$	16	$	--	$	24
	Nuclear decommissioning trusts		550		150		--		700
	Other derivatives		--		3		--		3
	Total	$	558	$	169	$	--	$	727

Liabilities:
	Commodity derivatives	$	--	$	11	$	--	$	11

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 liabilities that were accounted for at fair value on a nonrecurring basis as of March 31, 2007.


Nonrecurring Fair Value Measures			At fair value as of March 31, 2007
(Dollars in millions)			Level 1		Level 2		Level 3		Total

Liabilities:
	Asset retirement obligations*	$	--	$	--	$	44	$	44

* Update to SONGS decommissioning costs as discussed in Note 3.

NOTE 6. REGULATORY MATTERS

Power Procurement and Resource Planning

Otay Mesa Energy Center

In October 2006, SDG&E, Calpine Corporation (Calpine), Otay Mesa Energy Center, LLC (OMEC), 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 a 573-megawatt (MW) generating facility to be constructed by OMEC in the Otay Mesa area of SDG&E's service territory. The agreement includes, among other things, an option in favor of SDG&E to purchase the facility for a fixed price at the end of the 10-year power purchase agreement (PPA) and an option in favor of OMEC to compel SDG&E to purchase the plant for a lower fixed price at the end of the PPA. The CPUC also approved an additional return to SDG&E to compensate it for the effect on its financial ratios from the expected requirement to consolidate OMEC in accordance with FIN 46(R), Consol idation of Variable Interest Entities. Among other conditions precedent, the transaction also required the approvals of the court having jurisdiction over the Calpine bankruptcy and of the Federal Energy Regulatory Commission (FERC), which were obtained in November 2006 and January 2007, respectively. The remaining conditions precedent are expected to be favorably resolved in the second quarter of 2007. Assuming such resolution is timely attained, the generating facility 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. The purpose of the project is to enhance reliability, provide access to renewable resources and reduce energy costs for SDG&E customers. 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 proposed transmission line economically justified and needed to meet the demand for electricity in the region, the CPUC's Energy Division deeming the application complete and the company's holding public participation hearings to get input on the project. In November 2006, a ruling was issued establishing the scope of the CPUC proceeding and targeting a draft decision to be issued in December 2007 and a final decision to be adopted in early 2008. The CPUC plans to issue a draft Environmental Impact Report (EIR) and Environmental Impact Statement (EIS) for public comment in August 2007 with final EIR/EIS targeted for November 2007. On April 26, 2007, the U.S. Department of Energy proposed designating portions of the Southwestern United States as a "national interest corridor" for electric transmission which, if adopted, would allow federal review and permitting of the Sunrise Powerlink if the CPUC delays or rejects the project. The proposal is subject to a 60-day comment period which will include public meetings. Timely approval by the CPUC is crit ical for completion of the Sunrise Powerlink by 2010, when it will be necessary for SDG&E to gain access to renewable energy sources to comply with the requirement for SDG&E to achieve a 20 percent renewable energy portfolio by 2010, as discussed below.

Renewable Energy

California Senate Bill 107 (SB 107), enacted in September 2006, requires California's investor-owned utilities (IOUs) to achieve a 20 percent renewable energy portfolio by 2010, instead of 2017 as previously required by state law. SDG&E already had been moving forward to achieve a 20 percent goal by 2010, consistent with California's Energy Action Plan. As of early April 2007, SDG&E has executed renewable energy contracts that are expected to supply approximately 12 percent of SDG&E’s projected retail demand by the end of 2010, assuming the suppliers deliver as forecasted and the necessary transmission infrastructure, including the Sunrise Powerlink, is added. Failure to reach the goal could subject the company to penalties ranging up to $25 million per year. SDG&E's ability to meet the requirements of SB 107 are highly dependent upon many factors, including, but not limited to, the timely regulatory app roval of contracted renewable energy projects, the developers' ability to obtain project financing, and successful development and implementation of the renewable energy technologies. The developers' ability to obtain project financing is dependent upon, among other things, access to electric transmission capacity to move the renewable energy to the markets. Without a timely approval by regulators and the successful addition of new transmission infrastructure, including Sunrise Powerlink, there can be no assurance that SDG&E will be able to achieve the requirements of SB 107.

Greenhouse Gas Initiative

In 2006, additional legislative bills were passed, including Assembly Bill 32 and Senate Bill 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 Senate Bill 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 megawatt-hour).

