Exhibit 13.01

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

This section of the 2005 Annual Report includes management's discussion and analysis of operating results from 2003 through 2005, and provides information about the capital resources, liquidity and financial performance of Sempra Energy and its subsidiaries (collectively referred to as "the company"). This section also focuses on the major factors expected to influence future operating results and discusses investment and financing activities and plans. It should be read in conjunction with the Consolidated Financial Statements included in this Annual Report.

OVERVIEW

Sempra Energy

Sempra Energy is a Fortune 500 energy services holding company. Its business units provide a wide spectrum of value-added electric and natural gas products and services to a diverse range of customers. Operations are divided into the California Utilities, Sempra Global and Sempra Financial, as described below.

		Sempra Energy
California Utilities			Sempra Global		Sempra Financial
	Southern California Gas Company			Sempra Commodities
	San Diego Gas & Electric Company			Sempra Generation
				Sempra LNG
				Sempra Pipelines & Storage

Summary descriptions of the operating business units are provided below and further detail is provided throughout this section of the Annual Report.

Major events affecting the results for 2005 and/or future years (and the page number where each is discussed) include the following:

• Agreements to settle, subject to court approvals, certain class action antitrust litigation (97);

• Continued development of the liquefied natural gas (LNG) business (20);

• Agreement in January 2006 to sell Sempra Generation's Twin Oaks Power plant (Twin Oaks) in Texas (26);

• Sempra Commodities' sale of its two natural gas storage facilities, Bluewater Gas Storage and Pine Prairie Energy Center, in September 2005 (10);

• Sempra Generation's purchase of the remaining 50-percent interest in El Dorado Energy from Reliant Energy in July 2005 (19);

• Construction by Sempra Generation of the Palomar power plant to be owned by San Diego Gas & Electric Company (SDG&E) (59);

• Favorable resolution of prior years' income tax issues (11);

• Impairment of Sempra Generation's unused turbine set (10);

• Regulatory approval of demand-side management (DSM) award settlements in 2005 (93); and

• Resolution of other regulatory matters, primarily the approval of SDG&E's settlement with the Independent System Operator (ISO, an independent operator of California's wholesale transmission grid) (96).

The California Utilities

Southern California Gas Company (SoCalGas) and SDG&E (collectively, the California Utilities) serve 23 million consumers from California's Central Valley to the Mexican border. Natural gas service is provided throughout Southern California and portions of central California through 6.4 million meters. Electric service is provided throughout San Diego County and portions of Orange County, both in Southern California, through 1.3 million meters.

Sempra Global

Sempra Global is a holding company for most of the subsidiaries of Sempra Energy that are not subject to California utility regulation.

Sempra Global's principal subsidiaries provide the following energy-related products and services:

• Sempra Commodities is a wholesale and retail trader of physical and financial products, including natural gas, power, crude oil and other commodities; a trader and wholesaler of metals, serving a broad range of customers; and an owner of synthetic fuel facilities that generate Section 29 income tax credits;

• Sempra Generation owns and operates power plants, provides energy services and facilities management, and owns mineral rights in properties that produce petroleum and natural gas;

• Sempra LNG is developing receipt terminals for the importation of LNG and has an agreement to supply natural gas to Mexico's government-owned electric utility; and

• Sempra Pipelines & Storage develops and owns natural gas pipelines and storage facilities in the United States and Mexico. It also holds interests in companies that provide natural gas or electricity services to over 2.9 million customers in Argentina, Chile, Mexico and Peru, and owns two small natural gas distribution utilities in the eastern United States.

Sempra Financial

Sempra Financial holds investments in tax-advantaged limited partnerships which own 1,300 affordable-housing properties throughout the United States.

RESULTS OF OPERATIONS

Overall Operations

Net income was $920 million in 2005, a 2.8% increase over 2004, and diluted earnings per share were $3.65, a decrease of 4.7%, as described below. The increase in net income was primarily due to increased profits at Sempra Commodities and SDG&E, offset by expenses associated with an agreement to settle certain litigation. The decrease in diluted earnings per share was due to the higher weighted-average number of shares outstanding resulting from the additional shares of common stock issued in 2005 in settlement of the equity unit contracts discussed in Note 12 of the notes to Consolidated Financial Statements.

The following table shows net income and diluted earnings per share for each of the last five years.

(Dollars in millions, except per share amounts)	Net Income	Diluted Earnings Per Share
2005	$ 920	$ 3.65
2004	$ 895	$ 3.83
2003	$ 649	$ 3.03
2002	$ 591	$ 2.87
2001	$ 518	$ 2.52

Comparison of Earnings

To assist the reader in understanding the trend of earnings, the following table summarizes the major unusual factors affecting net income and operating income in 2005, 2004 and 2003. The numbers in parentheses are the page numbers where each 2005 item is discussed therein.

	Net Income									Operating Income
(Dollars in millions)		2005			2004			2003			2005			2004			2003
Reported amounts	$	920		$	895		$	649		$	1,111		$	1,281		$	943
Unusual items:
Increase in California energy crisis litigation reserves (97)		311			84			38			508			140			66
Resolution of prior years income tax issues (11)		(156	)		(56	)		(118	)		--			--			--
Impairment losses (51)		38			--			68			63			--			101
Sempra Commodities' gain on sale of natural gas storage facilities (59)		(41	)		--			--			(67	)		--			--
DSM awards (93)		(31	)		--			--			(49	)		--			--
Other incentive awards (93)		--			--			(29	)		--			--			(49	)
Other regulatory matters (96)		(24	)		(55	)		--			(33	)		(51	)		--
South Bay charitable contribution deduction (12)		(23	)		--			--			(23	)		--			--
Discontinued operations - AEG1 (11)		9			25			--			--			--			--
Gains on sale of SoCalGas' partnership property and on partial sale of Luz del Sur		--			(14	)		--			--			(15	)		--
Resolution of vendor disputes in Argentina		--			(12	)		(11	)		--			--			--
Gain on settlement of Cameron liability		--			(8	)		--			--			--			--
SDG&E power contract settlement		--			--			(65	)		--			--			(116	)
SONGS2 incentive pricing (ended 12/31/03)		--			--			(53	)		--			--			(89	)
Changes in accounting principles		--			--			46			--			--			--
SoCalGas sublease losses		--			--			11			--			--			19
Impact of the repeal of EITF3 98-10		--			--			(9	)		--			--			(15	)
AEG equity losses - disposed of in April 2004		--			--			5			--			--			--
	$	1,003		$	859		$	532		$	1,510		$	1,355		$	860

1 Atlantic Electric & Gas (AEG)
² San Onofre Nuclear Generating Station (SONGS)
³ Emerging Issues Task Force (EITF)

Net Income (Loss) by Business Unit

	Years ended December 31,
(Dollars in millions)		2005					2004					2003
California Utilities
Southern California Gas Company *		$	211		23	%	$	232		26	%	$	209		32	%
San Diego Gas & Electric Company *			262		28			208		23			334		52
Total California Utilities			473		51			440		49			543		84
Sempra Global
Sempra Commodities			460		50			320		36			157		24
Sempra Generation			164		18			137		15			71		11
Sempra Pipelines & Storage			64		7			63		7			3		--
Sempra LNG			(25	)	(3	)		(8	)	(1	)		(2	)	--
Total Sempra Global			663		72			512		57			229		35
Sempra Financial			23		3			36		4			41		6
Parent and other **			(230	)	(25	)		(68	)	(7	)		(118	)	(18	)
Income from continuing operations			929		101			920		103			695		107
Discontinued operations, net of tax			(9	)	(1	)		(25	)	(3	)		--		--
Cumulative effect of changes in accounting principles			--		--			--		--			(46	)	(7	)
Consolidated net income		$	920		100	%	$	895		100	%	$	649		100	%

* After preferred dividends
** Includes after-tax interest expense ($102 million, $112 million and $100 million in 2005, 2004 and 2003, respectively), after-tax litigation expense, intercompany eliminations recorded in consolidation and certain corporate costs incurred at Sempra Global.

California Utility Operations

The California Utilities are subject to federal, state and local governmental agencies. The primary regulatory agency is the California Public Utilities Commission (CPUC), which regulates utility rates and operations. The Federal Energy Regulatory Commission (FERC) regulates interstate transportation of natural gas and electricity and various related matters. The Nuclear Regulatory Commission regulates nuclear generating plants. Municipalities and other local authorities regulate the location of utility assets, including natural gas pipelines and electric lines. Other business units are also subject to regulation by the FERC, various state commissions, local governmental entities, and various similar authorities in countries other than the United States.

Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues increased by $716 million (16%) to $5.3 billion in 2005, and the cost of natural gas increased by $639 million (25%) to $3.2 billion in 2005. The increases in 2005 were due to higher natural gas prices, which are passed on to customers, offset by a small decrease in volume. In addition, natural gas revenues increased at SoCalGas due to higher authorized margin of $28 million, the CPUC's 2005 Cost of Service decision eliminating 2004 revenue sharing (for which $18 million was included in revenue in 2005), $14 million in DSM awards in 2005 and $14 million of higher revenues for recoverable expenses, which are fully offset in other operating expenses. SDG&E's natural gas revenues further increased due to $7 million in DSM awards in 2005. The company's weighted average cost per million British thermal units (mmbtu) of natural gas was $7.83 in 2005, $5.94 in 2004 and $5.06 in 2003.

Although the current regulatory framework provides that the cost of natural gas purchased for customers and the variations in that cost are passed through to the customers on a substantially concurrent basis, SoCalGas' Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to share in the savings or costs from buying natural gas for customers below or above market-based monthly benchmarks. The mechanism permits full recovery of all costs within a tolerance band around the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. In addition, SDG&E's natural gas procurement Performance-Based Regulation (PBR) mechanism provides an incentive mechanism by measuring SDG&E's procurement of natural gas against a benchmark price comprised of monthly natural gas indices, resulting in shareholder rewards for costs achieved below the benchmark and shareholder penalties when costs exceed the benchmark. Further discussion is provided in Notes 1 and 14 of the notes to Consolidated Financial Statements.

Natural gas revenues increased by $532 million (13%) to $4.5 billion in 2004 compared to 2003, and the cost of natural gas increased by $522 million (25%) to $2.6 billion in 2004 compared to 2003. The increase in 2004 was primarily attributable to natural gas price increases, and at SoCalGas, the increase was further due to an increase in margin of $33 million and $18 million from a favorable Cost of Service decision in 2004, offset by $56 million of approved performance awards recognized during 2003, including $49 million of natural gas procurement awards. Performance awards are discussed in Note 14 of the notes to Consolidated Financial Statements.

Electric Revenue and Cost of Electric Fuel and Purchased Power. Electric revenues increased by $131 million (8%) to $1.8 billion in 2005, and the cost of electric fuel and purchased power increased by $48 million (8%) to $624 million in 2005. The increase in revenue was due to $41 million of higher revenues for recoverable expenses, a DSM award settlement in 2005 of $28 million and $23 million related to the 2005 Internal Revenue Service (IRS) decision relating to the sale of SDG&E's former South Bay power plant. In addition, revenues and costs increased $48 million due to higher purchased power costs.

Electric revenues decreased by $128 million (7%) to $1.7 billion in 2004 compared to 2003, and the cost of electric fuel and purchased power increased by $35 million (6%) to $576 million in 2004 compared to 2003. The decrease in revenues was due to the 2003 recognition of $116 million related to the approved settlement that allocated between SDG&E's customers and shareholders the profits from certain intermediate-term power purchase contracts that SDG&E had entered into during the early stages of California's electric utility industry, and higher 2003 earnings of $25 million from PBR awards. Performance awards are discussed in Note 14 of the notes to Consolidated Financial Statements. In addition, electric revenues and costs increased $35 million due to higher electric commodity costs and volumes.

The tables below summarize the California Utilities' natural gas and electric volumes and revenues by customer class for the years ended December 31, 2005, 2004 and 2003.

Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)

								Transportation and Exchange
			Natural Gas Sales										Total
			Volumes		Revenue			Volumes		Revenue			Volumes		Revenue
2005:
	Residential			271		$	3,193		1		$	6		272		$	3,199
	Commercial and industrial			123			1,257		273			190		396			1,447
	Electric generation plants			1			3		201			88		202			91
	Wholesale			--			--		19			6		19			6
				395		$	4,453		494		$	290		889			4,743
	Balancing accounts and other																510
		Total														$	5,253
2004:
	Residential			287		$	2,904		2		$	7		289		$	2,911
	Commercial and industrial			126			1,013		276			198		402			1,211
	Electric generation plants			--			2		252			90		252			92
	Wholesale			--			--		20			6		20			6
				413		$	3,919		550		$	301		963			4,220
	Balancing accounts and other																317
		Total														$	4,537
2003:
	Residential			273		$	2,479		2		$	7		275		$	2,486
	Commercial and industrial			121			863		277			189		398			1,052
	Electric generation plants			--			3		241			79		241			82
	Wholesale			--			--		20			4		20			4
				394		$	3,345		540		$	279		934			3,624
	Balancing accounts and other																381
		Total														$	4,005

Electric Distribution and Transmission
(Volumes in millions of kWhs, dollars in millions)

		2005					2004					2003
		Volumes		Revenue			Volumes		Revenue			Volumes		Revenue
Residential			7,075		$	738		7,038		$	692		6,702		$	731
Commercial			6,674			654		6,592			644		6,263			674
Industrial			2,148			141		2,072			133		1,976			161
Direct access			3,213			114		3,441			105		3,322			87
Street and highway lighting			93			11		97			11		91			11
Off-system sales			--			--		--			--		8			--
			19,203			1,658		19,240			1,585		18,362			1,664
Balancing accounts and other						131					73					122
	Total				$	1,789				$	1,658				$	1,786

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, as discussed in Note 1 of the notes to Consolidated Financial Statements, the associated volumes and distribution revenues are included in the above table.

Sempra Global and Parent Operating Revenues and Cost of Sales. These tables provide a breakdown of operating revenues and cost of sales at Sempra Global and the parent companies by business unit.

	Years ended December 31,
(Dollars in millions)		2005					2004					2003
OPERATING REVENUES
Sempra Commodities		$	2,724		58	%	$	1,689		52	%	$	1,227		58	%
Sempra Generation *			1,921		41			1,662		51			773		37
Sempra Pipelines & Storage *			329		7			269		8			210		10
Sempra LNG			--		--			--		--			(2	)	--
Total Sempra Global			4,974		106			3,620		111			2,208		105
Parent and other **			(279	)	(6	)		(381	)	(11	)		(108	)	(5	)
Total		$	4,695		100	%	$	3,239		100	%	$	2,100		100	%
COST OF SALES
Sempra Commodities		$	1,267		47	%	$	597		34	%	$	542		45	%
Sempra Generation *			1,332		49			1,198		69			498		41
Sempra Pipelines & Storage *			266		10			209		12			166		14
Total Sempra Global			2,865		106			2,004		115			1,206		100
Parent and other **			(150	)	(6	)		(263	)	(15	)		(2	)	--
Total		$	2,715		100	%	$	1,741		100	%	$	1,204		100	%

* Does not include the revenues or costs of the unconsolidated affiliates that are part of this business unit.
** Includes intercompany eliminations recorded in consolidation, including the Palomar plant as discussed in Note 2 of the notes to Consolidated Financial Statements.

Increases in 2005 revenues and cost of sales reflect increased trading activity and higher commodity prices at Sempra Commodities, primarily as a result of increased volatility in energy markets, and increased Sempra Generation power sales to the DWR as a result of higher natural gas prices.

The increase in 2004 revenues compared to 2003 was primarily due to higher revenues at Sempra Generation resulting from increased volumes of power sales under the DWR contract, and higher revenues at Sempra Commodities resulting from increased commodity revenue, particularly from metals, natural gas and petroleum due to increased volatility and higher prices. The increase in cost of sales was primarily due to costs related to the higher sales volume for Sempra Generation.

Litigation Expenses. Litigation expenses were $551 million, $150 million and $72 million for 2005, 2004 and 2003, respectively. The increases in 2005 and 2004 were primarily due to increases in litigation reserves related to matters arising from the 2000 - 2001 California energy crisis. Note 15 of the notes to Consolidated Financial Statements provides additional information concerning this matter.

Other Operating Expenses. This table provides a breakdown of other operating expenses by business unit.

	Years ended December 31,
(Dollars in millions)		2005				2004				2003
OTHER OPERATING EXPENSES
California Utilities
Southern California Gas Company		$	954	36	%	$	908	40	%	$	916	43	%
San Diego Gas & Electric Company			603	23			574	26			611	29
Total California Utilities			1,557	59			1,482	66			1,527	72
Sempra Global
Sempra Commodities			811	31			556	25			414	20
Sempra Generation			146	6			136	6			122	6
Sempra Pipelines & Storage			41	1			43	2			43	2
Sempra LNG			34	1			26	1			1	--
Total Sempra Global			1,032	39			761	34			580	28
Parent and other *			45	2			--	--			1	--
Total		$	2,634	100	%	$	2,243	100	%	$	2,108	100	%

* Includes intercompany eliminations recorded in consolidation.

Other operating expenses for 2005 increased primarily due to an increase in expenses at Sempra Commodities attributable to the growth in revenues noted previously. In addition, other operating expenses at the California Utilities increased due to $59 million of favorable resolutions of regulatory matters in 2004 and $51 million of higher recoverable expenses in 2005, offset by the $42 million net effect related to the 2005 recovery of line losses and grid management charges arising from the favorable settlement with the ISO.

The increase in other operating expenses in 2004 from 2003 was primarily the result of higher costs at Sempra Global, particularly at Sempra Commodities due to increased trading activity, start-up costs at Sempra LNG and higher costs at Sempra Generation due to new generating plants coming on line in 2003. These increases were offset by a decrease at the California Utilities in 2004, primarily resulting from the favorable resolution of regulatory matters in 2004 and losses in 2003 associated with a sublease of portions of the SoCalGas headquarters building.

Gains on Sale of Assets. 2005 included Sempra Commodities' $106 million ($67 million after related costs) before-tax gain on the sale of its two natural gas storage facilities, Bluewater Gas Storage and Pine Prairie Energy Center. 2004 included SoCalGas' $15 million before-tax gain on the sale of partnership properties.

Impairment Losses. Impairments in 2005 included a $63 million before-tax write-down of unused gas and steam turbines at Sempra Generation. Impairments in 2003 included a $77 million before-tax write-down of the carrying value of the assets of Frontier Energy, a small utility subsidiary of Sempra Pipelines & Storage, and a $24 million before-tax write-down of the carrying value of the assets at AEG.

Other Income, Net. Other income, net, as discussed further in Note 1 of the notes to Consolidated Financial Statements and which consists primarily of equity earnings from unconsolidated subsidiaries, was $51 million, $33 million and $(40) million in 2005, 2004 and 2003, respectively. The increases in 2005 and 2004 were due to higher equity earnings at Sempra Generation (resulting from the acquisition of the Coleto Creek coal plant (Coleto Creek) in July 2004 by a joint venture 50% owned by Sempra Generation) and lower equity losses at Sempra Financial (due to the 2004 sale of an alternative-fuel investment). The increases were offset by a $12 million decrease in regulatory interest at SoCalGas primarily due to a Cost of Service decision in 2004, and the $13 million before-tax gain in 2004 on the settlement of an unpaid portion of the purchase price of the proposed Cameron LNG project for an amount less than the liability (which had been recorded as a derivative). The increase in 2004 compared to 2003 was due to lower equity losses at Sempra Financial, increased equity earnings at Sempra Generation resulting from the acquisition of the Coleto Creek coal plant and the $13 million before-tax gain in 2004 related to Cameron LNG.

Interest Income. Interest income was $75 million, $69 million and $104 million in 2005, 2004 and 2003, respectively. The decrease in 2004 from 2003 was due to $59 million recorded as a result of the favorable resolution of income tax issues with the IRS in 2003, offset by interest recorded on income tax receivables in 2004.

Income Taxes. For the years ended 2005, 2004 and 2003, the company had income tax expenses of $42 million, $193 million and $47 million, respectively. The effective income tax rates were 5 percent, 18 percent and 7 percent, respectively. The decrease in 2005 expense was due to lower pre-tax income from continuing operations and the lower effective tax rate. The decrease in the effective rate was due primarily to $156 million of favorable resolution of prior years' income tax issues in 2005 offset by $56 million of favorable resolutions in 2004. The change in income tax expense in 2004 from 2003 was due primarily to higher taxable income. Additionally, 2003 was impacted by the favorable resolution of income tax issues, which reduced income tax expense by $83 million. Income before taxes in 2003 included $59 million in interest income arising from the income tax settlement, resulting in an offsetting $24 million income tax expense.

Equity in Income of Certain Unconsolidated Subsidiaries. For the years ended 2005, 2004 and 2003, equity in income of certain unconsolidated affiliates, net of tax, as discussed further in Note 3 of the notes to Consolidated Financial Statements, was $55 million, $62 million and $62 million, respectively. The decrease in 2005 was primarily due to a $5 million after-tax gain at Sempra Pipelines & Storage from the 2004 partial sale of Luz del Sur S.A.A. (Luz del Sur), its Peruvian electric utility.

Discontinued Operations. In the second quarter of 2004, Sempra Energy disposed of its interest in AEG, a marketer of power and natural gas commodities to commercial and residential customers in the United Kingdom. Losses related to AEG were $9 million and $25 million for the years ended December 31, 2005 and 2004, respectively. The 2005 loss was primarily attributable to foreign currency translation adjustments associated with AEG's remaining assets and liabilities, legal costs and reserves against accounts receivable. Note 4 of the notes to Consolidated Financial Statements provides further details.

During 2003, the company accounted for its investment in AEG under the equity method of accounting. As such, for the year ended December 31, 2003, the company recorded its share of AEG's net losses of $5 million in Other Income, Net on the Statements of Consolidated Income. Effective December 31, 2003, AEG was consolidated as a result of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, Consolidation of Variable Interest Entities, as discussed in Note 1 of the notes to Consolidated Financial Statements.

Net Income. Variations in net income are summarized in the table shown previously under "Comparison of Earnings."

Business Unit Results

Southern California Gas Company

SoCalGas recorded net income of $211 million, $232 million and $209 million in 2005, 2004 and 2003, respectively. The decrease in 2005 was due primarily to the resolution of the 2004 Cost of Service proceedings (as discussed further in Note 14 of the notes to Consolidated Financial Statement) which favorably affected 2004 net income by $34 million, an increase of $33 million after-tax in California energy crisis litigation expenses (as discussed further in Note 15 of the notes to Consolidated Financial Statements) and the $9 million after-tax gain from the sale of the Hawaiian Gardens property in 2004, offset by favorable resolution of income tax issues in 2005 of $24 million, higher margins in 2005 of $17 million after-tax and the recognition of DSM awards of $9 million after-tax in 2005. In addition to the 2004 matters noted above, the increase in 2004 from 2003 was due to higher margins in 2004 and losses in 2003 associated with a long-term sublease of portions of its headquarters building, offset by the favorable resolution of income tax issues and by higher GCIM awards in 2003.

San Diego Gas & Electric Company

SDG&E recorded net income of $262 million, $208 million and $334 million in 2005, 2004 and 2003, respectively. The increase in 2005 was due primarily to the regulatory resolution of the recovery of line losses and grid management charges arising from the favorable after-tax settlement of $24 million with the ISO (as discussed further in Note 14 of the notes to Consolidated Financial Statements), the recognition of DSM awards of $22 million after-tax, favorable resolution of income tax issues of $60 million, and the $23 million recovery of costs associated with the 2005 IRS decision relating to the sale of the South Bay power plant, offset by a $17 million increase in after-tax California energy crisis litigation expenses, the favorable after-tax impact of $21 million from the resolution of the 2004 Cost of Service proceeding and $19 million lower after-tax electric transmission and distribution margin and higher operational costs in 2005. In addition to the 2004 matters noted above, the decrease in 2004 from 2003 was primarily due to the favorable resolution of income tax issues in 2003, which positively affected 2003 earnings by $79 million, income of $65 million after-tax in 2003 related to the approved settlement of intermediate-term power purchase contracts; the 2003 Incremental Cost Incentive Pricing income (as discussed further in Note 13 of the notes to Consolidated Financial Statements) for SONGS ($53 million after-tax) and higher performance awards in 2003, offset by higher electric transmission and distribution margin in 2004.

Sempra Commodities

Sempra Commodities recorded net income of $460 million, $320 million and $157 million in 2005, 2004 and 2003, respectively, excluding the negative impact of the cumulative effect of the change in accounting principle of $29 million in 2003. The increase in 2005 was due to improvements in its North American operations and most product line segments, as shown below, the $41 million after-tax gain on the September 2005 sale of two natural gas storage facilities and a $26 million favorable resolution of prior years' income tax issues in 2005. The increase in 2004 from 2003 was primarily attributable to higher trading margins, resulting from increased volatility in the markets, particularly for metals, natural gas and petroleum. In addition to the effect of changing prices and volumes, earnings variability will continue in future periods as a result of natural gas and oil inventories, and of storage and transportation capacity contracts' not being marked to market while the economically offsetting derivative instruments are marked to market. Margin, summarized below by geographical region and product line, consists of net revenues less related costs (primarily brokerage, transportation and storage) plus or minus net interest income/expense, and is used by management in evaluating geographical and product line performance. Results for 2005 include $108 million of gains recorded at the time a structured derivative is originated, commonly referred to as "day-one" gains.

	Years ended December 31,
Margin (Dollars in millions)		2005				2004				2003
Geographical:
North America		$	1,091	81	%	$	689	67	%	$	439	72	%
Europe and Asia			255	19			338	33			172	28
		$	1,346	100	%	$	1,027	100	%	$	611	100	%
Product Line:
Gas		$	439	32	%	$	318	31	%	$	146	24	%
Power			443	33			170	17			137	22
Oil - crude and products			292	22			268	26			128	21
Metals			54	4			180	17			96	16
Other			118	9			91	9			104	17
		$	1,346	100	%	$	1,027	100	%	$	611	100	%

Other includes synthetic fuel credit operations of $110 million, $97 million and $77 million in 2005, 2004 and 2003, respectively, which contributed $36 million, $29 million and $23 million to net income in 2005, 2004 and 2003, respectively.

A summary of Sempra Commodities' unrealized revenues for trading activities follows:

	Years ended December 31,
(Dollars in millions)	2005			2004			2003
Balance at January 1	$	1,193		$	347		$	270
Additions		1,241			1,606			830
Realized		(946	)		(760	)		(703	)
Cumulative effect adjustment		--			--			(50	)
Balance at December 31	$	1,488		$	1,193		$	347

The estimated fair values as of December 31, 2005, and the scheduled maturities related to the unrealized revenues are (dollars in millions):

	Fair Market			Scheduled Maturity (in months)
Source of fair value	Value					0-12		13-24		25-36			>36
Prices actively quoted	$	1,188			$	725	$	92	$	297		$	74
Prices provided by other external sources		52				3		2		--			47
Prices based on models and other valuation methods		(12	)			--		--		--			(12	)
Over-the-counter (OTC) revenue		1,228	*			728		94		297			109
Exchange contracts **		260				464		71		(272	)		(3	)
Total	$	1,488			$	1,192	$	165	$	25		$	106

* The present value of unrealized revenue to be received from outstanding OTC contracts.
** Cash received (paid) associated with open exchange contracts.

Sempra Generation

Sempra Generation recorded net income of $164 million in 2005, $137 million in 2004 and $71 million in 2003, excluding the favorable impact of the cumulative effect of the change in accounting principle of $9 million in 2003. The 2005 increase was due to $30 million of higher mark-to-market after-tax gains on long-term forward contracts for the sale of power during 2007 to 2012, $10 million of higher equity earnings from the Coleto Creek power plant (a full year of equity earnings in 2005 compared to six months in 2004), $10 million of higher earnings at Sempra Generation's energy services and facilities management businesses, $6 million of higher interest income, and improved earnings attributable to increased sales at its other power plants. The increases were offset by after-tax impairment losses of $38 million in 2005 related to the write-down of unused gas and steam turbines. The increase in 2004 from 2003 was primarily because power sales under Sempra Generation's contract with the DWR were at lower levels in 2003 and prior years than in 2004 and future years.

Sempra Pipelines & Storage

Net income for Sempra Pipelines & Storage was $64 million, $63 million and $3 million in 2005, 2004 and 2003, respectively. The increase in 2004 from 2003 was due to the $50 million after-tax write-down in 2003 of the carrying value of the assets of Frontier Energy, $11 million higher after-tax earnings in 2004 from the company's operations in Mexico, a $5 million after-tax gain on the sale of a portion of its interests in Luz del Sur, offset by $9 million of income tax accruals for issues related to its South American investments. Both 2004 and 2003 were favorably impacted by the resolution of vendor disputes in Argentina.

Sempra LNG

Sempra LNG recorded net losses of $25 million, $8 million and $2 million for the years ended December 31, 2005, 2004 and 2003, respectively. The increase in 2005 was primarily due to higher development costs and general and administrative expenses in 2005 and an $8 million after-tax gain in 2004 from the settlement of an unpaid portion of the purchase price of the Cameron liquefied natural gas project for an amount less than the liability (which had been recorded as a derivative).

Sempra Financial

Sempra Financial recorded net income of $23 million in 2005, $36 million in 2004 and $41 million in 2003. The decreases in 2005 and 2004 were due to lower income tax credits, offset by lower equity losses, primarily as a result of maturing affordable housing investments and the sale of its Section 29 tax credit investment (Carbontronics) during the third quarter of 2004. The sale transaction has been accounted for under the cost recovery method, whereby future proceeds in excess of Carbontronics' carrying value will be recorded as income as received. As a result of this sale, Sempra Financial will not be recognizing Section 29 income tax credits in the future. Section 29 income tax credits are discussed further in Note 7 of the notes to Consolidated Financial Statements.

Parent and Other

Net losses for Parent and Other were $230 million, $68 million and $118 million in 2005, 2004 and 2003, respectively. Net losses consist primarily of interest expense, litigation expense and tax-related adjustments. Interest expense was $102 million, $112 million and $100 million for 2005, 2004 and 2003, respectively. In addition to interest expense, net losses for 2005 included $193 million after-tax related to the California energy crisis litigation, offset by a $41 million favorable resolution of prior year's income tax issues. For 2004, net losses included $27 million after-tax of litigation expenses, offset by a reduction in income tax accruals. Additionally, 2003 losses include the $21 million after-tax write down of the carrying value of AEG's assets.

Book Value Per Share

Book value per share was $23.95, $20.77 and $17.17, at December 31, 2005, 2004 and 2003, respectively. The increases in 2005 and 2004 were primarily the result of comprehensive income's exceeding dividends, and sales of additional shares of common stock for a per-share price in excess of its book value, primarily in connection with the equity units described in Note 12 of the notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

The company's California Utility operations and Sempra Generation's power sale contract with the DWR generally are the major source of liquidity. A substantial portion of the funding of the company's capital expenditures and its ability to pay dividends is dependent on the relatively stable pattern of earnings by the California Utilities and Sempra Generation's long-term power sale contracts. The availability of capital for other business operations is also greatly affected by Sempra Commodities' liquidity and margin requirements, which fluctuate substantially. Sempra Generation's margin requirements, as discussed below, may also fluctuate substantially. The company's expansion, particularly in the LNG business, also requires the issuances of securities from time to time.

At December 31, 2005, there was $772 million in unrestricted cash and $4.7 billion in available unused, committed lines of credit to provide liquidity and support commercial paper. At December 31, 2005, $22 million of these lines supported variable-rate debt. 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 to fund shareholder dividends, any new business acquisitions or start-ups, and other commitments. Forecasted capital expenditures for the next five years are discussed in "Future Construction Expenditures and Investments." If cash flows from operations were to be significantly reduced or the company were to be unable to issue new securities under acceptable terms, the company would be required to reduce non-utility capital expenditures, trading operations and/or investments in new businesses. 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.

At the California Utilities, cash flows from operations, security issuances and/or capital contributions by Sempra Energy are expected to continue to be adequate to meet utility capital expenditure requirements. In June 2004, SDG&E received CPUC approval of its intended 2006 purchase from Sempra Generation of the 550-megawatt (MW) Palomar generating facility being constructed in Escondido, California. As a result, SDG&E's dividends to Sempra Energy have been suspended to increase SDG&E's equity in preparation for the purchase of the completed facility, expected in the first half of 2006, and the level of future dividends will be affected by SDG&E's increased capital expenditures. Note 2 of the notes to Consolidated Financial Statements provides additional discussion on the Palomar plant.

Sempra Commodities provides or requires cash as the level of its net trading assets fluctuates with prices, volumes, margin requirements (which are substantially affected by credit ratings and commodity price fluctuations) and the length of its various trading positions.

Sempra Commodities' intercompany borrowings were $638 million and $421 million at December 31, 2005 and 2004, respectively, and as high as $1.3 billion and $747 million in 2005 and 2004, respectively. Sempra Commodities' external debt was $103 million and $161 million at December 31, 2005 and 2004, respectively. Company management continuously monitors the level of Sempra Commodities' cash requirements in light of the company's overall liquidity. Such monitoring includes the procedures discussed in "Market Risk."

Sempra Generation's projects have been financed through a combination of operating cash flow, project financing, funds from the company and external borrowings. Sempra Generation may return funds to the company if it proceeds with plans to sell certain plants as discussed in Note 3 of the notes to Consolidated Financial Statements.

Sempra Generation's long-term power sale contracts typically contain collateral requirements related to credit lines. The collateral arrangements provide for Sempra Generation and/or the counterparty to post cash, guarantees or letters of credit to the other party for exposure in excess of established thresholds. Sempra Generation may be required to provide collateral when market price movements adversely affect the counterparty's cost of replacement energy supplies were Sempra Generation to fail to deliver the contracted amounts. As of December 31, 2005, Sempra Generation had $267 million of outstanding collateral requirements under these contracts, portions of which have been remitted or guaranteed at December 31, 2005. The $267 million excludes a $280 million collateral exposure under a purchase power agreement related to Twin Oaks. This collateral exposure will be assumed by the buyer of the power plant when the sale of the facility is completed, which is expected to occur in the first half of 2006.

Sempra Pipelines & Storage is expected to require funding from the company and/or external sources to continue the expansion of its existing natural gas distribution operations in Mexico, its Liberty Gas Storage (Liberty) facility, its planned participation in the development of a natural gas pipeline in conjunction with Kinder Morgan Energy Partners, L.P. (KMP), as discussed in "Investments," and its planned development of pipelines to serve LNG facilities in Baja California, Mexico; Louisiana and Texas, as discussed in Note 2 of the notes to Consolidated Financial Statements.

Sempra LNG will require funding for its planned development of LNG receiving facilities. While Sempra LNG's $1.25 billion credit facility and other Sempra Energy sources are expected to be adequate for these requirements, the company may decide to use project financing if that is believed to be advantageous.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $521 million, $1 billion and $1.2 billion for 2005, 2004 and 2003, respectively.

The 2005 change in net cash provided by operating activities was primarily due to a $608 million increase in net trading assets and a $400 million decrease in overcollected regulatory balancing accounts in 2005, offset by a $478 million increase in other liabilities in 2005.

The decrease in cash flows from operations in 2004 compared to 2003 was primarily attributable to an increase in net trading assets in 2004 compared to a decrease in 2003, increased deposits with customers and a higher increase in accounts receivable in 2004, offset by an increase in overcollected regulatory balancing accounts at SoCalGas in 2004 compared to a decrease in 2003, and higher net income and higher accounts payable in 2004.

The company made pension plan and other postretirement benefit plan contributions of $24 million and $45 million, respectively, during 2005, and $27 million and $50 million, respectively, during 2004.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $1.2 billion, $611 million and $1.3 billion for 2005, 2004 and 2003, respectively.

The increase in cash used in investing activities between 2005 and 2004 was primarily attributable to a $321 million increase in capital expenditures in 2005, $363 million in proceeds from the sale of U.S. Treasury obligations that previously securitized the synthetic lease for one of Sempra Generation's power plants in 2004 and $157 million in proceeds from the disposal of AEG's discontinued operations in 2004, offset by $247 million in proceeds from the sale of Sempra Commodities' natural gas storage sites in 2005.

The decrease in cash used in investing activities in 2004 compared to 2003 was primarily due to proceeds from the sale of the U.S. Treasury obligations. The collateral was no longer necessary since Sempra Generation bought out the lease in January 2004. The decrease in cash used in investing activities was also due to lower investments in the Elk Hills power plant (Elk Hills), which was completed in 2003, and reduced capital spending for the completed Termoeléctrica de Mexicali (TDM) and Mesquite power plants, offset by investments made in Topaz Power Partners (Topaz) in 2004. In addition, the company received proceeds of $157 million from the disposal of AEG's discontinued operations.

Expenditures for property, plant and equipment and for investments are presented in the following table.

(Dollars in millions)	Property, plant and equipment	Investments in and acquisitions of subsidiaries
2005	$ 1,404	$ 86
2004	$ 1,083	$ 74
2003	$ 1,049	$ 202
2002	$ 1,214	$ 429
2001	$ 1,068	$ 111

The California Utilities

Capital expenditures for property, plant and equipment by the California Utilities were $825 million in 2005 compared to $725 million in 2004 and $762 million in 2003.

In December 2005, SDG&E submitted its initial request to the CPUC for a proposed new transmission power line between the San Diego region and the Imperial Valley. The proposed line, called the Sunrise Powerlink, would be capable of providing electricity to 650,000 homes and is estimated to cost between $1 billion and $1.4 billion. SDG&E expects to submit a proposed route and an alternative route to the CPUC in 2006.

Sempra Generation

Sempra Generation owns and operates power plants in the Pacific Southwest, Texas and Mexico. The following table lists the MW capacity of each operating power plant. All of the plants are natural gas-fired facilities, except for Coleto Creek and Twin Oaks, which are coal-fired. On January 18, 2006, Sempra Generation announced an agreement for the sale of Twin Oaks.

Power Plant	Maximum Generating Capacity (MW)		Location
Pacific Southwest:
Mesquite Power	1,250		Arlington, AZ
TDM	625		Mexicali, Baja California, Mexico
Elk Hills (50% owned)	275	*	Bakersfield, CA
El Dorado	480		Boulder City, NV
	2,630
Texas:
Coleto Creek (50% owned)	316	*	Goliad County, TX
Twin Oaks	305		Bremond, TX
Three other active Topaz
power plants (50% owned)	554	*	South Central, TX
	1,175
Total MW in operation	3,805

* Sempra Generation's share

Additional information concerning Sempra Generation's facilities is provided in Notes 2, 3 and 15 of the notes to Consolidated Financial Statements.

Sempra LNG

Sempra LNG develops and builds, and will operate LNG receipt terminals and sell regasified LNG. Information concerning its projects in Baja California, Mexico; Louisiana and Texas is provided in Note 2 of the notes to Consolidated Financial Statements.

Sempra Pipelines & Storage

Note 2 of the notes to Consolidated Financial Statements provides information concerning expenditures by Sempra Pipelines & Storage for its natural gas pipelines and storage facilities.

Investments

Investment and acquisition costs were $86 million, $74 million and $202 million for 2005, 2004 and 2003, respectively. The increase in 2005 was primarily due to the purchase of Reliant Energy's 50-percent interest in El Dorado, as discussed below. The decrease in 2004 was due to the sale of the U.S. Treasury obligations and lower investments in Elk Hills, offset by investments made in Topaz in 2004.

Sempra Generation

In July 2005, Sempra Generation purchased Reliant Energy's 50-percent interest in El Dorado for $132 million (including assumed debt), resulting in Sempra Generation's having full ownership of the 480-MW El Dorado power plant.

In December 2005, Sempra Generation announced plans to sell or refinance its Texas-based power plants due to the increased market valuation of coal-fired power plants in Texas. The coal-fired assets involved in the announcement include the company's wholly owned Twin Oaks and Coleto Creek, which the company co-owns in the Topaz joint venture with Carlyle/Riverstone. The joint venture also owns three operating natural gas and oil-fired plants in Laredo, San Benito and Corpus Christi, Texas that were included in the announcement. On January 18, 2006, Sempra Generation announced an agreement to sell Twin Oaks.

Information concerning Sempra Generation's investments in Topaz and Elk Hills is provided in Note 3 of the notes to Consolidated Financial Statements.

Sempra Pipelines & Storage

In December 2005, Sempra Pipelines & Storage entered into definitive agreements with KMP to jointly pursue through Rockies Express Pipeline LLC (Rockies Express) development of a proposed natural gas pipeline, the Rockies Express Pipeline, that would link producing areas in the Rocky Mountain region to the upper Midwest and the Eastern United States. Also in December 2005, a subsidiary of Sempra Global entered into a binding precedent agreement with Rockies Express for 200 million cubic feet per day of capacity on the Rockies Express Pipeline, which will have capacity of up to 2 billion cubic feet (bcf) per day.