Long-term Energy Resource Plan

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

Transmission Formula Rate

On March 28, 2007, SDG&E filed an Offer of Settlement (Settlement) with the FERC that would provide revenues of $208 million in 2008, compared to $190 million in 2007, an increase of 9.5 percent. Under the Settlement, SDG&E would recover its annual transmission cost of service at a return on equity (ROE) of 11.35 percent, an increase from the current authorized formula ROE of 11.25 percent, and renew SDG&E's current annual transmission formula rate for approximately six years commencing July 1, 2007 through August 31, 2013. The Settlement was supported by the CPUC and was unopposed by a number of intervenors. The Settlement is subject to FERC approval, which is expected by July 2007.

General Rate Case

In December 2006, SDG&E filed a 2008 General Rate Case (GRC) application to establish its authorized 2008 margin requirements and the ratemaking mechanisms by which those margin requirements would change on an annual basis over the subsequent five-year period (2009 - 2013), as discussed in Note 10 of the Notes to Consolidated Financial Statements in the Annual Report. Relative to authorized margin requirements for 2007, the GRC request represents an increase of $232 million ($34 million for natural gas and $198 million for electric) in 2008. Public participation hearings are scheduled for May 2007, intervenor testimony is due June 1, 2007, evidentiary hearings begin July 30, 2007 and a final CPUC decision is expected by the end of 2007.

In January 2007, SDG&E filed a Phase II GRC (GRC Phase II) application to update its electric marginal cost, revenue allocation and rate design. SDG&E’s GRC Phase II application sets forth several new rate design and marginal cost allocation proposals, including dynamic pricing or time differential rate proposals that will encourage customers to shift their usage from peak demand to off-peak hours. Also proposed is a phase-out of the rate cap enacted by the California Legislature in 2001 at the height of California's energy crisis. GRC Phase II hearings are expected to be completed early in the fourth quarter 2007 with a final CPUC decision early in 2008.

Cost of Capital Proceeding

The Company is planning to file with the CPUC in early May 2007 an application to adjust its cost of capital, with any resulting changes in ROE and/or capital structure to be effective in 2008. SDG&E's present ROE of 10.7 percent was approved by the CPUC in December 2005 and effective as of January 1, 2006, with an authorized capital structure of 45.25 percent debt, 5.75 percent preferred stock and 49 percent common equity.

Advanced Metering Infrastructure

An all-party settlement was approved by the CPUC in April 2007 associated with SDG&E's advanced metering infrastructure initiative to install advanced meters with integrated two-way communications functionality throughout SDG&E's service territory. This settlement adds the beneficial functionalities of remote disconnect and a home area network for all customers, resulting in estimated expenditures for this project of $572 million (including a $500 million capital investment). Meter installations for 1.4 million electric and 900,000 natural gas meters are anticipated to commence in the fourth quarter of 2008 and be completed by early 2011.

Natural Gas Market OIR

The CPUC considered natural gas market issues, including market design and infrastructure requirements, as part of its Natural Gas Market Order Instituting Rulemaking (OIR). A final decision in Phase II of this proceeding was issued in September 2006, reaffirming the adequacy of the capacity of the SoCalGas and SDG&E systems to meet current demand. In particular, the Phase II decision establishes natural gas quality standards that would accommodate regasified liquefied natural gas (LNG) supplies. While the decision closed the OIR, several parties, including the South Coast Air Quality Management District (SCAQMD), filed applications with the CPUC for rehearing of the September 2006 decision, contending that the California Environmental Quality Act (CEQA) applies to the increase in natural gas quality standards approved by the CPUC, and that impacts on the environment should be fully considered. The CPUC denied the rehearing requests. In Janu ary 2007, the SCAQMD filed, and amended in March 2007, lawsuits against the CPUC in the California Court of Appeal and the California Supreme Court challenging the CPUC's September 2006 decision and alleging that CEQA was improperly bypassed.

Utility Ratemaking Incentive Awards

Performance-Based Regulation (PBR) and demand-side management (DSM) awards are not included in the company's earnings until CPUC approval of each award is received. Final CPUC approval of SDG&E's Gas PBR Year 13 activities and the resulting $2.3 million shareholder award is expected in early May 2007.

The Operational PBR mechanism includes safety, reliability and customer service measures established in the GRC. On May 1, 2007, SDG&E filed for its 2006 Operational PBR shareholder award of $8.9 million ($8.4 million for electric and $0.5 million for natural gas). CPUC approval is expected by the end of 2007.