In November 2005, EnCana Marketing, a subsidiary of EnCana, entered into a binding precedent agreement with Rockies Express for 500 million cubic feet per day of natural gas capacity on the proposed Rockies Express Pipeline. At the same time, Rockies Express entered into a purchase-and-sale agreement with Alenco Pipelines Inc, another subsidiary of EnCana, for the purchase of the Entrega Pipeline, which purchase is anticipated to close in the first quarter of 2006. Segment 1 of the Entrega Pipeline, which runs from the Meeker Hub in Colorado to Wamsutter, Wyoming, has been completed. Under the terms of the purchase-and-sale agreement, Rockies Express is obligated to construct the second segment of the Entrega Pipeline, which will run from Wamsutter to an interconnection with the Rockies Express Pipeline at the Cheyenne Hub in Colorado.

Also in November 2005, Sempra Pipelines & Storage and KMP announced a memorandum of understanding with Overthrust Pipeline Company (Overthrust), a subsidiary of Questar Corp., to enter into a long-term lease to provide Rockies Express Pipeline with capacity for up to 1.5 bcf per day on Overthrust's pipeline. The capacity lease will effectively extend the Rockies Express Pipeline to the Opal Hub in Wyoming.

At December 31, 2005, binding, conforming commitments (including the commitments by EnCana and Sempra Energy) in connection with the recent open seasons held to solicit shipper support for the Rockies Express Pipeline project aggregated over 1 bcf per day. Additionally, a variety of non-conforming bids were received and Rockies Express is currently in negotiations with these and other shippers to finalize binding precedent agreements for transportation on the Rockies Express Pipeline. The total cost of the project, including the cost of the Entrega Pipeline and capitalized interest during construction, is expected to be $4.0 - $4.4 billion.

During the first quarter of 2005, Sempra Pipelines & Storage filed for FERC authorization to construct and operate the Liberty facility and the Port Arthur pipeline. In May 2005, ProLiance Transportation and Storage, LLC acquired a 25-percent ownership in Liberty. In December 2005, the FERC issued a Certificate of Public Convenience and Necessity for Liberty. Further discussion is provided in Note 2 of the notes to Consolidated Financial Statements.

Discussion of investing activities by Sempra Pipelines & Storage, including the $201 million cumulative foreign currency exchange adjustment relating to its investments in Argentina, is provided in Note 3 of the notes to Consolidated Financial Statements.

Sempra LNG

In January 2005, Sempra LNG was awarded a 15-year natural gas supply contract by Mexico's state owned electric utility, Comisión Federal de Electricidad (CFE). The contract is estimated at $1.4 billion over its life and supports the CFE's future energy needs in northern Baja California, including the Presidente Juarez power plant in Rosarito. The supply is expected to come from natural gas processed at Energía Costa Azul, Sempra LNG's regasification terminal in Baja California. Starting in 2008 and running through 2022, the agreement provides the CFE with an average of about 130 million cubic feet per day of natural gas. In early 2005, Sempra LNG began construction of Energía Costa Azul, which is expected to begin operations in 2008. The terminal and related pipeline are expected to cost approximately $1 billion and will be capable of processing 1 bcf of natural gas per day. Additional discussion of the terminal is provided in Note 2 of the notes to the Consolidated Financial Statements.

In August 2005, Sempra LNG announced an agreement with Eni S.p.A. for 40 percent of the send-out capacity of the Cameron LNG terminal. Combined with other, preliminary non-binding agreements with multiple parties, this allowed the company to begin construction, with the commencement of commercial operations slated for 2008. In January 2006, Sempra LNG announced it has received approval from the FERC to begin the mandatory pre-filing process for the proposed $250 million expansion of the terminal's production capacity to 2.65 bcf of natural gas per day from 1.5 bcf per day. The final FERC decision is expected in early 2007.

During the first quarter of 2005, Sempra LNG filed for FERC authorization to construct and operate the Port Arthur LNG receiving terminal. The terminal will be capable of processing 1.5 bcf of natural gas per day and can be expanded to 3 bcf per day. Project approval and the start of construction is expected in 2007, with the start-up slated for 2010.

In June 2005, Sempra LNG terminated an agreement signed in December 2004 with the Alaskan Gas Line Port Authority to develop the "All Alaska Pipeline Project."

Future Construction Expenditures and Investments

The company expects to make capital expenditures and investments of $2.3 billion in 2006. Significant capital expenditures are expected to include $1.2 billion for California utility plant improvements and $600 million for the development of LNG regasification terminals. These expenditures and investments are expected to be financed by cash flows from operations, asset sales and security issuances.

Over the next five years, the company expects to make capital expenditures and investments of $6 billion at the California Utilities, and has identified $4 billion of capital expenditures at the other subsidiaries, including the development of the LNG facilities and pipelines. The former amount includes $500 million for the Palomar power plant which is being constructed by Sempra Generation and which will be purchased by SDG&E when completed in the first half of 2006. The construction costs were recorded by Sempra Generation as incurred and will not result in a significant amount of capital expenditures in 2006.

Construction, investment and financing programs are periodically reviewed and revised by the company in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost of capital and environmental requirements, as discussed in Note 15 of the notes to Consolidated Financial Statements.

The company's level of construction expenditures and investments in the next few years may vary substantially, and will depend on the availability of financing, regulatory approvals and business opportunities providing desirable rates of return. The company intends to finance its capital expenditures in a manner that will maintain its strong investment-grade ratings and capital structure.

The amounts and timing of capital expenditures are subject to approvals by the CPUC, the FERC and other regulatory bodies.

The possible SDG&E involvement with completion of the Otay Mesa power plant is discussed in Note 13 of the notes to Consolidated Financial Statements.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash provided by (used in) financing activities totaled $1 billion, $(380) million and $89 million for 2005, 2004 and 2003, respectively.

The 2005 increase in cash provided by financing activities was due to a $1.1 billion decrease in payments on long-term debt, a $584 million increase in issuances of common stock in 2005 in connection with the Equity Units' $600 million purchase contract settlement and a $265 million net increase in short-term borrowings, offset by a $235 million decrease in issuances of long-term debt, the redemption of $200 million of mandatorily redeemable preferred securities, a $90 million increase in repurchases of common stock and a $73 million increase in dividends paid in 2005. The 2004 increase in cash used in financing activities was due to higher payments on long-term debt and lower issuances of common stock, offset by an increase in short-term debt.

Long-Term and Short-Term Debt

During 2005, the company's long-term debt increased $334 million to $4.9 billion. At December 31, 2005, the company's long-term debt had a weighted average life to maturity of 10.4 years and a weighted average interest rate of 5.34 percent. In 2005, the company issued $762 million in long-term debt.

In May 2005, SDG&E publicly offered and sold $250 million of 5.35% first mortgage bonds, maturing in 2035. In November 2005, SDG&E and SoCalGas each publicly offered and sold $250 million of 5.30% and 5.75%, respectively, first mortgage bonds, maturing in 2015 and 2035, respectively.

Payments on long-term debt in 2005 included $300 million of notes payable that matured in December 2005 and $66 million related to SDG&E's rate-reduction bonds. Also in 2005, Sempra Generation repaid $122 million debt assumed in the purchase of the remaining interest in El Dorado and Sempra Financial repaid $28 million of debt incurred to acquire limited partnership interests.

In May 2004, the company issued $600 million of senior unsecured notes, consisting of $300 million of 4.75-percent fixed-rate, five-year notes and $300 million of four-year, floating-rate notes. The proceeds of the issuance were used to repay $500 million of debt maturing July 1, 2004, and for general corporate purposes.

In June 2004, SDG&E issued $251 million of first mortgage bonds and applied the proceeds in July to refund an identical amount of first mortgage bonds and related tax-exempt industrial development bonds of a shorter maturity. The bonds secure the repayment of tax-exempt industrial development bonds of an identical amount, maturity and interest rate issued by the City of Chula Vista, the proceeds of which were loaned to SDG&E and which are repaid with payments on the first mortgage bonds. The bonds were initially issued as auction-rate securities, but SDG&E entered into floating-for-fixed interest-rate swap agreements that effectively changed the bonds' interest rates to fixed rates in September 2004. The swaps are set to expire in 2009.

In December 2004, SoCalGas issued $100 million of floating rate first mortgage bonds maturing in December 2009. The interest rate is based on the 3-month LIBOR rate plus 0.17%.

Payments on long-term debt in 2004 included $500 million of notes payable that matured in July 2004, $426 million of first mortgage bonds and $66 million of rate-reduction bonds. Also in 2004, Sempra Generation purchased the assets of Mesquite Trust, thereby extinguishing $630 million of debt outstanding, and Sempra Financial repaid $34 million of debt incurred to acquire limited partnership interests.

In 2003, the company issued $900 million in long-term debt, consisting of $400 million of senior unsecured notes and $500 million of first mortgage bonds issued by SoCalGas.

Payments on long-term debt in 2003 included $100 million of the borrowings under a line of credit and $66 million of rate-reduction bonds. In 2003, Sempra Financial repaid $36 million of debt incurred to acquire limited partnership interests. Repayments also included $325 million of SoCalGas' first mortgage bonds. In addition, $70 million of SoCalGas' $75 million medium-term notes were put back to the company.

Note 5 of the notes to Consolidated Financial Statements provides information concerning lines of credit and further discussion of debt activity.

Capital Stock Transactions

During 2005, 19.7 million shares of common stock were issued at $30.52 per share in settlement of the 2002 share purchase contracts included in the company's $600 million of Equity Units. Also during 2005, the company repurchased common stock for $95 million, including 2.3 million shares of common stock at a cost of $88 million in connection with the share repurchase program discussed in Note 12 of the notes to Consolidated Financial Statement.

In October 2003, the company completed a common stock offering of 16.5 million shares priced at $28 per common share, resulting in net proceeds of $448 million. The proceeds were used primarily to pay off short-term debt.

Dividends

Dividends paid on common stock were $268 million in 2005, $195 million in 2004 and $182 million in 2003. In February 2006, the company's board of directors approved an increase in the quarterly dividend from $0.29 per share to $0.30 per share.

The payment and amount of future dividends are within the discretion of the company's board of directors. The CPUC's regulation of the California Utilities' capital structure limits the amounts that are available for loans and dividends to the company from the California Utilities. At December 31, 2005, SoCalGas could have provided a total (combined loans and dividends) of $118 million to Sempra Energy and no amounts were available from SDG&E.

Capitalization

Total capitalization, including short-term debt and the current portion of long-term debt and excluding the rate-reduction bonds (which are non-recourse to the company), at December 31, 2005 was $12 billion. The debt-to-capitalization ratio was 48 percent at December 31, 2005. Significant changes affecting capitalization during 2005 included common stock issuances, long-term borrowings and repayments, short-term borrowings, income and dividends. Additional discussion related to the significant changes is provided in Notes 5 and 12 of the notes to Consolidated Financial Statements and "Results of Operations" above.

Commitments

The following is a summary of the company's principal contractual commitments at December 31, 2005. Additional information concerning commitments is provided above and in Notes 5, 8, 11 and 15 of the notes to Consolidated Financial Statements.

(Dollars in millions)		2006		2007 and 2008		2009 and 2010		Thereafter		Total
Short-term debt	$	1,062	$	--	$	--	$	--	$	1,062
Long-term debt		101		994		937		2,892		4,924
Interest on debt (1)		283		477		381		2,235		3,376
Due to unconsolidated affiliates		--		62		--		100		162
Preferred stock of subsidiaries subject to mandatory redemption		3		16		--		--		19
Operating leases		113		200		166		155		634
Litigation reserve		110		135		53		79		377
Purchased-power contracts		285		614		596		2,641		4,136
Natural gas contracts		2,083		718		190		196		3,187
Construction commitments		585		315		7		20		927
Twin Oaks coal supply (2)		28		55		53		258		394
SONGS decommissioning		14		11		--		314		339
Other asset retirement obligations		5		32		28		572		637
Pension and postretirement benefit obligations (3)		79		208		241		667		1,195
Environmental commitments		29		29		--		--		58
Other		5		10		16		16		47
Totals	$	4,785	$	3,876	$	2,668	$	10,145	$	21,474
(1) Based on forward rates in effect at December 31, 2005. (2) An agreement has been signed to sell Twin Oaks. (3) Amounts are after reduction for the Medicare Part D subsidy and only include expected payments to the plans for the next 10 years.

The table excludes trading liabilities and commitments, which are primarily offset by trading assets; contracts between affiliates; intercompany debt; individual contracts that have annual cash requirements less than $1 million; and employment contracts.

Off Balance-sheet Arrangements

At December 31, 2005, the company was contingently liable for $131 million of accounts receivable from government agencies that it had sold, with recourse, to a financial institution.

As discussed in Note 3 in regards to American Electric Power and in Note 15 in regards to Chilquinta Energía Finance Co., LLC, an affiliate of the company's Peruvian and Chilean entities, the company has provided guarantees aggregating $100 million at December 31, 2005, to unrelated parties.

Credit Ratings

Credit ratings of the company and its principal subsidiaries remained unchanged at investment grade levels in 2005. As of January 31, 2006, credit ratings for Sempra Energy and its principal subsidiaries were still as follows:

	Standard & Poor's	Moody's Investor Services, Inc.	Fitch
SEMPRA ENERGY
Unsecured debt	BBB+	Baa1	A
SDG&E
Secured debt	A+	A1	AA
Unsecured debt	A-	A2	AA-
Preferred stock	BBB+	Baa1	A+
Commercial paper	A-1	P-1	F1+
SOCALGAS
Secured debt	A+	A1	AA
Unsecured debt	A-	A2	AA-
Preferred stock	BBB+	Baa1	A+
Commercial paper	A-1	P-1	F1+
PACIFIC ENTERPRISES
Preferred stock	BBB+	--	A
SEMPRA GLOBAL
Unsecured debt guaranteed by Sempra Energy	--	Baa1	--
Commercial paper guaranteed by Sempra Energy	A-2	P-2	F1

As of January 31, 2006, the company has a stable outlook rating from all three credit rating agencies.

FACTORS INFLUENCING FUTURE PERFORMANCE

The California Utilities' operations and Sempra Generation's long-term contracts generally provide relatively stable earnings and liquidity, while Sempra Pipelines & Storage and Sempra LNG provide opportunities for earnings growth and Sempra Commodities experiences significant volatility in earnings and liquidity requirements. Performance will also depend on the successful completion of construction programs, which are discussed in various places in this report. Notes 13 through 15 of the notes to Consolidated Financial Statements describe matters that could affect future performance.

Litigation

Note 15 of the notes to Consolidated Financial Statements describes litigation (primarily cases arising from the California energy crisis and Sempra Generation's contract with the DWR), the ultimate resolution of which could have a material adverse effect on future performance.

California Utilities

Notes 13 and 14 of the notes to Consolidated Financial Statements describe electric and natural gas restructuring and rates, and other pending proceedings and investigations.

Sempra Global

Electric-Generation Assets

As discussed in "Capital Resources and Liquidity" above, and in Notes 2 and 3 of the notes to Consolidated Financial Statements, the company is involved in the disposal and/or refinancing of a portion of its electric-generation capabilities, which will affect the company's future performance.

Investments

As discussed in "Cash Flows From Investing Activities," the company's investments will significantly impact the company's future performance.

Sempra LNG is in the process of constructing the Energía Costa Azul LNG receiving terminal in Baja California, Mexico and the Cameron LNG receiving terminal in Louisiana, and developing the Port Arthur LNG receiving terminal in Texas. Additional information regarding these activities is provided above under "Capital Resources and Liquidity" and in Note 2 of the notes to Consolidated Financial Statements.

In December 2005, Sempra Pipelines & Storage entered into definitive agreements with KMP to jointly pursue through Rockies Express development of a proposed natural gas pipeline, the Rockies Express Pipeline, which would link producing areas in the Rocky Mountain region to the upper Midwest and the Eastern United States and which will have capacity of up to 2 bcf per day. Additional information regarding Rockies Express is provided above under "Capital Resources and Liquidity."

In December 2005, Sempra Generation announced plans to sell or refinance its Texas-based power plants due to the increased market valuation of coal-fired power plants in Texas, including Twin Oaks and Coleto Creek. In January 2006, Sempra Generation announced an agreement for the sale of Twin Oaks. Additional information regarding these activities is provided above under "Capital Resources and Liquidity" and in Notes 2 and 3 of the notes to Consolidated Financial Statements.

In July 2004, the company announced that it had acquired the rights to develop Liberty, located in Calcasieu Parish, Louisiana. In May 2005, ProLiance Transportation and Storage, LLC acquired a 25-percent ownership in Liberty from the company. In September 2005, Sempra Commodities completed the $253 million sale of two natural gas storage facilities. Additional information regarding these activities is provided above under "Capital Resources and Liquidity" and in Note 2 of the notes to Consolidated Financial Statements.

The Argentine economic decline and government responses (including Argentina's unilateral, retroactive abrogation of utility agreements early in 2002) are continuing to adversely affect the company's investment in two Argentine utilities. Information regarding this situation is provided in Notes 3 and 15 of the notes to Consolidated Financial Statements.

Market Risk

Market risk is the risk of erosion of the company's cash flows, net income, asset values and equity due to adverse changes in prices for various commodities, and in interest and foreign-currency rates.

The company has adopted policies governing its market risk management and trading activities of all affiliates. Assisted by the company's Energy Risk Management Group (ERMG) and the California Utilities' Risk Management Department (CURMD), the company's Energy Risk Management Oversight Committee (ERMOC) and each of the California Utilities' Risk Management Committees, consisting of senior officers, establish policy for and oversee company-wide energy risk management activities and monitor the results of trading and other activities to ensure compliance with the company's stated energy risk management and trading policies. The ERMG and the CURMD receive daily information detailing positions regarding market positions that create credit, liquidity and market risk from the California Utilities and from all non-CPUC-regulated affiliates, respectively. Independently from the company's energy procurement department, the ERMG and the CURMD monitor energy price risk management and measure and report the market and credit risk associated with these positions.

Along with other tools, the company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence intervals. VaR is calculated independently by the ERMG for all non-CPUC-regulated affiliates and by the CURMD for the California Utilities. Historical and implied volatilities and correlations between instruments and positions are used in the calculation. The California Utilities use energy and natural gas derivatives to manage natural gas and energy price risk associated with servicing load requirements. The use of energy and natural gas derivatives is in compliance with risk management and trading activity plans that have been filed and approved by the CPUC. Any costs or gains/losses associated with the use of energy and natural gas derivatives, which use is in compliance with CPUC approved plans, are considered to be commodity costs that are passed on to customers on a substantially concurrent basis.

Following is a summary of Sempra Commodities' trading VaR profile (using a one-day holding period, at two confidence levels) in millions of dollars:

	95%			99%
December 31, 2005	$	16.5		$	23.3
2005 range	$	5.7	to $ 27.5	$	7.9	to $ 38.3
December 31, 2004	$	8.0		$	11.3
2004 range	$	2.8	to $ 18.7	$	3.9	to $ 26.1

The 2005 increase in VaR is primarily due to increased volumes and price of Sempra Commodities' transactions.

The company uses energy and natural gas derivatives to manage natural gas and energy price risk associated with servicing their utility load requirements. The use of derivative financial instruments is subject to certain limitations imposed by company policy and regulatory requirements.

Revenue recognition is discussed in Notes 1 and 10 and the additional market risk information regarding derivative instruments is discussed in Note 10 of the notes to Consolidated Financial Statements.

The following discussion of the company's primary market risk exposures as of December 31, 2005 includes a discussion of how these exposures are managed.

Commodity Price Risk

Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these commodities or related financial instruments are traded. The company's various subsidiaries are exposed, in varying degrees, to price risk, primarily in the petroleum, metals, natural gas and electricity markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments of each subsidiary.

Sempra Commodities

Sempra Commodities derives most of its revenue from its worldwide trading activities in natural gas, electricity, petroleum products, metals and other commodities. As a result, Sempra Commodities is exposed to price volatility in the related domestic and international markets. Sempra Commodities conducts these activities within a structured and disciplined risk management and control framework that is based on clearly communicated policies and procedures, position limits, active and ongoing management monitoring and oversight, clearly defined roles and responsibilities, and daily risk measurement and reporting.

California Utilities

The California Utilities' market risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchase, sale, intrastate transportation and storage activity. However, the California Utilities may, at times, be exposed to market risk as a result of SDG&E's natural gas PBR and electric procurement activities or SoCalGas' GCIM, which are discussed in Note 14 of the notes to Consolidated Financial Statements. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This would increase the per-unit fixed costs, which could lead to further volume declines. The California Utilities manage their risk within the parameters of their market risk management framework. As of December 31, 2005, the total VaR of the California Utilities' natural gas and electric positions was not material and the procurement activities are in compliance with the procurement plans filed with and approved by the CPUC.

Interest Rate Risk

The company is exposed to fluctuations in interest rates primarily as a result of its short-term and long-term debt. The company historically has funded utility operations through long-term debt issues at fixed rates of interest recovered in utility rates. Some more-recent debt offerings have been issued with floating rates. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures.

At December 31, 2005, the California Utilities had $2.4 billion of fixed-rate debt and $0.3 billion of variable-rate debt. Interest on fixed-rate utility debt is fully recovered in rates on a historical cost basis and interest on variable-rate debt is provided for in rates on a forecasted basis. At December 31, 2005, utility fixed-rate debt had a one-year VaR of $276 million and utility variable-rate debt had a one-year VaR of $7 million. Non-utility debt (fixed-rate and variable-rate) subject to VaR modeling totaled $2.3 billion at December 31, 2005, with a one-year VaR of $82 million.

At December 31, 2005, the notional amount of interest-rate swap transactions totaled $1.2 billion. Note 5 of the notes to Consolidated Financial Statements provides further information regarding interest-rate swap transactions.

In addition, the company is subject to the effect of interest-rate fluctuations on the assets of its pension plans, other postretirement plans and the nuclear decommissioning trust. However the effects of these fluctuations, as they relate to the California Utilities, are expected to be passed on to customers.

Credit Risk

Credit risk is the risk of loss that would be incurred as a result of nonperformance by counterparties of their contractual obligations. As with market risk, the company has adopted policies governing the management of credit risk. Credit risk management is performed by the ERMG and the California Utilities' credit department and overseen by the ERMOC and the California Utilities' respective RMC. Using rigorous models, the ERMG, CURMD and the company calculate current and potential credit risk to counterparties on a daily basis and monitor actual balances in comparison to approved limits. The company avoids concentration of counterparties whenever possible, and management believes its credit policies associated with counterparties significantly reduce overall credit risk. These policies include an evaluation of prospective counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances, the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty, and other security such as lock-box liens and downgrade triggers. At December 31, 2005, Sempra Commodities' 20 largest customers had balances totaling $910 million, of which $863 million corresponds to investment-grade customers, with individual customers varying from $28 million to $117 million. The company believes that adequate reserves have been provided for counterparty nonperformance.

As described in Note 15 of the notes to Consolidated Financial Statements, Sempra Generation has a contract with the DWR to supply up to 1,900 MW of power to the state of California over 10 years, beginning in 2001. This contract results in a significant potential nonperformance exposure with a single counterparty; however, this risk has been addressed and mitigated by the liquidated damages provision of the contract.

The developing LNG projects will result in significant reliance on the credit-worthiness of its major suppliers and customers of the projects.

The company monitors credit risk through a credit approval process and the assignment and monitoring of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry.

As noted above under "Interest Rate Risk," the company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should counterparties to the agreement not perform.

Foreign Currency Rate Risk

The company has investments in entities whose functional currency is not the U.S. dollar, exposing the company to foreign exchange movements, primarily in Latin American currencies. As a result of the devaluation of the Argentine peso that began at the end of 2001, Sempra Pipelines & Storage has reduced the carrying value of its Argentine investments downward by a cumulative total of $201 million as of December 31, 2005. These non-cash adjustments continue to occur based on fluctuations in the Argentine peso and have not affected net income, but have affected other comprehensive income (loss) and accumulated other comprehensive income (loss). Further discussion is provided in Note 3 of the notes to Consolidated Financial Statements.

The company's primary objective with respect to currency risk is to preserve the economic value of its overseas investments and to reduce net income volatility that would otherwise occur due to exchange-rate fluctuations.

Sempra Energy's net investment in its Latin American operating companies and the resulting cash flows are partially protected against normal exchange-rate fluctuations by rate-setting mechanisms that are intended to compensate for local inflation and currency exchange-rate fluctuations. In addition, the company offsets material cross-currency transactions and net income exposure through various means, including financial instruments and short-term investments.

Because the company does not hedge its net investment in foreign countries, it is susceptible to volatility in other comprehensive income caused by exchange rate fluctuations. The primary effect on other comprehensive income due to exchange rate variations has been the devaluation of the Argentine peso against the U.S. dollar, as discussed in Note 3 of the notes to Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND KEY NON-CASH PERFORMANCE INDICATORS

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. The most critical policies, all of which are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission, are the following:

Statement of Financial Accounting Standards (SFAS) 5, "Accounting for Contingencies," establishes the amounts and timing of when the company provides for contingent losses. Details of the company's issues in this area are discussed in Note 15 of the notes to Consolidated Financial Statements.

SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant effect on the way the California Utilities record assets and liabilities, and the related revenues and expenses that would not be recorded absent the principles contained in SFAS 71.

SFAS 109, "Accounting for Income Taxes," governs the way the company provides for income taxes. Details of the company's issues in this area are discussed in Note 7 of the notes to Consolidated Financial Statements.

SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," and EITF Issue 02-3, "Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," have a significant effect on the balance sheets of Sempra Commodities and the California Utilities but have no significant effect on the California Utilities' income statements because of the principles contained in SFAS 71. The effect on Sempra Commodities' income statement is discussed in Note 10 of the notes to Consolidated Financial Statements.

In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve:

The calculation of fair or realizable values, including the investments in Argentina under the Bilateral Investment Treaty, and the fair values of long-lived assets. For example, in determining whether major facilities that are not currently profitable have carrying values that are in excess of their fair values and the extent of any excess, critical assumptions include the costs of natural gas, competing fuels (primarily propane) and electricity.

The probable costs to be incurred in the resolution of litigation.

The collectibility of receivables, regulatory assets, deferred tax assets and other assets.

The resolution of various income tax issues between the company and the various taxing authorities.

The costs to be incurred in fulfilling certain contracts that have been marked to market.

The various assumptions used in actuarial calculations for pension plans, other than as related to the California Utilities, where rate-making effects negate any effects of the assumptions on net income. For the remaining plans, the approximate annual effect on net income of a 1% change in the assumed discount rate or the assumed rate of return on plan assets would be $2.5 million or $1 million, respectively. Additional discussion of pension plan assumptions is included in Note 8 of the notes to Consolidated Financial Statements.

Differences between estimates and actual amounts have had significant impacts in the past and are likely to have significant impacts in the future.

As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values whenever possible. When no such data is available, it uses internally developed models and other techniques. The assumed collectibility of receivables considers the aging of the receivables, the credit-worthiness of customers and the enforceability of contracts, where applicable. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the credit-worthiness of the other parties and other factors. The anticipated resolution of income tax issues considers past resolutions of the same or similar issue, the status of any income tax examination in progress and positions taken by taxing authorities with other taxpayers with similar issues. Costs to fulfill contracts that are carried at fair value are based on prior experience. Actuarial assumptions are based on the advice of the company's independent actuaries. The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and the company's expectation of future financial and/or taxable income, based on its strategic planning.

Choices among alternative accounting policies that are material to the company's financial statements and information concerning significant estimates have been discussed with the audit committee of the board of directors.

Key non-cash performance indicators for the company's subsidiaries include numbers of customers and quantities of natural gas and electricity sold for the California Utilities, and plant availability factors at Sempra Generation's generating plants. For competitive reasons, Sempra Generation does not disclose its plant availability factors. The California Utilities information is provided in "Overview" and "Results of Operations." Sempra Commodities does not use non-cash performance factors. Its key indicators are profit margins by product line and by geographic area. "Business Unit Results - Sempra Commodities" provides the information for Sempra Commodities. Other than its two small natural gas utilities in the eastern United States, Sempra Pipelines & Storage's only consolidated operations are in Mexico. The natural gas distribution utility that operates in three separate areas has increased the customer count to almost 100,000 and the sales volume to almost 55 million cubic feet per day in 2005. The pipeline system had contracted capacity of 450 million cubic feet per day in 2005 and 2004.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have had a significant effect on the company's financial statements are SFAS 123R and 143, and FIN 47. They are described below.

SFAS 123R, "Share-Based Payment": In December 2004, the FASB issued SFAS 123 (revised), a revision of SFAS 123, Accounting for Stock-Based Compensation. This statement requires companies to measure and record the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The effective date of this statement is January 1, 2006 for the company.

SFAS 143, "Accounting for Asset Retirement Obligations" and FIN 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143": SFAS 143 requires entities to record the fair value of liabilities for legal obligations related to asset retirements in the period in which they are incurred. It also requires most energy utilities, including the California Utilities, to reclassify amounts recovered in rates for future removal costs not covered by a legal obligation from accumulated depreciation to a regulatory liability. Issued in March 2005, FIN 47 clarifies that the term conditional asset-retirement obligation as used in SFAS 143 refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 is effective for the company's 2005 annual report.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Annual 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, national and international 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, and the Federal Energy Regulatory Commission and other regulatory bodies in the United States and other countries; 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; 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.

FIVE YEAR SUMMARY

(In millions, except per share amounts)				At December 31 or for the years then ended
				2005		2004			2003			2002		2001
Operating revenues
California utilities:
	Natural gas		$	5,253	$	4,537		$	4,005		$	3,255	$	4,365
	Electric			1,789		1,658			1,786			1,282		1,673
Sempra Global and parent				4,695		3,239			2,100			1,520		1,695
	Total operating revenues		$	11,737	$	9,434		$	7,891		$	6,057	$	7,733
Operating income			$	1,111	$	1,281		$	943		$	973	$	1,014
Income from continuing operations before
	extraordinary item and cumulative effect
	of changes in accounting principles		$	929	$	920		$	695		$	575	$	518
Net income			$	920	$	895		$	649		$	591	$	518
Income per common share from continuing
	operations before extraordinary item
	and cumulative effect of changes in
	accounting principles:
		Basic	$	3.78	$	4.03		$	3.29		$	2.80	$	2.54
		Diluted	$	3.69	$	3.93		$	3.24		$	2.79	$	2.52
Net income per common share:
		Basic	$	3.74	$	3.92		$	3.07		$	2.88	$	2.54
		Diluted	$	3.65	$	3.83		$	3.03		$	2.87	$	2.52
Dividends declared per common share			$	1.16	$	1.00		$	1.00		$	1.00	$	1.00
Return on common equity				16.7%		20.5%			19.3%			21.4%		19.5%
Effective income tax rate				5%		18%			7%			20%		32%
Price range of common shares			$	47.86-	$	37.93-		$	30.90-		$	26.25-	$	28.61-
				35.53		29.51			22.25			15.50		17.31
Weighted average rate base:
	SoCalGas		$	2,386	$	2,351		$	2,268		$	2,222	$	2,262
	SDG&E		$	2,902	$	2,755		$	2,619		$	2,452	$	2,334
AT DECEMBER 31
Current assets			$	13,318	$	8,776		$	7,866		$	7,010	$	4,692
Total assets			$	29,213	$	23,775		$	21,988		$	20,242	$	17,378
Current liabilities			$	12,157	$	9,082		$	8,569		$	7,554	$	5,629
Long-term debt (excludes current portion)			$	4,823	$	4,192		$	3,841		$	4,083	$	3,436
Trust preferred securities			$	--	$	200	*	$	200	*	$	200	$	200
Shareholders' equity			$	6,160	$	4,865		$	3,890		$	2,825	$	2,692
Common shares outstanding				257.2		234.2			226.6			204.9		204.5
Book value per share			$	23.95	$	20.77		$	17.17		$	13.79	$	13.16
* Amount was reclassified to Due to Unconsolidated Affiliates effective in 2003. The company redeemed the securities in February 2005.

Certain prior-year amounts have been reclassified to conform to the current year's presentation.

Note 1 of the notes to Consolidated Financial Statements discusses the 2003 changes in accounting principles. Note 4 discusses a discontinued operation. Note 15 discusses litigation and other contingencies.

An extraordinary gain of $16 million was recorded in 2002 related to Sempra Commodities' acquisition of two businesses for amounts less than the fair value of the businesses' net assets.

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

Management is responsible for the preparation of the company's consolidated financial statements and related information appearing in this report. Management believes that the consolidated financial statements fairly present the form and substance of transactions and that the financial statements reasonably present the company's financial position and results of operations in conformity with accounting principles generally accepted in the United States of America. Management also has included in the company's financial statements amounts that are based on estimates and judgments, which it believes are reasonable under the circumstances.

Deloitte & Touche LLP, an independent registered public accounting firm, audits the company's consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent review of the fairness of reported operating results and financial position.

The board of directors of the company has an Audit Committee composed of five non-management directors. The committee meets periodically with financial management, the internal auditors and Deloitte & Touche LLP to review accounting, control, auditing and financial reporting matters.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of company management, including the principal executive officer and principal financial officer, the company conducted an evaluation of 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. Based on the company's evaluation under the framework in Internal Control -- Integrated Framework, management concluded that the company's internal control over financial reporting was effective as of December 31, 2005. Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, as stated in its report, which is included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Sempra Energy:

We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Sempra Energy and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated February 21, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of three new accounting standards.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 21, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Sempra Energy:

We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sempra Energy and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As described in Note 1 to the financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, effective December 31, 2005, Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities -- an Interpretation of ARB No. 51, effective December 31, 2003, and the rescission of EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, effective January 1, 2003.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 21, 2006

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)

					Years ended December 31,
					2005			2004			2003
OPERATING REVENUES
California utilities					$	7,042		$	6,195		$	5,791
Sempra Global and parent						4,695			3,239			2,100
				Total operating revenues		11,737			9,434			7,891
OPERATING EXPENSES
California utilities:
		Cost of natural gas				3,232			2,593			2,071
		Cost of electric fuel and purchased power				624			576			541
Other cost of sales						2,715			1,741			1,204
Litigation expense						551			150			72
Other operating expenses						2,634			2,243			2,108
Depreciation and amortization						646			621			615
Franchise fees and other taxes						251			236			230
Gains on sale of assets, net						(112	)		(15	)		(15	)
Impairment losses						85			8			122
				Total operating expenses		10,626			8,153			6,948
Operating income						1,111			1,281			943
Other income, net (Note 1)						51			33			(40	)
Interest income						75			69			104
Interest expense						(311	)		(322	)		(308	)
Preferred dividends of subsidiaries						(10	)		(10	)		(10	)
Trust preferred distributions of subsidiary						--			--			(9	)
Income from continuing operations before income taxes and
			equity in earnings of certain unconsolidated subsidiaries			916			1,051			680
Income tax expense						42			193			47
Equity in income of certain unconsolidated subsidiaries
			(Note 3)			55			62			62
Income from continuing operations						929			920			695
Discontinued operations, net of tax (Note 4)						(9	)		(25	)		--
Income before cumulative effect of changes in accounting
	principles					920			895			695
Cumulative effect of changes in accounting principles, net of tax
	(Note 1)					--			--			(46	)
Net income					$	920		$	895		$	649
Basic earnings per share:
	Income from continuing operations				$	3.78		$	4.03		$	3.29
	Discontinued operations, net of tax					(0.04	)		(0.11	)		--
	Cumulative effect of changes in accounting principles, net of tax					--			--			(0.22	)
	Net income				$	3.74		$	3.92		$	3.07
	Weighted-average number of shares outstanding (thousands)					245,906			228,271			211,740
Diluted earnings per share:
	Income from continuing operations				$	3.69		$	3.93		$	3.24
	Discontinued operations, net of tax					(0.04	)		(0.10	)		--
	Cumulative effect of changes in accounting principles, net of tax					--			--			(0.21	)
	Net income				$	3.65		$	3.83		$	3.03
	Weighted-average number of shares outstanding (thousands)					252,088			233,852			214,482
Dividends declared per share of common stock					$	1.16		$	1.00		$	1.00

See notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS

			December 31, 2005			December 31, 2004
(Dollars in millions)
ASSETS
Current assets:
	Cash and cash equivalents		$	772		$	419
	Short-term investments			12			15
	Trade accounts receivable, net			998			950
	Other accounts and notes receivable, net			194			82
	Due from unconsolidated affiliates			3			4
	Deferred income taxes			132			15
	Interest receivable			29			80
	Trading-related receivables and deposits, net			3,370			2,606
	Derivative trading instruments			4,502			2,339
	Commodities owned			2,498			1,547
	Regulatory assets			255			255
	Inventories			212			172
	Other			291			222
	Current assets of continuing operations			13,268			8,706
	Current assets of discontinued operations			50			70
		Total current assets		13,318			8,776
Investments and other assets:
	Due from unconsolidated affiliates			21			42
	Regulatory assets arising from fixed-price contracts and other derivatives			398			500
	Other regulatory assets			713			751
	Nuclear decommissioning trusts			638			612
	Investments			1,104			1,164
	Sundry			920			844
		Total investments and other assets		3,794			3,913
Property, plant and equipment:
	Property, plant and equipment			17,564			16,203
	Less accumulated depreciation and amortization			(5,463	)		(5,117	)
		Property, plant and equipment, net		12,101			11,086
Total assets			$	29,213		$	23,775

See notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS

				December 31, 2005			December 31, 2004
(Dollars in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Short-term debt			$	1,062		$	405
	Accounts payable - trade				1,272			1,020
	Accounts payable - other				140			106
	Income taxes payable				68			187
	Trading-related payables				4,127			3,182
	Derivative trading instruments				3,246			1,484
	Commodities sold with agreement to repurchase				634			513
	Dividends and interest payable				140			123
	Regulatory balancing accounts, net				192			509
	Fixed-price contracts and other derivatives				130			157
	Current portion of long-term debt				101			398
	Due to unconsolidated affiliates				--			205
	Other				1,035			776
	Current liabilities of continuing operations				12,147			9,065
	Current liabilities of discontinued operations				10			17
			Total current liabilities		12,157			9,082
Long-term debt					4,823			4,192
Deferred credits and other liabilities:
	Due to unconsolidated affiliate				162			162
	Customer advances for construction				110			97
	Postretirement benefits other than pensions				121			129
	Deferred income taxes				245			420
	Deferred investment tax credits				73			78
	Regulatory liabilities arising from removal obligations				2,313			2,692
	Asset retirement obligations				958			326
	Other regulatory liabilities				200			199
	Fixed-price contracts and other derivatives				400			500
	Deferred credits and other				1,312			854
			Total deferred credits and other liabilities		5,894			5,457
Preferred stock of subsidiaries					179			179
Commitments and contingencies (Note 15)
SHAREHOLDERS' EQUITY
Preferred stock (50 million shares authorized; none issued)					--			--
Common stock (750 million shares authorized;					2,958			2,301
		257 million and 234 million shares outstanding at
		December 31, 2005 and 2004, respectively)
Retained earnings					3,588			2,961
Deferred compensation relating to ESOP					(28	)		(32	)
Accumulated other comprehensive income (loss)					(358	)		(365	)
Total shareholders' equity					6,160			4,865
Total liabilities and shareholders' equity				$	29,213		$	23,775

See notes to Consolidated Financial Statements.

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

			Years ended December 31,
			2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income		$	920		$	895		$	649
	Adjustments to reconcile net income to net cash provided by operating activities
		Loss from discontinued operations, net of tax		9			25			--
		Depreciation and amortization		646			621			615
		Gains on sale of assets, net		(112	)		(15	)		(15	)
		Impairment losses		85			8			122
		Deferred income taxes and investment tax credits		(283	)		13			(118	)
		Non-cash rate reduction bond expense		68			75			68
		Equity in income of unconsolidated affiliates		(66	)		(36	)		(5	)
		Cumulative effect of changes in accounting principles, net of tax		--			--			46
		Other		(50	)		(6	)		27
	Net changes in other working capital components			(1,169	)		(395	)		(158	)
	Changes in other assets			27			(127	)		(18	)
	Changes in other liabilities			451			(27	)		(28	)
		Net cash provided by continuing operations		526			1,031			1,185
		Net cash used in discontinued operations		(5	)		(30	)		--
		Net cash provided by operating activities		521			1,001			1,185
CASH FLOWS FROM INVESTING ACTIVITIES
	Expenditures for property, plant and equipment			(1,404	)		(1,083	)		(1,049	)
	Proceeds from sale of assets			277			377			29
	Proceeds from disposal of discontinued operations			5			157			--
	Investments in and acquisitions of subsidiaries, net of cash acquired			(86	)		(74	)		(202	)
	Purchases of nuclear decommissioning and other trust assets			(299	)		(319	)		(330	)
	Proceeds from sales by nuclear decommissioning and other trusts			262			262			283
	Dividends received from unconsolidated affiliates			72			59			72
	Increase in loans to affiliates, net			--			--			(99	)
	Other			(12	)		10			4
		Net cash used in investing activities		(1,185	)		(611	)		(1,292	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Common dividends paid			(268	)		(195	)		(182	)
	Issuances of common stock			694			110			505
	Repurchases of common stock			(95	)		(5	)		(7	)
	Issuances of long-term debt			762			997			900
	Payments on long-term debt			(532	)		(1,670	)		(601	)
	Redemption of mandatorily redeemable preferred securities			(200	)		--			--
	Increase (decrease) in short-term debt, net			662			397			(518	)
	Other			(6	)		(14	)		(8	)
		Net cash provided by (used in) financing activities		1,017			(380	)		89
Increase (decrease) in cash and cash equivalents				353			10			(18	)
Cash and cash equivalents, January 1				419			409			427
Cash and cash equivalents, December 31			$	772		$	419		$	409

See notes to Consolidated Financial Statements.