NOTE 7. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

At March 31, 2007, the company's reserves for litigation matters were $59 million, of which $57 million 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 Energy is 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's 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 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, this discount would have potentia l 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 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 November 2005, the California Attorney General and the CPUC filed a lawsuit in the San Diego County Superior Court alleging that Sempra Energy and the Sempra Utilities intentionally misled the CPUC in a 1998 application that resulted in SDG&E curtailing natural gas service to electric generators and others. In September 2006, the parties settled the case whereby the Sempra Utilities agreed to pay $2 million for attorneys' fees and costs to the California Attorney General, Sempra Energy gave SDG&E an option to purchase the El Dorado power plant in 2011 for net book value (subject to FERC approval) and Sempra Energy agreed to pay approximately $5.7 million to SDG&E electricity customers over a two-year period beginning in 2009. The decisions by SDG&E and the CPUC as to whether the option should be exercised are expected to be made in 2007. The company recorded after-tax expense of $0.4 million in 2006 to reflect these settlement costs.

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. The plaintiffs suing the company claim that all of the defendants' actions have damaged them in the amount of $357 million before trebling. In June 2005, the court denied the defendants' motion to dismiss on federal preemption and filed rate doctrine grounds. No trial date has been scheduled for these actions.

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 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 lawsui ts against the Sempra Energy companies claiming manipulation of the electricity markets.

In October 2005, on the basis of federal preemption and Filed Rate grounds, the San Diego Superior Court dismissed with prejudice consolidated cases that claimed that energy companies, such as the Sempra Energy companies, manipulated the electricity markets. On February 26, 2007, the California Court of Appeal affirmed the dismissals.

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 $3.0 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 April 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 $18 million related to settlements filed in March and April of 2007 and which are pending FERC approval.

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.

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 $8.14 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.

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 three months ended March 31, 2007 compared to the corresponding period in 2006, primarily due to decreased costs that are passed through to customers, offset by increased authorized revenues at San Onofre Nuclear Generating Station (SONGS). Natural gas revenues decreased for the three months ended March 31, 2007 due to lower overall costs of natural gas.

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 three month periods ended March 31.

Electric Distribution and Transmission

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


	2007					2006
	Volumes		Revenue			Volumes		Revenue
Residential		1,960		$	249		1,882		$	197
Commercial		1,683			185		1,607			142
Industrial		525			48		530			35
Direct access		778			28		898			34
Street and highway lighting		25			3		27			3
		4,971			513		4,944			411
Balancing accounts and other					(43	)				66
Total				$	470				$	477

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.

Natural Gas Sales, Transportation and Exchange

(Volumes in billion cubic feet, dollars in millions)

< TD style="background-color:#CCFFCC" valign=top width=31.2>


								Transportation
			Natural Gas Sales					and Exchange					Total
			Volumes		Revenue			Volumes		Revenue			Volumes		Revenue
2007:
	Residential			14		$	172		--		$	--		14		$	172
	Commercial and industrial			5			55		1			2		6			57
	Electric generation plants			--			--		14			10		14			10
				19		$	227		15		$	12		34			239
	Balancing accounts and other															--
		Total														$	239

2006:
	Residential			12		$	171		--		$	--		12		$	171
	Commercial and industrial			5			64		2			2		7			66
	Electric generation plants			--			1		14			10		14			11
				17		$	236		16		$	12		33			248
	Balancing accounts and other															(3	)
		Total														$	245

Income Taxes

Income tax expense was $38 million and $35 million for the three months ended March 31, 2007 and 2006, respectively, and the effective income tax rates were 38 percent and 42 percent, respectively. The increase in income tax expense was due primarily to higher pretax income, offset by a lower effective tax rate in 2007. The decrease in effective tax rate was primarily due to the regulatory treatment for certain capital expenditures that are expensed for income tax purposes.

Net Income

Net income for SDG&E increased by $15 million (31%) to $63 million for the three months ended March 31, 2007. The increase is primarily due to higher earnings from electric generation, including the Palomar generating plant, which commenced commercial operations in the second quarter of 2006, and SONGS.

CAPITAL RESOURCES AND LIQUIDITY

At March 31, 2007, the company had $43 million in unrestricted cash and $500 million in an available unused, committed line of credit which is shared with SoCalGas and which is discussed more fully in Note 4 of the Notes to Condensed Consolidated Financial Statements. Management believes that these amounts and cash flows from operations and security 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 the first quarter of 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 $142 million (115%) to $266 million for 2007. The change was primarily due to a $67 million higher increase in overcollected regulatory balancing accounts in 2007, an $18 million decrease in other current assets in 2007 compared to a $35 million increase in 2006 and a $29 million increase in net income (adjusted for non-cash items) in 2007.

For the three months ended March 31, 2007, the company made contributions of a negligible amount and $4 million to the pension and other postretirement benefit plans, respectively.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities decreased by $445 million (76%) to $139 million for 2007 primarily due to the purchase of the Palomar generating plant in 2006.