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

		Years ended December 31,
		2005			2004			2003
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, and debt due within one year)
Accounts and notes receivable		$	(92	)	$	(303	)	$	(191	)
Net trading assets			(1,062	)		(454	)		59
Income taxes, net			(86	)		(64	)		72
Inventories			(40	)		(26	)		(12	)
Regulatory balancing accounts			(321	)		79			(155	)
Regulatory assets and liabilities			(4	)		(23	)		(30	)
Other current assets			(38	)		(31	)		(9	)
Accounts payable			283			300			75
Other current liabilities			191			127			33
	Net changes in other working capital components	$	(1,169	)	$	(395	)	$	(158	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Interest payments, net of amounts capitalized		$	295		$	318		$	296
Income tax payments, net of refunds		$	429		$	254		$	118

See notes to Consolidated Financial Statements.

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2005, 2004 and 2003

(Dollars in millions)		Comprehensive Income		Common Stock		Retained Earnings		Deferred Compensation Relating to ESOP		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2002				$ 1,436		$ 1,861		$ (33	)	$ (439	)	$ 2,825
Net income		$ 649				649						649
Comprehensive income adjustments:
	Foreign currency translation gains (Note 1)	57								57		57
	Pension	(16	)							(16	)	(16	)
	SFAS 133	(3	)							(3	)	(3	)
Comprehensive income		$ 687
Common stock dividends declared						(212	)					(212	)
Equity units adjustment				6								6
Quasi-reorganization adjustment (Note 1)				19								19
Issuance of common stock				553								553
Tax benefit related to employee stock options				13								13
Repurchase of common stock				(6	)							(6	)
Common stock released from ESOP				7				(2	)			5
Balance at December 31, 2003				2,028		2,298		(35	)	(401	)	3,890
Net income		$ 895				895						895
Comprehensive income adjustments:
	Foreign currency translation gains (Note 1)	40								40		40
	Pension	28								28		28
	Available-for-sale securities	4								4		4
	SFAS 133	(36	)							(36	)	(36	)
Comprehensive income		$ 931
Common stock dividends declared						(232	)					(232	)
Quasi-reorganization adjustment (Note 1)				86								86
Issuance of common stock				172								172
Tax benefit related to employee stock options				16								16
Repurchase of common stock				(5	)							(5	)
Common stock released from ESOP				4				3				7
Balance at December 31, 2004				2,301		2,961		(32	)	(365	)	4,865
Net income		$ 920				920						920
Comprehensive income adjustments:
	Foreign currency translation gains (Note 1)	30								30		30
	Available-for-sale securities	(4	)							(4	)	(4	)
	SFAS 133	(19	)							(19	)	(19	)
Comprehensive income		$ 927
Common stock dividends declared						(293	)					(293	)
Issuance of common stock				720								720
Tax benefit related to employee stock options				26								26
Repurchase of common stock				(95	)							(95	)
Common stock released from ESOP				6				4				10
Balance at December 31, 2005				$ 2,958		$ 3,588		$ (28	)	$ (358	)	$ 6,160

See notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Sempra Energy (the company); its majority-owned subsidiaries and in 2004 the variable-interest entities of which the company was the primary beneficiary. Investments in affiliated companies over which Sempra Energy has the ability to exercise significant influence, but not control, are accounted for using the equity method. Further discussion of investments in unconsolidated subsidiaries is provided in Note 3. All material intercompany accounts and transactions have been eliminated.

In connection with charges related to litigation, the significant instances of which are discussed in Note 15, Sempra Energy management determines the allocation of the charges among its business units based on the extent of their involvement with the subject of the litigation.

Quasi-Reorganization

In 1993, Pacific Enterprises (PE) effected a quasi-reorganization for financial reporting purposes as of December 31, 1992. Certain of the liabilities established in connection with the quasi-reorganization were favorably resolved in 2003 and 2004, resulting in adjustments to common equity in these years. The remaining liabilities will be resolved in future years and management believes the provisions established for these matters are adequate.

Use of Estimates in the Preparation of the Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period, and the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Although management believes the estimates and assumptions are reasonable, actual amounts can differ significantly from those estimates.

Basis of Presentation

Certain prior-year amounts have been reclassified to conform to the current year's presentation.

Regulatory Matters

Effects of Regulation

The accounting policies of the company's principal utility subsidiaries, San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) (collectively, the California Utilities), conform with GAAP for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).

The California Utilities prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation, under which a regulated utility records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. To the extent that recovery is no longer probable as a result of changes in regulation or the utility's competitive position, the related regulatory assets would be written off. In addition, SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that a loss be recognized whenever a regulator excludes all or part of utility plant or regulatory assets from ratebase. Regulatory liabilities represent reductions in future rates for amounts due to customers. Information concerning regulatory assets and liabilities is provided below in "Revenues," "Regulatory Balancing Accounts" and "Regulatory Assets and Liabilities."

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31, 2005, represent net payables (payables net of receivables) of $13 million and $179 million for SoCalGas and SDG&E, respectively. The corresponding amounts at December 31, 2004 were net payables of $178 million and $331 million, respectively.

Except for certain costs subject to balancing account treatment, fluctuations in most operating and maintenance accounts affect utility earnings. Balancing accounts provide a mechanism for charging utility customers the amount actually incurred for certain costs, primarily commodity costs. The CPUC has also approved balancing account treatment for variances between forecast and actual for SoCalGas' and SDG&E's volumes and commodity costs, eliminating the impact on earnings from any throughput and revenue variances from adopted forecast levels. Additional information on regulatory matters is included in Notes 13 and 14.

Regulatory Assets and Liabilities

In accordance with the accounting principles of SFAS 71, the company records regulatory assets and regulatory liabilities as discussed above.

Regulatory assets (liabilities) as of December 31 relate to the following matters:

(Dollars in millions)		2005			2004
SDG&E
Fixed-price contracts and other derivatives		$	473		$	500
Recapture of temporary rate reduction*		116			183
Deferred taxes recoverable in rates		294			278
Unamortized loss on retirement of debt, net		42			46
Employee benefit costs		174			160
Removal obligations**		(1,216		)	(1,246		)
Other		36			29
	Total	(81		)	(50		)
SoCalGas
Fixed-price contracts and other derivatives		49			148
Environmental remediation		39			42
Unamortized loss on retirement of debt, net		40			44
Removal obligations**		(1,097		)	(1,446		)
Deferred taxes refundable in rates		(200		)	(199		)
Employee benefit costs		97			65
Other		3			7
	Total	(1,069		)	(1,339		)
Total		$	(1,150	)	$	(1,389	)

* In connection with electric industry restructuring, which is described in Note 13, SDG&E temporarily reduced rates to its small-usage customers. That reduction is being recovered in rates through 2007.
** This is related to SFAS 143, Accounting for Asset Retirement Obligations, which is discussed below in "New Accounting Standards."

Net regulatory assets (liabilities) are recorded on the Consolidated Balance Sheets at December 31 as follows:

(Dollars in millions)		2005			2004
Current regulatory assets		$	255		$	255
Noncurrent regulatory assets		1,111			1,251
Current regulatory liabilities*		(3		)	(4		)
Noncurrent regulatory liabilities		(2,513		)	(2,891		)
	Total	$	(1,150	)	$	(1,389	)

* Included in Other Current Liabilities.

All of these assets either earn a return, generally at short-term rates, or the cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost.

Cash and Cash Equivalents

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

Non-cash Investing and Financing Activities

Property, Plant and Equipment increased by $45 million in 2005 as a result of changes in unpaid construction costs. (Comparable changes in 2004 and 2003 were not material.) Also in 2005, the company acquired subsidiary assets of $126 million and assumed related liabilities of $55 million, for a net cash payment of $71 million. In 2003 the company consolidated variable interest entities (as discussed further under "New Accounting Standards" below) with assets of $820 million and liabilities of $881 million.

Restricted cash

Restricted cash was $12 million and $15 million at December 31, 2005 and 2004, respectively. The amounts are included in current assets under the caption Short-term Investments and primarily serve as cash collateral for certain debt agreements.

Collection Allowances

The allowance for doubtful accounts was $12 million, $8 million and $19 million at December 31, 2005, 2004 and 2003, respectively. The company recorded provisions for doubtful accounts of $13 million, $12 million and $5 million in 2005, 2004 and 2003, respectively.

The allowance for realization of trading assets was $64 million, $56 million and $67 million at December 31, 2005, 2004 and 2003, respectively. The company recorded provisions (reduction thereof) for trading assets of $30 million, $3 million and $(4) million in 2005, 2004 and 2003, respectively.

Trading Instruments

Trading assets and trading liabilities (described further in Note 10) include option premiums paid and received, unrealized gains and losses from exchange-traded futures and options, over-the-counter (OTC) swaps, forwards, physical commodities and options. Trading instruments are recorded by Sempra Commodities on a trade-date basis and the majority of such derivative instruments are adjusted daily to current market value. Unrealized gains and losses on OTC transactions reflect amounts which would be received from or paid to a third party upon net settlement of the contracts. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists under an enforceable netting arrangement.

Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and carried at current market value based on current closing exchange quotations. Derivative commodity swaps and forward transactions are accounted for as contractual commitments on a trade-date basis and carried at fair value derived from current dealer quotations and underlying commodity-exchange quotations. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates. For long-dated forward transactions, current market values are derived using internally developed valuation methodologies based on available market information. When there is an absence of observable market data at inception, the value of the transaction is its cost. Where market rates are not quoted, current interest, commodity and volatility rates are estimated by reference to current market levels. Given the nature, size and timing of transactions, estimated values may differ significantly from realized values. Changes in market values are reflected in net income. Although trading instruments may have scheduled maturities in excess of one year, the actual settlement of these transactions can occur sooner, resulting in the current classification of trading assets and liabilities on the Consolidated Balance Sheets.

Energy transportation and storage contracts are recorded at cost, and energy commodity inventory is recorded at the lower of cost or market. However, metals inventories continue to be recorded at fair value in accordance with Accounting Research Bulletin (ARB) No. 43, Restatement and Revision of Accounting Research Bulletins.

Inventories

At December 31, 2005, inventory shown on the Consolidated Balance Sheets, which does not include Commodities Owned (which is shown as a separate caption on the balance sheets), included natural gas of $140 million, and materials and supplies of $72 million. The corresponding balances at December 31, 2004 were $115 million and $57 million, respectively. Natural gas at the California Utilities ($140 million and $111 million at December 31, 2005 and 2004, respectively) is valued by the last-in first-out (LIFO) method. When the California Utilities' inventory is consumed, differences between the LIFO valuation and replacement cost are reflected in customer rates. Materials and supplies at the California Utilities are generally valued at the lower of average cost or market.

Income Taxes

Income tax expense includes current and deferred income taxes from operations during the year. In accordance with SFAS 109, Accounting for Income Taxes, the company records deferred income taxes for temporary differences between the book and tax bases of assets and liabilities. Investment tax credits from prior years are being amortized to income by the California Utilities over the estimated service lives of the properties. Other credits, mainly low-income housing and synthetic-fuel tax credits, are recognized in income as earned. The company follows certain provisions of SFAS 109 that permit regulated enterprises to recognize regulatory assets or liabilities to offset deferred tax liabilities and assets, respectively, if it is probable that such amounts will be recovered from, or returned to, customers. The company follows Accounting Principles Board Opinion (APBO) 23, Accounting for Income Taxes -- Special Areas, in recording deferred taxes for investments in foreign subsidiaries and the undistributed earnings of foreign subsidiaries.

Property, Plant and Equipment

Property, Plant and Equipment primarily represents the buildings, equipment and other facilities used by the California Utilities to provide natural gas and electric utility services, and by Sempra Generation.

The cost of plant includes labor, materials, contract services, and certain expenditures incurred during a major maintenance outage of a generating plant. Maintenance costs are expensed as incurred. In addition, the cost of utility plant includes an allowance for funds used during construction (AFUDC). The cost of non-utility plant includes capitalized interest. The cost of most retired depreciable utility plant minus salvage value is charged to accumulated depreciation.

Property, plant and equipment balances by major functional categories are as follows:

				Property, Plant and Equipment at December 31,				Depreciation rates for years ended December 31,
	(Dollars in billions)			2005		2004		2005		2004		2003
California Utilities:
	Natural gas operations			$	8.6	$	8.1	3.66	%	3.65	%	4.27	%
	Electric distribution				3.5		3.4	4.13	%	4.11	%	4.70	%
	Electric transmission				1.1		1.0	3.05	%	3.06	%	3.09	%
	Other electric				0.6		0.6	9.75	%	11.33	%	9.53	%
	Construction work in progress				0.8		0.5	NA		NA		NA
			Total		14.6		13.6
Sempra Global and Parent:
	Land and land rights				0.1		0.1
	Buildings and leasehold improvements				0.1		0.2
	Machinery and equipment
		Generating plant			1.4		1.2
		Pipelines			0.3		0.3
		Other			0.5		0.4
	Construction work in progress				0.5		0.3
	Other				0.1		0.1
					3.0		2.6	various		various		various
			Total	$	17.6	$	16.2

Accumulated depreciation and decommissioning of natural gas and electric utility plant in service were $3.4 billion and $1.6 billion, respectively, at December 31, 2005, and were $3.3 billion and $1.4 billion, respectively, at December 31, 2004. Depreciation expense is based on the straight-line method over the useful lives of the assets or, for the California Utilities, a shorter period prescribed by the CPUC. Accumulated depreciation for power plants at Sempra Generation was $111 million and $47 million at December 31, 2005 and 2004, respectively. Depreciation expense is computed using the straight-line method over the asset's estimated original composite useful life or the remaining term of the site leases, whichever is lower.

AFUDC, which represents the cost of debt and equity funds used to finance the construction of utility plant, is added to the cost of utility plant. Although it is not a current source of cash, AFUDC increases income and is recorded partly as an offset to interest charges and partly as a component of Other Income, Net in the Statements of Consolidated Income. AFUDC amounted to $19 million, $18 million and $29 million for 2005, 2004 and 2003, respectively. Total capitalized carrying costs, including AFUDC and the impact of Sempra Generation's construction projects, were $48 million, $27 million and $55 million for 2005, 2004 and 2003, respectively.

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the fair value of the net assets of acquired companies. Goodwill is not amortized, but is tested annually for impairment in accordance with SFAS 142, Goodwill and Other Intangible Assets.

There were no changes in the carrying amount of goodwill (included in Noncurrent Sundry Assets on the Consolidated Balance Sheets) since January 1, 2004. As of December 31, 2005, goodwill is recorded as follows:

(Dollars in millions)
Sempra Commodities	$	164
Sempra Generation		18
Other		6
	$	188

In addition, the unamortized goodwill related to unconsolidated subsidiaries (included in Investments on the Consolidated Balance Sheets), primarily those located in South America, was $291 million and $296 million at December 31, 2005 and 2004, respectively, before foreign-currency translation adjustments. Including foreign-currency translation adjustments, these amounts were $258 million and $238 million, respectively. Other intangible assets were not material at December 31, 2005 or 2004.

Long-Lived Assets

The company periodically evaluates whether events or circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets, the definition of which does not include unconsolidated subsidiaries. Impairment of long-lived assets occurs when the estimated future undiscounted cash flows are less than the carrying amount of the assets. If that comparison indicates that the assets' carrying value may be permanently impaired, the potential impairment is measured based on the difference between the carrying amount and the fair value of the assets based on quoted market prices or, if market prices are not available, on the estimated discounted cash flows. This calculation is performed at the lowest level for which separately identifiable cash flows exist. Further discussion of SFAS 144 is provided in "New Accounting Standards." During 2005 impairments included pre-tax write-downs of $66 million at Sempra Generation and $6 million at Sempra Pipelines & Storage for abandoned projects. Impairments in 2003 included a $77 million before-tax write-down of the carrying value of the assets of Frontier Energy, a small utility subsidiary of Sempra Pipelines & Storage, and a $24 million before-tax write-down of the carrying value of the assets at Atlantic Electric & Gas Limited (AEG). This is discussed further in "New Accounting Standards" below and in Note 4. The carrying value of unconsolidated subsidiaries is evaluated for impairment based on the requirements of APBO 18, The Equity Method of Accounting for Investments in Common Stock.

Nuclear Decommissioning Liability

At December 31, 2005 and 2004, SDG&E had asset retirement obligations of $339 million and $328 million, respectively, and related regulatory liabilities of $346 million and $333 million, respectively, related to nuclear decommissioning, in accordance with SFAS 143. Information about San Onofre Nuclear Generating Station (SONGS) decommissioning costs is included below in "New Accounting Standards."

Legal Fees

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

Comprehensive Income

Comprehensive income includes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events, including foreign-currency translation adjustments, minimum pension liability adjustments and certain hedging activities. The components of other comprehensive income, which consists of all these changes other than net income as shown on the Statements of Consolidated Income, are shown in the Statements of Consolidated Changes in Shareholders' Equity.

The components of Accumulated Other Comprehensive Income (Loss), net of income taxes at December 31, 2005 (in millions of dollars) are as follows:

Foreign-currency translation loss	$	(264	)
Financial instruments, net of $30 income tax benefit		(58	)
Minimum pension liability adjustments, net of $25 income tax benefit		(36	)
Balance as of December 31, 2005	$	(358	)

Stock-Based Compensation

The company has stock-based employee compensation plans, which are described in Note 9. The company accounts for these plans under the recognition and measurement principles of APBO 25, Accounting for Stock Issued to Employees, and related Interpretations. Employee compensation cost is reflected in net income in all years for restricted stock awards, and in 2005, for the acceleration in vesting for certain options. The following table provides the pro forma effects of recognizing compensation expense in accordance with SFAS 123, Accounting for Stock-Based Compensation:

		Years ended December 31,
(Dollars in millions, except per share amounts)			2005			2004			2003
Net income as reported		$	920		$	895		$	649
Stock-based employee compensation expense reported in net income net of tax			37			24			13
Total stock-based employee compensation under fair-value method for all awards, net of tax			(43	)		(30	)		(20	)
Pro forma net income		$	914		$	889		$	642
Earnings per share:
	Basic - as reported	$	3.74		$	3.92		$	3.07
	Basic - pro forma	$	3.72		$	3.89		$	3.03
	Diluted - as reported	$	3.65		$	3.83		$	3.03
	Diluted - pro forma	$	3.63		$	3.80		$	2.99

Revenues

Revenues of the California Utilities are primarily derived from deliveries of electricity and natural gas to customers and changes in related regulatory balancing accounts. Revenues from electricity and natural gas sales and services are recorded under the accrual method and recognized upon delivery. The portion of SDG&E's electric commodity that was procured for its customers by the California Department of Water Resources (DWR) and delivered by SDG&E is not included in SDG&E's revenues or costs. Commodity costs associated with long-term contracts allocated to SDG&E from the DWR also are not included in the Statements of Consolidated Income, since the DWR retains legal and financial responsibility for these contracts. Note 13 includes a discussion of the electric industry restructuring. Natural gas storage contract revenues are accrued on a monthly basis and reflect reservation, storage and injection charges in accordance with negotiated agreements, which have terms of up to three years. Operating revenue includes amounts for services rendered but unbilled (approximately one-half month's deliveries) at the end of each year. Included in revenues for the California utilities are revenues of $1.8 billion, $1.7 billion and $1.8 billion for electric and $5.3 billion, $4.5 billion and $4.0 billion for natural gas for 2005, 2004 and 2003, respectively.

Additional information concerning utility revenue recognition is discussed above under "Regulatory Matters."

Sempra Commodities generates a substantial portion of its revenues from market making and trading activities, as a principal, in natural gas, electricity, petroleum, metals and other commodities, for which it quotes bid and ask prices to end users and other market makers. Principal transaction revenues are recognized on a trade-date basis, and include realized gains and losses, and the net change in the fair value of unrealized gains and losses. Sempra Commodities also earns trading profits as a dealer by structuring and executing transactions. Sempra Commodities utilizes derivative instruments to reduce its exposure to unfavorable changes in market prices, which are subject to significant and volatile fluctuation. These instruments include futures, forwards, swaps and options.

Options, which are either exchange-traded or directly negotiated between counterparties, provide the holder with the right to buy from or sell to the other party an agreed amount of a commodity at a specified price within a specified period or at a specified time. As a writer of options, Sempra Commodities generally receives an option premium and then manages the risk of an unfavorable change in the value of the underlying commodity by entering into offsetting transactions or by other means.

Forward and future transactions are contracts for delivery of commodities in which the counterparty agrees to make or take delivery at a specified price. Commodity swap transactions may involve the exchange of fixed and floating payment obligations without the exchange of the underlying commodity. Sempra Commodities' financial instruments represent contracts with counterparties whereby payments are linked to or derived from market indices or on terms predetermined by the contract.

Non-derivative contracts are being carried at cost and accounted for on an accrual basis and, therefore, the related profit or loss will be recognized as the contract is performed. Derivative instruments are discussed further in Note 10.

Sempra Generation's revenues are derived primarily from the sale of electric energy to governmental and wholesale power marketing entities and are recognized as the energy is delivered in accordance with the provisions of Emerging Issues Task Force (EITF) 91-6, Revenue Recognition of Long-term Power Supply Contracts, and EITF 96-17, Revenue Recognition Under Long-term Power Sales Contracts that Contain Both Fixed and Variable Terms. During 2005 and 2004, electric energy sales to the DWR accounted for a significant portion of Sempra Generation's revenues. A small portion of Sempra Generation's revenue is generated from energy-related products and services to commercial, industrial, government and institutional markets.

The consolidated foreign subsidiaries of Sempra Pipelines & Storage, all of which operate in Mexico, recognize revenue as deliveries are made similar to the California Utilities, except that SFAS 71 is not applicable due to the different regulatory environment.

Foreign Currency Translation

The assets and liabilities of the company's foreign operations are translated into U.S. dollars at current exchange rates, and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments do not enter into the calculation of net income or retained earnings (unless the operation is being discontinued), but are reflected in Comprehensive Income and in Accumulated Other Comprehensive Income, a component of shareholders' equity, as described above. To reflect the fluctuation in the value of the Argentine peso, the functional currency of the company's Argentine operations, Sempra Pipelines & Storage adjusted its investment in its two Argentine natural gas utility holding companies downward by $3 million, downward by $1 million and upward by $26 million in 2005, 2004 and 2003, respectively. A similar adjustment has been made to its investment in Chile to reflect the fluctuation in the value of the Chilean peso, the functional currency of the company's Chilean operations, upward by $32 million in 2005, $22 million in 2004 and $43 million in 2003. These non-cash adjustments did not affect net income, but did affect Comprehensive Income and Accumulated Other Comprehensive Income (Loss). Smaller adjustments have been made to other operations where the U.S. dollar is not the functional currency. Additional information concerning these investments is described in Note 3.

Currency transaction gains and losses in a currency other than the entity's functional currency are included in the calculation of consolidated net income. The company recorded $1 million of currency transaction gains in 2005 and $8 million of currency transaction losses in 2003.

Transactions with Affiliates

Loans to Unconsolidated Affiliates

In December 2001, Sempra Pipelines & Storage issued two U.S. dollar denominated loans totaling $35 million and $22 million to its affiliates Camuzzi Gas Pampeana S. A. and Camuzzi Gas del Sur S. A., respectively. These loans have variable interest rates (11.54% at December 31, 2005) and are due in October 2006 and June 2006, respectively. The balances outstanding under the notes were $21 million and $42 million at December 31, 2005 and 2004, respectively. These amounts are included in non-current assets under Due from Unconsolidated Affiliates, because company management does not expect to request payment in 2006.

Loans from Unconsolidated Affiliates

At both December 31, 2005 and 2004, Sempra Pipelines & Storage had long-term notes payable to affiliates which include $60 million at 6.47% due April 1, 2008 and $100 million at 6.62% due April 1, 2011. The loans are due to Chilquinta Energía Finance Co. LLC and are secured by Sempra Pipelines & Storage's investments in Chilquinta Energía S.A. and Luz del Sur S.A.A. (Luz del Sur), which are discussed in Note 3.

In February 2000, a wholly owned subsidiary trust of the company issued $200 million of preferred stock in the form of 8.90% Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). The company redeemed the $200 million of mandatorily redeemable trust preferred securities in February 2005.

Revenues and Expenses with Unconsolidated Affiliates

During the first seven months of 2005 and in all of 2004, Sempra Generation recorded $38 million and $60 million, respectively, in sales to El Dorado, then an unconsolidated affiliate, and recorded $43 million and $71 million, respectively, of purchases from El Dorado for those same periods. Sempra Energy purchased the remaining 50% interest in El Dorado in July 2005 and consolidated El Dorado in its financial statements. Additionally, during 2005 and 2004, Sempra Commodities recorded $85 million and $28 million, respectively of purchases from Topaz Power Partners (Topaz), an unconsolidated affiliate. Sales to Topaz were $213 million and $74 million in 2005 and 2004, respectively.

Capitalized Interest

The company recorded $33 million, $12 million and $34 million of capitalized interest for 2005, 2004 and 2003, respectively, including the portion of AFUDC related to debt.

Other Income, Net

Other Income, Net consists of the following:

			Years ended December 31,
(Dollars in millions)		2005				2004			2003
Equity in income (losses) of unconsolidated subsidiaries (Note 3)		$		11		$	(26	)	$	(57	)
Regulatory interest, net				(6	)		3			(2	)
Allowance for equity funds used during construction				14			14			21
Gain on settlement of Cameron liability				--			13			--
Sundry, net				32			29			(2	)
	Total	$		51		$	33		$	(40	)

New Accounting Standards

SFAS 123 (revised 2004), "Share-Based Payment" (SFAS 123R): In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R, a revision of SFAS 123, Accounting for Stock-Based Compensation (SFAS 123), which establishes the accounting for transactions in which an entity exchanges its equity instruments for goods or services received. This statement requires companies to measure and record the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The company expects to adopt the provisions of SFAS 123R using a modified prospective application. The modified prospective method requires companies to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value that the company had originally estimated for purposes of preparing its SFAS 123 pro forma disclosures. For all new awards that are granted or modified after the effective date, a company would use SFAS 123R's measurement model. The effect of adopting SFAS 123R has not been determined; however, the pro forma effects of recognizing compensation expense in accordance with SFAS 123 are discussed above in Stock-Based Compensation. The effective date of this statement is January 1, 2006.

SFAS 143, "Accounting for Asset Retirement Obligations" and FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143": Beginning in 2003, SFAS 143 requires entities to record the present value of liabilities for future costs expected to be incurred when assets are retired from service, if the retirement process is legally required. It requires recording of the estimated retirement cost over the life of the related asset by depreciating the present value of the obligation (measured at the time of the asset's acquisition) and accreting the discount until the liability is settled. The adoption of SFAS 143 on January 1, 2003 resulted in the recording of an addition to utility plant of $71 million, representing the company's share of SONGS' estimated future decommissioning costs (as discounted to the present value at the dates the units began operation), and accumulated depreciation of $41 million related to the increase to utility plant, for a net increase of $30 million. On January 1, 2003, the company recorded additional asset retirement obligations of $20 million associated with the future retirement of a former power plant and three storage facilities.

In March 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143." The interpretation clarifies that the term "conditional asset-retirement obligation" as used in SFAS 143, refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated.

The adoption of FIN 47 on December 31, 2005 resulted in the recording of an addition to utility plant of $198 million and accumulated depreciation of $74 million related to the increase to utility plant, for a net increase of $124 million. In addition, the company recorded a corresponding retirement obligation liability of $619 million (which includes accretion of that discounted value to December 31, 2005) and a regulatory liability of $1.1 billion to reflect that the California Utilities have collected the funds from customers more quickly than FIN 47 would accrete the retirement liability and depreciate the asset.

The adoption of SFAS 143 required the reclassification of utilities' estimated removal costs collected in rates, which had historically been recorded in accumulated depreciation, to a regulatory liability. At December 31, 2005 and 2004, these costs were $200 million and $1.4 billion, respectively, for SoCalGas, and $724 million and $913 million, respectively, for SDG&E. The change in the balance is due to the implementation of FIN 47, which required the reclassification of disposal costs that previously have been included in the utilities' estimated cost of removal obligations to a regulatory liability and to Asset Retirement Obligations.

In accordance with FIN 47, the company has determined that the amount of asbestos-containing materials could not be determined and, therefore, no liability has been recognized for the related removal obligations. Since most, if not all, of the cost of removing such materials would be found at the California Utilities, where the cost of removal would be expected to be recovered in rates, the effect of not recognizing these liabilities is not material to the company's financial condition or results of operations. A liability for the obligations will be recorded in the period in which sufficient information is available to reasonably estimate the removal cost.

Had FIN 47 been in effect on December 31, 2004, the asset retirement obligation liability would have been $583 million as of that date.

Except for the items noted above, the company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

Implementation of SFAS 143 and FIN 47 had no significant effect on results of operations and is not expected to have a significant effect in the future.

The changes in the asset retirement obligations for the years ended December 31, 2005 and 2004 are as follows (dollars in millions):

	2005			2004
Balance as of January 1	$	348	*	$	337	*
Adoption of FIN 47		619
Accretion expense		25			24
Payments		(16	)		(10	)
Revision of estimated cash flows		1			(3	)
Balance as of December 31	$	977	*	$	348	*

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

SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets": In August 2001, the FASB issued SFAS 144, which replaces SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. It applies to all long-lived assets. Among other things, SFAS 144 requires that an impairment loss be recorded if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows.

During the third and fourth quarters of 2003, the company recorded impairment charges of $77 million and $24 million to write down the carrying value of the assets of Frontier Energy and AEG, respectively. The Frontier Energy impairment resulted from reductions in actual and anticipated sales of natural gas by the utility. The AEG impairment was due to less-than-anticipated customer growth. In applying the provisions of SFAS 144, management determined the fair value of such assets based on its estimates of discounted future cash flows.

During the fourth quarter of 2005, Sempra Generation recorded a non-cash impairment charge to write down the carrying value of a turbine set (consisting of two gas turbines and one steam turbine) to their estimated fair values. The estimated fair value was based on sales of similar assets. The turbine set was initially purchased in anticipation of constructing one of several electrical generation projects under development by the company. The impairment resulted from management's strategic review process and the decision to indefinitely delay all development projects which might utilize the turbine sets. The charge is included in Impairment Losses in the Statements of Consolidated Income.

SFAS 154, "Accounting Changes and Error Corrections, a replacement of APBO 20 and FASB Statement No. 3": This statement applies to all voluntary changes in accounting principles and to changes required by an accounting pronouncement in instances where the pronouncement does not include specific transition provisions. APBO 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to do so. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities": EITF 98-10 provided for marking to market commodities and arrangements that are not marked to market by SFAS 133 unless certain hedging standards specified in SFAS 133 are complied with. For the company, this consists of contracts involving transportation and storage and certain inventory. The specified hedging standards have been complied with for a portion of the otherwise-excluded items. A substantial majority of the company's items covered by EITF 98-10 are covered by SFAS 133. On January 1, 2003, the company recorded the initial effect of EITF 98-10's rescission as a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million. Neither the cumulative nor the ongoing effect impacts the company's cash flow or liquidity. Additional information on derivative instruments is provided in Note 10.

FIN 46, "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51": FIN 46, as revised by FIN 46R, requires an enterprise to consolidate a variable interest entity (VIE), as defined in FIN 46, if the company is the primary beneficiary of a VIE's activities.

Sempra Energy adopted FIN 46 on December 31, 2003, resulting in the consolidation of two VIEs for which it is the primary beneficiary. One of the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant for which the company had a synthetic lease agreement. The company recorded an after-tax credit of $9 million in the fourth quarter of 2003 for the cumulative effect of the change in accounting principle. The company bought out the lease in January 2004 and now owns the plant.

The other VIE is AEG. Consolidation of AEG resulted in Sempra Energy's recording of 100 percent of AEG's balance sheet and results of operations, whereas it previously recorded only its share of AEG's net operating results. Due to AEG's consolidation, the company recorded an after-tax charge of $26 million in the fourth quarter of 2003 for the cumulative effect of the change in accounting principle. During the first quarter of 2004, Sempra Energy's board of directors approved management's plan to dispose of AEG. Note 4 provides further discussion concerning this matter and the April 2004 disposal of AEG. Had AEG and the Mesquite Trust been consolidated in 2003, the company's net income for 2003 would have been $662 million.

The $46 million cumulative effect recorded in 2003 on the Statements of Consolidated Income, net of the tax benefit of $26 million, consists of the following items which are described above (dollars in millions):

FIN 46:
	Mesquite Trust		$	9
	AEG			(26	)
		Net Charge		(17	)
EITF 98-10				(29	)
		Total Charge	$	(46	)

In addition, contracts under which SDG&E acquires power from generation facilities otherwise unrelated to SDG&E could result in a requirement for SDG&E to consolidate the entity that owns the facility. In accordance with FIN 46, SDG&E is continuing the process of determining whether it has any such situations and, if so, gathering the information that would be needed to perform the consolidation. The effects of this, if any, are not expected to significantly affect the financial position of SDG&E and there would be no effect on results of operations or liquidity.

FASB Staff Position (FSP) 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004": As discussed in the 2004 Annual Report, the company continued to evaluate the repatriation provision throughout 2005. The company has completed its evaluation and will not repatriate any foreign earnings pursuant to the repatriation provision.

NOTE 2. RECENT ACQUISITION AND INVESTMENT ACTIVITY

Sempra Commodities

In 2003, the company acquired rights for the development of Bluewater Gas Storage, a natural gas storage facility in Michigan, and in 2004 the company acquired rights for the development of Pine Prairie Energy Center, a salt-cavern natural gas storage facility in Evangeline Parish, Louisiana. In September 2005, Sempra Commodities sold both investments for $253 million.

Sempra Generation

In July 2005, Sempra Generation purchased Reliant Energy's 50-percent interest in El Dorado Energy for $132 million (including assumed debt), resulting in Sempra Generation's having full ownership of the 480-megawatt (MW) El Dorado power plant located in Boulder City, Nevada.

In July 2004, Sempra Generation began construction of the 550-MW Palomar power plant in Escondido, California. The project is expected to be completed in the first half of 2006, at which time it will be sold to SDG&E.

In December 2005, Sempra Generation announced plans to sell or refinance its Texas-based power plants due to the increased market valuation of coal-fired power plants in Texas. The coal-fired assets involved in the announcement include the company's wholly owned Twin Oaks Power plant (Twin Oaks), with a carrying value of $128 million at December 31, 2005, and the Coleto Creek Power plant, with a carrying value of $47 million at December 31, 2005, that the company co-owns in the Topaz joint venture with Carlyle/Riverstone. The joint venture also owns three operating natural gas and oil-fired plants (in Laredo, San Benito and Corpus Christi, Texas) that were included in the announcement. In January 2006, Sempra Generation announced an agreement for the sale of Twin Oaks for $480 million.

Sempra LNG

In December 2004, Sempra LNG entered into two contracts for the Energía Costa Azul terminal in Baja California, Mexico. One is for the construction of the terminal at Costa Azul for $500 million and one is for the construction of the project's breakwater for $170 million. Through December 31, 2005, Sempra LNG has made expenditures of $334 million related to Energía Costa Azul. Construction on the terminal began in early 2005 and the terminal is expected to begin operations in 2008. It is expected to cost approximately $800 million and will be capable of processing 1 billion cubic feet (bcf) of natural gas per day. Sempra Pipelines & Storage will be expanding its Baja California pipelines to connect Energía Costa Azul to existing natural gas pipelines.

In August 2005, Sempra LNG finalized a contract for the construction of its Cameron LNG regasification terminal in Hackberry, Louisiana. The contract is valued at approximately $500 million. The terminal is currently designed to supply 1.5 bcf of natural gas per day. In January 2006, Sempra LNG received approval from the FERC to begin the mandatory pre-filing process to expand the terminal's production capacity to 2.65 bcf per day. The total cost of the project, including the proposed expansion, is expected to be $950 million. In addition, total rent payments and wharfage fees related to the plant's land lease are expected to be $47 million over 30 years. The initial construction of Cameron is scheduled to be completed in late 2008 and the proposed expansion is scheduled for completion in 2010. Grading for the terminal began in August 2005.

Sempra Pipelines & Storage

Sempra Pipelines & Storage will be expanding its existing pipelines in Baja California, Mexico, and adding a spur line to connect Sempra LNG's Energía Costa Azul terminal to existing natural gas pipelines. The estimated costs related to the connection of Energía Costa Azul to these lines is $200 million. The expansion is expected to be completed in early 2008.

In July 2004, the company acquired the rights to develop Liberty Gas Storage (Liberty), a salt-cavern natural gas storage facility located in Calcasieu Parish, Louisiana. In May 2005, ProLiance Transportation and Storage, LLC acquired a 25-percent ownership in Liberty from the company. In December 2005, the company received authorization from the FERC to construct and operate Liberty. The facility will provide 17 bcf of working natural gas capacity for storage and will be connected to the Cameron and Port Arthur Pipelines. These two new pipelines under development by Sempra Pipelines & Storage will connect area liquefied natural gas (LNG) regasification terminals to the interstate gas transmission system. Liberty is estimated to cost $172 million and is expected to begin operations in September 2006.

NOTE 3. INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES

Investments are generally accounted for under the equity method when the company has an ownership interest of twenty to fifty percent. In these cases, the company's pro rata shares of the subsidiaries' net assets are included in Investments on the Consolidated Balance Sheets, and are adjusted for the company's share of each investee's earnings or losses, dividends and foreign currency translation effects. Equity in earnings of unconsolidated subsidiaries that is recorded before income tax is reported in Other Income, Net on the Statements of Consolidated Income. Equity earnings recorded net of income tax recorded by the subsidiary are reported in Equity in Earnings of Certain Unconsolidated Subsidiaries on the Statements of Consolidated Income. The company accounts for certain investments in housing partnerships made before May 19, 1995 under the cost method, whereby they have been amortized over ten years based on the expected residual value. The company has no unconsolidated subsidiaries where its ability to influence or control an investee differs from its ownership percentage.

The company's long-term investment balances and earnings are summarized as follows:

			Investment at December 31,
(Dollars in millions)				2005		2004
Equity method investments:
	Chilquinta Energía		$	430	$	376
	Luz del Sur			150		157
	Sodigas Pampeana and Sodigas Sur			88		82
	Elk Hills Power			218		217
	Topaz Power Partners			51		66
	El Dorado Energy*			--		55
	Housing partnerships			121		146
	Sempra Financial synthetic-fuel partnerships			--		12
		Total		1,058		1,111
Cost method investments--housing partnerships				24		36
	Investments in unconsolidated subsidiaries			1,082		1,147
Other				22		17
Total long-term investments			$	1,104	$	1,164

					Earnings for the Years ended December 31,
(Dollars in millions)				2005				2004			2003
Equity method investments:
	Earnings recorded net of tax:
		Chilquinta Energía		$		25		$	16		$	19
		Luz del Sur				21			29			20
		Sodigas Pampeana and Sodigas Sur				9			17			23
			Total earnings recorded net of tax	$		55		$	62		$	62
	Earnings recorded before tax:
		Elk Hills Power		$		3		$	3		$	(1	)
		El Dorado Energy*				(6	)		(13	)		(5	)
		Topaz Power Partners				28			13			--
		Housing partnerships				(17	)		(20	)		(27	)
		Sempra Financial synthetic-fuel partnerships				3			(9	)		(19	)
		AEG				--			--			(5	)
			Total earnings recorded before tax	$		11		$	(26	)	$	(57	)

* El Dorado Energy has been consolidated since the acquisition of the remaining 50% in July 2005.

For equity method investments, costs in excess of equity in net assets (goodwill) were $258 million and $238 million at December 31, 2005 and 2004, respectively. Amortization thereof ceased in 2002 in accordance with SFAS 142. Costs in excess of the underlying equity in net assets will continue to be reviewed for impairment in accordance with APBO 18. Descriptive information concerning each of these investments follows.

Sempra Pipelines & Storage

Sempra Pipelines & Storage and PSEG Global (PSEG), an unaffiliated company, each own a

50-percent interest in Chilquinta Energía S.A., a Chilean electric utility.

On April 1, 2004, Sempra Pipelines & Storage and PSEG sold a portion of their interests in Luz del Sur, a Peruvian electric utility, for a total of $62 million. Each party had a 44-percent interest in Luz del Sur prior to the sale and a 38-percent interest thereafter. As a result of the sale, Sempra Pipelines & Storage recognized a $5 million after-tax gain in 2004, which is included in Equity in Earnings of Certain Unconsolidated Subsidiaries on the Statements of Consolidated Income.