Significant capital expenditures in 2007 are expected to include $600 million 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 $(93) million and $240 million for the three months ended March 31, 2007 and 2006, respectively. The change was primarily due to a $200 million capital contribution from Sempra Energy in 2006 and a $72 million decrease in short-term borrowings in 2007 compared to a $61 million increase in 2006.

COMMITMENTS

At March 31, 2007, there were no significant changes to the commitments that were disclosed in the Annual Report, except for increases of $129 million and $44 million, respectively, related to a new power purchase contract and the increase in present value of estimated liabilities for SONGS decommissioning costs. The future payments under these contractual commitments are expected to be $49 million for 2007, $40 million for 2008 and $40 million for 2009. There are no future payments for 2010 and 2011, but $44 million thereafter.

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 6 of the Notes to Condensed Consolidated Financial Statements herein.

Litigation

Note 7 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

Note 6 of the Notes to Condensed Consolidated Financial Statements herein and Notes 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.


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 5 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 relating to acquiring instruments carried at fair value to be recognized as expense when incurred.

The following assets and liabilities are recorded at fair value as of March 31, 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 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.

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 Regulation.

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 5 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 ultimate settlement with a taxing authority.

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.

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 March 31, 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.

There have been no changes in the company's internal controls 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 controls over financial reporting.

The company evaluates the effectiveness of its internal control over financial reporting based on the framework in Internal Control--Integrated Framework issued 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 March 31, 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

The County of San Diego filed and then withdrew litigation against Sempra Energy and SDG&E that sought unspecified civil penalties for alleged violations of environmental standards applicable to the abatement, handling and disposal of asbestos-containing materials during the 2001 dismantlement of a natural gas storage facility. In addition, in November 2006, a federal court dismissed all charges against SDG&E and two employees in a federal criminal indictment charging them with having violated these standards and for related charges of conspiracy and having made false statements to governmental authorities. On February 12, 2007, the court granted the federal government's motion for reconsideration with respect to the false statement count. On February 27, 2007, the San Diego U.S. Attorney's Office re-indicted the previously dismissed case against SDG&E, its employees and contractors. A trial in this matter is sch eduled for June 2007.

Except as described above and in Notes 6 and 7 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.

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 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.


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

EXHIBIT 12


EXHIBIT 12.1
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)

						Three months
						ended
	2002	2003	2004	2005	2006	March 31, 2007
Fixed Charges and Preferred
Stock Dividends:

Interest	$ 83	$ 78	$ 71	$ 77	$ 102	$ 25

Interest portion of annual rentals	2	2	2	3	3	1

Total fixed charges	85	80	73	80	105	26

Preferred stock dividends (1)	9	9	8	6	8	2

Combined fixed charges and preferred stock
dividends for purpose of ratio	$ 94	$ 89	$ 81	$ 86	$ 113	$ 28

Earnings:

Pretax income from continuing operations	$ 300	$ 488	$ 361	$ 356	$ 394	$ 101

Total fixed charges (from above)	85	80	73	80	105	26

Less: interest capitalized	1	1	1	1	1	-

Total earnings for purpose of ratio	$ 384	$ 567	$ 433	$ 435	$ 498	$ 127

Ratio of earnings to combined fixed charges
and preferred stock dividends	4.09	6.37	5.35	5.06	4.41	4.54

Ratio of earnings to fixed charges	4.52	7.09	5.93	5.44	4.74	4.88


(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.

Ex 31.1

EXHIBIT 31.1

CERTIFICATION

I, Debra L. Reed, certify that:

I have reviewed this Quarterly Report on Form 10-Q of San Diego Gas & Electric Company;

Based on my knowledge, this Quarterly 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 Quarterly Report;

Based on my knowledge, the financial statements and other financial information included in this Quarterly 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 Quarterly 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 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 Quarterly 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 Quarterly Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Quarterly 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 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 function):

All significant deficiencies and material weaknesses in the design or operation of internal controls 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.

May 2, 2007

/S/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Ex 31.2

EXHIBIT 31.2

CERTIFICATION

I, Dennis V. Arriola, certify that:

I have reviewed this Quarterly 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.

May 2, 2007

/S/ Dennis V. Arriola

Dennis V. Arriola

Chief Financial Officer

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 San Diego Gas & Electric (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 March 31, 2007 (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.

May 2, 2007

/S/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

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 San Diego Gas & Electric (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.

May 2, 2007

/S/ Dennis V. Arriola

Dennis V. Arriola

Chief Financial Officer