Sempra Pipelines & Storage also owns 43 percent of two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur. As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent changes in the value of the peso, Sempra Pipelines & Storage had reduced the carrying value of its investment downward by a cumulative total of $201 million as of December 31, 2005. These non-cash adjustments continue to occur based on fluctuations in the value of the Argentine peso. They do not affect net income, but increase or decrease Other Comprehensive Income (Loss) and Accumulated Other Comprehensive Income (Loss).

The related Argentine economic decline and government responses (including Argentina's unilateral, retroactive abrogation of utility agreements early in 2002) continue to adversely affect the operations of these Argentine utilities. In 2002, Sempra Pipelines & Storage initiated arbitration proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments that has resulted from Argentine governmental actions. In 2003, Sempra Pipelines & Storage filed its legal brief with the International Center for Settlement of Investment Disputes, outlining its claims for $211 million (previously $258 million). The company has also presented additional information that may provide a basis for a larger award. Hearings were held in February 2006 and a decision is expected in late 2006. Sempra Energy also has a $48.5 million political-risk insurance policy under which it has filed a claim to recover a portion of the investments' diminution in value and has commenced the arbitration procedure with the insurance company to determine coverage and the amount of the loss under the policy. Hearings are scheduled for April 2006 and a decision is expected in mid-2006.

Sempra Generation

The 550-MW Elk Hills Power (Elk Hills) project located near Bakersfield, California began commercial operations in July 2003. Elk Hills is 50 percent owned by Sempra Generation.

The 480-MW El Dorado power plant, located near Las Vegas, Nevada, began commercial operations in May 2000. In July 2005, Sempra Generation purchased the remaining 50 percent ownership interest in El Dorado for $132 million (including assumed debt) from Reliant Energy Power Generation, who had been the joint venture partner in the El Dorado power plant.

In July 2004, Topaz acquired ten Texas power plants from American Electric Power (AEP), including the 632-MW coal-fired Coleto Creek Power Station and three natural gas and oil-fired plants in Laredo, San Benito and Corpus Christi, Texas. Topaz acquired these assets for $432 million in cash and the assumption of various environmental and asset retirement liabilities currently estimated at $41 million. $355 million of the purchase price was provided by non-recourse project financing related solely to the acquisition of the Coleto Creek Power Station.

The transaction included the acquisition of six operating power plants with generating capacity of 1,950 MW and four inactive power plants capable of generating 1,863 MW. Concurrently with the acquisition, Topaz sold one of the inactive power plants and no gain or loss was recorded on the transaction. In December 2005, Topaz sold the Eagle Pass hydro facility for a small gain.

Topaz has entered into several power sales agreements for 572 MW of Coleto Creek Power Station's capacity. Contracts comprising 98% of the total capacity under contract expire by 2010. Sempra Generation manages the plants.

In conjunction with the acquisition of the Topaz plants, Sempra Energy provided AEP a guarantee for certain specified liabilities described in the acquisition agreement. This guarantee is limited to $75 million for the first five years after the acquisition date and $25 million for the next five years, but not more than $75 million over the entire 10-year period. Management does not expect any material losses to result from the guarantee because performance is not expected to be required and, therefore, management believes that the fair value of the guarantee is immaterial. The guarantee would not necessarily be terminated in connection with sales of the plants.

In December 2005, Sempra Generation announced plans to sell or refinance certain Topaz plants and the Twin Oaks plant discussed in Note 2.

Sempra Financial

Sempra Financial invests as a limited partner in affordable-housing properties. Sempra Financial's portfolio includes 1,300 properties throughout the United States that are expected to provide income tax benefits (primarily from income tax credits) over 10-year periods.

The cost of Sempra Financial's investment in Section 29 income tax credits has been fully recovered for financial statement purposes as a result of a 2004 sale and additional, contingent payments are being recorded as income as they are received.

Sempra Commodities

Available-for-Sale Securities

Sempra Commodities recorded $6 million and $5 million in purchases of available-for-sale securities in 2005 and 2004, respectively, and sold $4 million of available-for-sale securities in 2005, yielding proceeds of $6 million. The cost basis of the sales was determined by the specific identification method and a gain of $2 million was realized as a result of the sales in 2005. Sempra Commodities had $5 million and $14 million of available-for-sale securities included in Investments at December 31, 2005 and 2004, respectively. There was $4 million in unrealized gains, net of income tax, in Accumulated Other Comprehensive Income (Loss) at December 31, 2004 related to these securities, which was largely transferred to income in 2005. Trading securities at December 31, 2005 included $9 million of securities, including a $5 million unrealized gain, that were reclassified from available-for-sale securities during 2005, due to changes in their status. Sempra Commodities had $12 million of trading securities at December 31, 2005.

NOTE 4. DISCONTINUED OPERATIONS

In the first quarter of 2004, Sempra Energy's board of directors approved management's plan to dispose of its interest in AEG, which marketed power and natural gas commodities to commercial and residential customers in the United Kingdom. This disposal met the criteria established for recognition as discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. In April 2004, AEG went into administrative receivership and substantially all of the assets were sold. This transaction resulted in an after-tax 2004 loss of $2 million.

The net losses from discontinued operations were $9 million and $25 million in 2005 and 2004, respectively. The 2005 loss was primarily attributed to foreign currency translation adjustments associated with AEG's remaining assets and liabilities, legal costs and reserves against accounts receivable. During 2003, the company accounted for its investment in AEG under the equity method of accounting. As such, in 2003, the company recorded its share of AEG's net losses of $5 million in Other Income, Net on the Statements of Consolidated Income. Additionally, during the fourth quarter of 2003, the company recorded an after-tax charge of $21 million to write down the carrying value of assets at AEG. Effective December 31, 2003, AEG was consolidated as a result of the adoption of FIN 46, as discussed in Note 1.

Included within the net loss from discontinued operations are AEG's operating results, summarized below:

	Years ended December 31,
(Dollars in millions)	2005				2004
Operating revenues		$	--			$	201
Loss from discontinued operations, before income tax benefit of $7 for 2004		$	--			$	(30	)
Loss on disposal of discontinued operations, before income tax benefit of $4 for 2004		$	(9	)		$	(6	)

AEG's balance sheet data, excluding intercompany balances (which are significant) eliminated in consolidation, are summarized below:

		December 31, 2005		December 31, 2004
(Dollars in millions)
Assets:
	Accounts receivable, net	$	14	$	37
	Other current assets		36		33
Total assets		$	50	$	70
Total liabilities (all current)		$	10	$	17

NOTE 5. DEBT AND CREDIT FACILITIES

Committed Lines of Credit

At December 31, 2005, the company had available $4.7 billion in unused, committed lines of credit to provide liquidity and support commercial paper. As of December 31, 2005, $22 million of the lines supported variable-rate debt.

Sempra Global has a $2.5 billion five-year syndicated revolving credit facility expiring in 2010 and a $750 million three-year syndicated revolving credit facility expiring in 2008. The five-year and three-year credit facilities also provide for the issuance of up to $400 million and $500 million, respectively, of letters of credit on behalf of Sempra Global. The amount of borrowings otherwise available under each facility would be reduced by the amount of outstanding letters of credit. Obligations under each facility are guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit rating. Each facility requires Sempra Energy to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65 percent. At December 31, 2005, Sempra Global had letters of credit of $166 million under the facility. The facility also provides support for $673 million of commercial paper outstanding at December 31, 2005.

Sempra Commodities has a five-year syndicated revolving credit facility providing up to $1.72 billion of extensions of credit (consisting of borrowings, letters of credit and other credit support accommodations) to Sempra Commodities and certain of its affiliates. The facility expires in 2010. The amount of credit available under the facility is limited to the amount of a borrowing base consisting of receivables, inventories and other assets of Sempra Commodities that secure the credit facility and that are valued for purposes of the borrowing base at varying percentages of current market value. Extensions of credit are guaranteed by Sempra Energy subject to a maximum guarantee liability of 20 percent of the lenders' total commitments under the facility. The facility requires Sempra Commodities to meet certain financial tests at the end of each quarter, including current ratio, leverage ratio, senior debt to tangible net worth ratio, and minimum net worth and tangible net worth tests. It also requires Sempra Energy to maintain, at the end of each quarter a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65 percent. It also imposes certain other limitations on Sempra Commodities, including limitations on other indebtedness, capital expenditures, liens, transfers of assets, investments, loans, advances, dividends, other distributions, modifications of risk-management policies and transactions with affiliates. At December 31, 2005, letters of credit of $838 million were outstanding under the facility.

Sempra LNG has a $1.25 billion five-year syndicated revolving credit facility that expires in 2009. The facility also provides for the issuance of letters of credit not exceeding $200 million outstanding at any one time. Borrowings, letter of credit obligations and other obligations under the facility are guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit ratings. The facility requires Sempra Energy to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65 percent. Sempra LNG had $200 million of outstanding borrowings and $185 million of outstanding letters of credit under this facility at December 31, 2005.

The California Utilities 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 the combined borrowing limit for both utilities of $600 million. Borrowings under the agreement bear interest at rates varying with market rates and the utility's credit rating. The agreement requires each utility to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65 percent. Borrowings under the agreement are individual obligations of the borrowing utility and a default by one utility would not constitute a default, or preclude borrowings by, the other. At December 31, 2005, the California Utilities had no amounts outstanding under this facility. The facility provides support for $88 million of commercial paper outstanding at December 31, 2005.

Uncommitted Lines of Credit

At December 31, 2005, Sempra Commodities had $457 million in various uncommitted lines of credit that are guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit rating. At December 31, 2005, Sempra Commodities had $343 million of letters of credit and no short-term borrowings outstanding against these lines.

Other Short-term Debt

In addition to the lines of credit and commercial paper, Sempra Energy had $101 million and $80 million of other short-term debt outstanding at December 31, 2005 and 2004, respectively. The company's weighted average interest rates on the total short-term debt outstanding were 4.54% and 2.82% at December 31, 2005 and 2004, respectively.

LONG-TERM DEBT

			December 31,
(Dollars in millions)				2005			2004
First mortgage bonds
	Variable rate (4.04% at December 31, 2005) December 1, 2009	$		100		$	100
	4.375% January 15, 2011			100			100
	Variable rates after fixed-to-floating rate swaps (3.62% at December 31, 2005) January 15, 2011			150			150
	4.8% October 1, 2012			250			250
	6.8% June 1, 2015			14			14
	5.3% November 15, 2015			250			--
	5.45% April 15, 2018			250			250
	5.9% June 1, 2018			68			68
	5.9% September 1, 2018			93			93
	5.85% June 1, 2021			60			60
	5% to 5.25% December 1, 2027			150			150
	2.516% to 2.832%* January and February 2034			176			176
	5.35% May 15, 2035			250			--
	5.75% November 15, 2035			250			--
	2.8275%* May 1, 2039			75			75
				2,236			1,486
Other long-term debt (unsecured unless otherwise noted)
	4.621% Notes May 17, 2007			600			600
	6.0% Notes February 1, 2013			400			400
	Notes at variable rates after fixed-to-floating swap (7.81% at December 31, 2005) March 1, 2010			300			300
	Notes at variable rates (4.46% at December 31, 2005) May 21, 2008			300			300
	4.75% Notes May 15, 2009			300			300
	7.95% Notes March 1, 2010			200			200
	Rate-reduction bonds, 6.31% to 6.37% at December 31, 2005 payable annually through 2007			132			198
	5.9% June 1, 2014			130			130
	Employee Stock Ownership Plan
	Bonds at 4.213% November 1, 2014			82			82
	Bonds at variable rates (4.59% at December 31, 2005) November 1, 2014			22			33
	5.5% December 1, 2021			60			60
	Debt incurred to acquire limited partnerships, secured by real estate, at 7.13% to 9.35% annually through 2009			48			76
	5.3% July 1, 2021			39			39
	4.9% March 1, 2023			25			25
	6.375% May 14, 2006			8			8
	5.67% January 18, 2028			5			5
	6.95% Notes December 1, 2005			--			300
	Other debt			40			33
	Capitalized leases			4			6
	Market value adjustments for interest rate swaps, net (expiring 2009-2011)			(1	)		13
				4,930			4,594
Current portion of long-term debt				(101	)		(398	)
Unamortized discount on long-term debt				(6	)		(4	)
Total		$		4,823		$	4,192

* After floating-to-fixed rate swaps expiring in 2009.

Excluding market value adjustments for interest-rate swaps and capital leases, which are described in Note 15, maturities of long-term debt are:

(Dollars in millions)
2006	$	100
2007		684
2008		308
2009		424
2010		512
Thereafter		2,899
Total	$	4,927

Callable Bonds

At the company's option, certain bonds are callable at various dates: $802 million in 2006, $82 million in 2007 and $274 million after 2010. In addition, $2.7 billion of bonds is callable subject to make-whole provisions.

First Mortgage Bonds

First mortgage bonds are issued by the California Utilities and secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds upon compliance with the provisions of their bond indentures, which require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of an additional $2.7 billion of first mortgage bonds at December 31, 2005.

In November 2005, SDG&E issued $250 million of first mortgage bonds maturing in 2015. In November 2005, SoCalGas issued $250 million of first mortgage bonds maturing in 2035. In May 2005, SDG&E issued $250 million of first mortgage bonds maturing in 2035.

Equity Units

In 2002, the company issued $600 million of Equity Units. The units included $600 million of the company's 5.60% senior notes due May 17, 2007. In February 2005, the company remarketed the senior notes for their remaining term at a rate of 4.621%. In March and May 2005, 19.7 million shares of common stock were issued in connection with the settlement of the related common stock purchase contract as discussed in Note 12.

Unsecured Long-term Debt

Various long-term obligations totaling $2.5 billion at December 31, 2005 are unsecured.

Rate-Reduction Bonds

In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26%. These bonds were issued to facilitate the 10-percent rate reduction mandated by California's electric-restructuring law, which is described in Note 13. They are being repaid over ten years by SDG&E's residential and small-commercial customers through a specified charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility property.

Debt of Employee Stock Ownership Plan (ESOP) and Trust (Trust)

The Trust covers substantially all of the employees of the parent organization, SoCalGas and most of Sempra Global's subsidiaries. The Trust is used to fund part of the retirement savings plan described in Note 8. The notes, which are payable by the trust and which mature in 2014, are repriced weekly and subject to repurchase by the company at the holder's option. Of these notes, $81.5 million were repriced at an interest rate of 4.213% for a three-year term ending July 1, 2007. ESOP debt was paid down by $23 million during the last three years when approximately 635,640 shares of company common stock were released from the Trust in order to fund the employer contribution to the company savings plan. Interest on the ESOP debt amounted to $4 million in 2005, $5 million in 2004 and $6 million in 2003. Dividends used for debt service amounted to $2 million in each of 2005, 2004 and 2003.

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.

Fair value hedges

During 2004, to balance the mix of fixed and floating-rate debt, Sempra Energy entered into interest-rate swaps that effectively exchanged the fixed rate on $300 million of its $500 million 7.95% notes maturing in 2010 for a floating rate. The swaps expire in 2010. During 2003, SoCalGas entered into an interest-rate swap that effectively exchanged the fixed rate on $150 million of its $250 million 4.375% first mortgage bonds maturing in 2011 for a floating rate. The swap expires in 2011. At December 31, 2005 and 2004, market value adjustments of $14 million and $10 million, respectively, were recorded as a decrease primarily in Sundry Assets and a corresponding decrease in Long-term Debt without affecting net income or other comprehensive income. There has been no hedge ineffectiveness on these swaps.

Cash flow hedges

In the third quarter of 2005, Sempra Energy Mexico entered into derivative transactions to hedge future interest payments associated with forecasted borrowings of $450 million for facilities related to Sempra LNG's Energía Costa Azul project. The swaps expire in 2027. 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. At December 31, 2005 pre-tax income arising from the ineffective portion of interest-rate cash flow hedges included $4 million recorded in Other Income, Net on the Statements of Consolidated Income. The effect of interest-rate cash flow hedges on other comprehensive income (loss) for the years ended December 31, 2005 and 2004 was $4 million and an immaterial amount, respectively. The balance in Accumulated Other Comprehensive Income (Loss) at December 31, 2005 related to interest-rate cash flow hedges was $4 million.

NOTE 6. FACILITIES UNDER JOINT OWNERSHIP

SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. The company's interests at December 31, 2005 were as follows:

(Dollars in millions)	SONGS	Southwest Powerlink
Percentage ownership	20%	91%
Utility plant in service	$ 39	$ 290
Accumulated depreciation and amortization	$ 2	$ 156
Construction work in progress	$ 21	$ 9

The company and the other owners each holds its interest as an undivided interest as tenants in common in the property. Each owner is responsible for financing its share of each project and participates in decisions concerning operations and capital expenditures.

The company's share of operating expenses is included in the Statements of Consolidated Income.

SONGS Decommissioning

Objectives, work scope and procedures for the dismantling and decontamination of the SONGS units must meet the requirements of the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency, the U.S. Department of the Navy (the land owner), the CPUC and other regulatory bodies.

The company's share of decommissioning costs for the SONGS units is estimated to be $339 million in 2005 dollars. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete Unit 1's decommissioning, which is currently in progress. Cost studies are updated every three years. The most recent update was submitted to the CPUC for its approval in 2005. Rate recovery of decommissioning costs is allowed until the time that the costs are fully recovered, and is subject to adjustment every three years based on the costs allowed by regulators. Collections are authorized to continue until 2013, at which time sufficient funds are expected to have been collected to fully decommission SONGS, but may be extended by CPUC approval until 2022, when the units' NRC operating licenses terminate and the decommissioning of Units 2 and 3 would be expected to begin.

The amounts collected in rates are invested in externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations that establish maximum amounts for investments in equity securities (50 percent of a qualified trust and 60 percent of a nonqualified trust), international equity securities (20 percent) and securities of electric utilities having ownership interests in nuclear power plants (10 percent). Not less than 50 percent of the equity portion of the trusts must be invested passively. The securities held by the trust are considered available for sale. These trusts are shown on the Consolidated Balance Sheets at market value with the offsetting credits recorded in Asset Retirement Obligations and Regulatory Liabilities Arising from Removal Obligations.

Unit 1 was permanently shut down in 1992, and physical decommissioning began in January 2000. Several structures, foundations and large components have been dismantled, removed and disposed of. Spent nuclear fuel has been removed from the Unit 1 Spent Fuel Pool and stored on-site in an independent spent fuel storage installation (ISFSI) licensed by the NRC. The remaining major work will include dismantling, removal and disposal of all remaining equipment and facilities (both nuclear and non-nuclear components), and decontamination of the site. These activities are expected to be completed in 2008. The ISFSI will be decommissioned after a permanent storage facility becomes available and the spent fuel is removed from the site by the U.S. Department of Energy. Unit 1's reactor vessel is expected to remain on site until Units 2 and 3 are decommissioned.

Trust investments include:

			December 31,
(Dollars in millions)	Maturity dates		2005		2004
Municipal bonds	2006 - 2034	$	54	$	45
U.S. government issues	2006 - 2038		222		209
Cash and other securities	2006 - 2033		35		55
Equity securities			327		303
Total		$	638	$	612

Net earnings of the trust were $30 million in 2005, $46 million in 2004 and $82 million in 2003. Proceeds from sales of securities (which are reinvested) were $223 million in 2005, $237 million in 2004 and $266 million in 2003, including net gains of $3 million, $12 million and $4 million in 2005, 2004 and 2003, respectively. The net unrealized holding gains included in Asset Retirement Obligations and Regulatory Liabilities Arising from Removal Obligations on the Consolidated Balance sheets were $193 million, $182 million and $159 million at December 31, 2005, 2004 and 2003, respectively.

Customer contribution amounts are determined by estimates of after-tax investment returns, decommissioning costs and decommissioning cost escalation rates. Lower actual investment returns or higher actual decommissioning costs result in an increase in future customer contributions.

Discussion regarding the impact of SFAS 143 is provided in Note 1. Additional information regarding SONGS is included in Notes 13 and 15.

NOTE 7. INCOME TAXES

Reconciliations of the U.S. statutory federal income tax rate to the effective income tax rate are as follows:

			Years ended December 31,
		2005			2004		2003
Statutory federal income tax rate		35		%	35	%	35	%
Utility depreciation		5			4		7
State income taxes - net of federal income tax benefit		3			4		8
Tax credits		(14		)	(14	)	(24	)
Foreign subsidiary income tax activity		(3		)	(3	)	(1	)
Resolution of Internal Revenue Service audits		(7		)	--		(12	)
Reduction of prior period state income tax accruals,
	net of federal income tax effect	(6		)	(3	)	--
Reduction of interest rate on prior period federal income
	tax liabilities, net of tax	--			(2	)	--
Utility repair allowance		(2		)	--		(1	)
Return to provision adjustments		(3		)	(1	)	(5	)
Other - net		(3		)	(2	)	--
Effective income tax rate		5		%	18	%	7	%

The geographic components of income from continuing operations before income taxes and equity in earnings of certain unconsolidated subsidiaries are as follows:

			Years ended December 31,
(Dollars in millions)		2005			2004		2003
Domestic	$	748		$	796	$	551
Foreign		168			255		129
Total	$	916		$	1,051	$	680

The components of income tax expense are as follows:

					Years ended December 31,
(Dollars in millions)				2005				2004			2003
Current:
	Federal		$	306			$	120		$	80
	State			8				21			74
	Foreign			11				39			11
		Total		325				180			165
Deferred:
	Federal			(195		)		17			(126	)
	State			(76		)		(24	)		(4	)
	Foreign			(6		)		26			18
		Total		(277		)		19			(112	)
Deferred investment tax credits				(6		)		(6	)		(6	)
		Total income tax expense	$	42			$	193		$	47

Accumulated deferred income taxes at December 31 relate to the following:

(Dollars in millions)						2005		2004
Deferred tax liabilities:
	Differences in financial and tax bases of depreciable and
		amortizable assets			$	900	$	861
	Balancing accounts and regulatory assets					192		124
	Unrealized revenue					39		79
	Partnership income					59		56
	Loss on reacquired debt					29		38
	Property taxes					23		25
	Equity Units					5		21
	Other					2		11
			Total deferred tax liabilities			1,249		1,215
Deferred tax assets:
	General business tax credit carryforward					236		193
	Credits from alternative minimum tax					143		111
	Investment tax credits					50		55
	Net operating losses of separate state and foreign entities					86		104
	Compensation-related items					171		173
	Postretirement benefits					44		51
	Other deferred liabilities					42		29
	State income taxes					39		48
	Bad debt allowance					8		18
	Other accruals not yet deductible					291		35
	Other					44		32
			Total deferred tax assets			1,154		849
				Net deferred income tax liability before valuation allowance		95		366
Valuation allowance						18		39
Net deferred income tax liability					$	113	$	405

The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows:

(Dollars in millions)		2005			2004
Current asset	$	(132	)	$	(15	)
Noncurrent liability		245			420
Total	$	113		$	405

In connection with its affordable-housing investments, the company has $236 million of unused general business tax credits in varying amounts dating back to 1999. The ability to offset these credits against future taxable income will expire between 2019 and 2025. The company expects to utilize the credits prior to expiration. In addition, the company has $143 million of alternative minimum tax credits with no expiration date. All of these credits have been included in the calculation of income tax expense in the year they arose.

Foreign subsidiaries have $348 million in unused net operating losses available to reduce future income taxes, primarily in Mexico, Canada and the United Kingdom. Significant amounts of these losses become unavailable to reduce future incomes taxes beginning in 2009. Financial statement benefits have been recorded on all but $37 million of these losses, primarily by offsetting them against deferred tax liabilities with the same expiration pattern and country of jurisdiction. No benefits have been recorded on $37 million of the losses because they have been incurred in jurisdictions where utilization is sufficiently in doubt.

The company has not provided for U.S. income taxes on foreign subsidiaries' undistributed earnings ($767 million at December 31, 2005), since they are expected to be reinvested indefinitely outside the U.S. It is not possible to predict the amount of U.S. income taxes that might be payable if these earnings were eventually repatriated.

The company believes it has adequately provided for income tax issues not yet resolved with federal, state and foreign tax authorities. At December 31, 2005, $51 million was accrued for such matters. Although not probable, the most adverse resolution of these issues could result in additional charges to earnings in future periods. Based upon a consideration of all relevant facts and circumstances, the company does not believe the ultimate resolution of tax issues for all open tax periods will have a materially adverse effect upon its results of operations or financial condition.

The new American Jobs Creation Act enabled companies to repatriate monies earned outside the U.S. at an income tax cost of only 15 percent of the normal rate, if the repatriation occurred by the end of 2005. The company decided not to repatriate any foreign earnings pursuant to that act's repatriation provision.

Section 29 Income Tax Credits

On July 1, 2004, Sempra Financial sold its investment in an enterprise that earns Section 29 income tax credits. That investment comprised one-third of Sempra Energy's Section 29 participation and was sold because the company's alternative minimum tax position defers utilization of the credits in the determination of income taxes currently payable. The transaction has been accounted for under the cost-recovery method, whereby future proceeds in excess of the carrying value of the investment will be recorded as income as received. As a result of this sale, Sempra Financial will not be receiving Section 29 income tax credits in the future. Sempra Commodities continues its operations related to Section 29 income tax credits.

The Internal Revenue Service (IRS) has conducted various examinations of the partnerships associated with the Section 29 income tax credits, covering various years as recent as 2000, depending on the partnership. It has reported no change in the credits. From acquisition of the facilities in 1998, the company has generated Section 29 income tax credits of $434 million through December 31, 2005, of which $85 million were recorded in 2005.

In the next two years, if the annual average wellhead price per barrel of oil reaches a certain price, a partial or complete phase-out of Section 29 credits will begin. Those prices are $53.21 for 2006 and $54.27 for 2007.

Pacific Enterprises' Quasi-Reorganization

Effective December 31, 1992, PE effected a quasi-reorganization for financial reporting purposes. The reorganization resulted in a restatement of the company's assets and liabilities to their estimated fair value at December 31, 1992 and the elimination of PE's retained earnings deficit. Since the reorganization was for financial purposes and not a taxable transaction, the company established deferred taxes relative to the book and tax bases differences.

During 2004, the company completed an extensive analysis of PE's deferred tax accounts. The analysis resulted in a $72 million reduction of the deferred tax liabilities and an offsetting credit to equity. The credit was recorded to equity because the balances related to tax effects of transactions prior to the quasi-reorganization. In 2004, the company also concluded its outstanding IRS examinations and appeals related to PE and its subsidiaries. As of December 31, 2005, the company's balance sheet includes a net deferred tax asset of $11 million related to remaining reserves arising from the quasi-reorganization.

NOTE 8. EMPLOYEE BENEFIT PLANS

The information presented below covers the plans of the company and its principal subsidiaries.

The company has funded and unfunded noncontributory defined benefit plans that together cover substantially all of its employees. The plans provide defined benefits based on years of service and either final average or career salary.

The company also has other postretirement benefit plans covering substantially all of its employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory, with participants' contributions adjusted annually. Other postretirement benefits include medical benefits for retirees' spouses.

Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. These assumptions include discount rates, expected return on plan assets, rates of compensation increase, health care cost trend rates, mortality rates, and other factors. These assumptions are reviewed on an annual basis prior to the beginning of each year and updated when appropriate. The company considers current market conditions, including interest rates, in making these assumptions.

The company maintains dedicated assets in support of its Supplemental Executive Retirement Plan.

SoCalGas' pension plan was amended effective January 1, 2005, to increase the pension formula for service credit in excess of 30 years as well as service credit in excess of 35 years resulting in an increase of the pension benefit obligation of $3 million.

Effective January 1, 2006 the other postretirement benefit plans for non-represented employees at SDG&E and SoCalGas were amended to integrate the benefits plan design across the company, resulting in a net $6 million decrease in the benefit obligation as of December 31, 2005.

December 31 is the measurement date for the pension and other postretirement benefit plans. The following table provides a reconciliation of the changes in the plans' projected benefit obligations during the latest two years, and the fair value of assets and a statement of the funded status as of the latest two year ends:

							Other Postretirement Benefits
	Pension Benefits
(Dollars in millions)		2005			2004			2005			2004
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1	$	2,694		$	2,578		$	922		$	954
Service cost		62			49			24			21
Interest cost		153			154			48			51
Plan amendments		3			--			(6	)		--
Actuarial loss (gain)		117			132			(74	)		(64	)
Joint venture accruals (Topaz Power)		--			--			1			--
Benefit payments		(186	)		(219	)		(46	)		(40	)
Net obligation at December 31		2,843			2,694			869			922
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1		2,340			2,263			585			519
Actual return on plan assets		186			269			39			56
Employer contributions		24			27			45			50
Benefit payments		(186	)		(219	)		(46	)		(40	)
Fair value of plan assets at December 31		2,364			2,340			623			585
Benefit obligation, net of plan assets at December 31		(479	)		(354	)		(246	)		(337	)
Unrecognized net actuarial loss		344			278			141			221
Unrecognized prior service cost		68			74			(17	)		(13	)
Net recorded liability at December 31	$	(67	)	$	(2	)	$	(122	)	$	(129	)

The assets and liabilities of the pension and other postretirement benefit plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in gains and losses. Investment gains and losses are deferred and recognized in pension and postretirement benefit costs over a period of years. The company uses the asset "smoothing" method for nearly 80 percent of the assets held for its pension and other postretirement plans and recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used to determine the expected return-on-assets component of net periodic cost. If, as of the beginning of a year, unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10-percent corridor accounting methods help mitigate volatility of net periodic costs from year to year.

The net liability is recorded on the Consolidated Balance Sheets as follows:

								Other Postretirement Benefits
		Pension Benefits
(Dollars in millions)			2005			2004			2005			2004
Prepaid benefit cost		$	80		$	147		$	--		$	--
Accrued benefit cost			(148	)		(149	)		(121	)		(129	)
Additional minimum liability			(165	)		(131	)		--			--
Intangible asset			5			7			--			--
Regulatory asset			99			62			--			--
Accumulated other comprehensive
	income (pre-tax)		62			62			--			--
Net recorded liability		$	(67	)	$	(2	)	$	(121	)	$	(129	)

The accumulated benefit obligations for defined benefit pension plans were $2.6 billion and $2.5 billion at December 31, 2005 and 2004, respectively. The following table provides information concerning pension plans with benefit obligations in excess of plan assets as of December 31.

	Projected Benefit Obligation Exceeds the Fair Value of Plan Assets				Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets
(Dollars in millions)		2005		2004		2005		2004
Projected benefit obligation	$	2,490	$	2,290	$	757	$	694
Accumulated benefit obligation	$	2,258	$	2,076	$	752	$	692
Fair value of plan assets	$	2,189	$	2,085	$	616	$	569

The following table provides the components of net periodic benefit costs (income) for the years ended December 31:

											Other Postretirement Benefits
		Pension Benefits
(Dollars in millions)			2005			2004			2003			2005			2004			2003
Service cost		$	62		$	49		$	52		$	24		$	21		$	19
Interest cost			153			154			152			48			51			55
Expected return on assets			(153	)		(154	)		(161	)		(39	)		(36	)		(35	)
Amortization of:
	Transition obligation		--			--			1			--			--			9
	Prior service cost		10			9			9			(2	)		(1	)		(1	)
	Actuarial loss		17			12			9			7			10			10
Regulatory adjustment			(36	)		(116	)		(14	)		9			2			(4	)
Transfer of retirees			30			--			--			(10	)		--			--
Total net periodic benefit cost (income)		$	83		$	(46	)	$	48		$	37		$	47		$	53

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was enacted in December of 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a tax-exempt federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that actuarially is at least equivalent to Medicare Part D. The company and its actuarial advisors determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D, and, accordingly, the company expects to be entitled to a tax-exempt subsidy that reduces the company's accumulated postretirement benefit obligation under the plan at January 1, 2005 by $78 million and reduces the net postretirement benefit cost for 2005 by $9 million.

The significant assumptions related to the company's pension and other postretirement benefit plans are as follows:

					Other Postretirement Benefits
		Pension Benefits
			2005	2004		2005	2004
WEIGHTED-AVERAGE ASSUMPTIONS USED
	TO DETERMINE BENEFIT OBLIGATION
	AS OF DECEMBER 31:
Discount rate			5.50%	5.66%		5.60%	5.66%
Rate of compensation increase			4.50%	4.50%		4.50%	4.50%

WEIGHTED-AVERAGE ASSUMPTIONS USED
	TO DETERMINE NET PERIODIC BENEFIT
	COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate		5.66%	6.00%	5.66%	6.00%
Expected return on plan assets		7.50%	7.50%	6.83%	7.32%
Rate of compensation increase		4.50%	4.50%	4.50%	4.50%

The company utilizes a bond-pricing model that is tailored to the attributes of its pension and other postretirement plans to determine the appropriate discount rate to use for its benefit plans.

The expected long-term rate of return on plan assets is derived from historical returns for broad asset classes consistent with expectations from a variety of sources, including pension consultants and investment advisors.

		2005			2004
ASSUMED HEALTH CARE COST
	TREND RATES AT DECEMBER 31:
Health-care cost trend rate		9.78	%	*	19.00	%	*
Rate to which the cost trend rate is assumed to
	decline (the ultimate trend)	5.50	%		5.50	%
Year that the rate reaches the ultimate trend		2008			2008

* This is the weighted average of the increases for the company's health plans. The rate for these plans ranged from 8.50% to 10% in 2005 and from 10% to 20% in 2004.

Assumed health-care cost trend rates have a significant effect on the amounts reported for the health-care plan costs. A one-percent change in assumed health-care cost trend rates would have the following effects:

(Dollars in millions)		1% Increase		1% Decrease
Effect on total of service and interest cost components of net
	periodic postretirement health-care benefit cost	$	13	$	(10	)
Effect on the health-care component of the accumulated other
	postretirement benefit obligation	$	117	$	(94	)

Pension Plan Investment Strategy

The asset allocation for the company's pension trust (which includes other postretirement benefit plans, except for those of the California Utilities separately described below) at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:

		Target Allocation		Percentage of Plan Assets at December 31,
Asset Category		2006		2005		2004
U.S. Equity		45	%	44	%	45	%
Foreign Equity		25		27		32
Fixed Income		30		29		23
	Total	100	%	100	%	100	%

The company's investment strategy is to stay fully invested at all times and maintain its strategic asset allocation, keeping the investment structure relatively simple. The equity portfolio is balanced to maintain risk characteristics similar to the Morgan Stanley Capital International (MSCI) 2500 index with respect to industry and sector exposures and market capitalization. The foreign equity portfolios are managed to track the MSCI Europe, Pacific Rim and Emerging Markets indexes. Bond portfolios are managed with respect to the Lehman Aggregate Bond Index and Lehman Long Government Credit Bond Index. The plan does not invest in securities of the company.

Investment Strategy for SoCalGas' Other Postretirement Benefit Plans

The asset allocation for SoCalGas' other postretirement benefit plans at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:

		Target Allocation		Percentage of Plan Assets at December 31,
Asset Category		2006		2005		2004
U.S. Equity		70	%	74	%	73	%
Fixed Income		30		26		27
	Total	100	%	100	%	100	%

SoCalGas' other postretirement benefit plans that are not included in the pension trust (shown above) are funded by cash contributions from SoCalGas and the retirees. The asset allocation is designed to match the long-term growth of the plan's liability. These plans are managed using index funds.

Investment Strategy for SDG&E's Postretirement Health Plans

The asset allocation for SDG&E's postretirement health plans at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:

		Target Allocation		Percentage of Plan Assets at December 31,
Asset Category		2006		2005		2004
U.S. Equity		25	%	23	%	25	%
Foreign Equity		5		6		6
Fixed Income		70		71		69
	Total	100	%	100	%	100	%

SDG&E's postretirement health plans that are not included in the pension trust (shown above) pay premiums to health maintenance organization and point-of-service plans from company and participant contributions. SDG&E's investment strategy is to match the long-term growth rate of the liability primarily through the use of tax-exempt California municipal bonds.

Future Payments

The company expects to contribute $37 million to its pension plans and $39 million to the other postretirement benefit plans in 2006.

The following table reflects the total benefits expected to be paid for the next 10 years to current employees and retirees from the plans or from the company's assets, including both the company's share of the benefit cost and, where applicable, the participants' share of the costs, which is funded by participant contributions to the plans.

			Other Postretirement Benefits
(Dollars in millions)	Pension Benefits
2006	$	193	$	42
2007	$	201	$	45
2008	$	214	$	48
2009	$	224	$	50
2010	$	233	$	53
2011-2015	$	1,297	$	300

The expected future Medicare Part D subsidy payments are as follows:

(Dollars in millions)
2006	$	2
2007	$	3
2008	$	3
2009	$	3
2010	$	4
2011-2015	$	23

Savings Plans

The company offers trusteed savings plans to all eligible employees. Eligibility to participate in the plans is immediate for salary deferrals. Subject to plan provisions, employees may contribute from one percent to 25 percent of their regular earnings, beginning with the start of employment. After one year of each employee's completed service, the company begins to make matching contributions. Employer contribution amounts and methodology vary by plan, but generally the contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments.

Employer contributions are initially invested in company common stock but may be transferred by the employee into other investments. Employee contributions are invested in company stock, mutual funds, institutional trusts or guaranteed investment contracts (the same investments to which employees may now direct the employer contributions) as elected by the employee. The plans of certain non-wholly owned subsidiaries prohibit investments in stock of the company and employer matching contributions are invested to mirror the employee-directed contributions. Employer contributions for the Sempra Energy and SoCalGas plans are partially funded by the Employee Stock Ownership Plan referred to below. Company contributions to the savings plans were $29 million in 2005, $25 million in 2004 and $22 million in 2003. The market value of company stock held by the savings plans was $824 million and $801 million at December 31, 2005 and 2004, respectively.

Sempra Commodities also operates defined contribution plans outside of the United States. The contributions made by the company to such plans were $4 million in 2005 and $3 million in each of 2004 and 2003.

Employee Stock Ownership Plan

All contributions to the ESOP Trust (described in Note 5) are made by the company; there are no contributions made by the participants. As the company makes contributions, the ESOP debt service is paid and shares are released in proportion to the total expected debt service. Compensation expense is charged and equity is credited for the market value of the shares released. Dividends on unallocated shares are used to pay debt service and are applied against the liability. The Trust held 1.9 million shares and 2.1 million shares, respectively, of Sempra Energy common stock, with fair values of $85.9 million and $78.7 million, at December 31, 2005 and 2004, respectively.

NOTE 9. STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of the company. The plans permit a wide variety of stock-based awards, including nonqualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents.

In 2005, 2004 and 2003, respectively, 1,170,800, 1,223,000 and 1,359,500 shares of restricted company stock were awarded to key employees. Compensation expense for the issuance of the restricted stock was $58 million in 2005, $37 million in 2004 and $16 million in 2003. The corresponding weighted average market values per share at the times of grant were $36.49, $30.57 and $24.42, respectively. Subject to earlier forfeitures or accelerated vesting upon termination of employment, a change in control or certain other events, the awards are scheduled to vest at the end of four years if specified goals are satisfied. Holders of restricted stock have full voting rights. They also have full dividend rights, except for senior officers, whose dividends are reinvested to purchase additional shares that become subject to the same performance-based vesting conditions as the restricted stock to which they relate.

In 2005, 2004 and 2003, the company granted to directors, officers and key employees options to acquire 946,000, 1,389,000 and 1,848,000 shares of stock, respectively. The option prices were equal to the market price of common stock at the dates of grant. The officers' and key employees' options vest over four-year periods (subject to earlier forfeitures or accelerated vesting upon termination of employment, a change in control or certain other events) and expire 10 years from the dates of grant, subject to earlier expiration upon termination of employment. Compensation expense for stock option grants (all associated with outstanding options with dividend equivalents that were issued before 2002) and similar awards was $3 million, $4 million and $6 million in 2005, 2004 and 2003, respectively.

As of December 31, 2005, 15,854,574 shares were authorized and available for future grants of restricted stock and/or stock options. In addition, on January 1 of each year, additional shares equal to 1.5 percent of the outstanding shares of Sempra Energy common stock become available for grant.

In 1995, SFAS 123 was issued. It encouraged a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS 123, the company adopted only its disclosure requirements and continued to account for stock-based compensation in accordance with the provisions of APBO 25. The issuance of SFAS 123R will require the company to begin accelerated recognition of stock-based compensation expense for participants who are eligible for retirement-related vesting, beginning in 2006. Discussion of SFAS 123R (a revision of SFAS 123) is provided in Note 1.

STOCK OPTION ACTIVITY

				Weighted
		Shares		Average	Options
		under		Exercise	Exercisable
		Option		Price	at December 31
OPTIONS WITH DIVIDEND EQUIVALENTS
December 31, 2002		3,079,865		$ 22.48	2,777,590
	Exercised	(876,391	)	$ 20.81
	Cancelled	(17,649	)	$ 24.72
	Transferred (see table below)	(1,536,775	)	$ 23.24
December 31, 2003		649,050		$ 22.89	649,050
	Exercised	(286,539	)	$ 21.04
December 31, 2004		362,511		$ 22.44	362,511
	Exercised	(122,594	)	$ 21.62
December 31, 2005		239,917		$ 22.86	239,917
				Weighted
		Shares		Average	Options
		under		Exercise	Exercisable
		Option		Price	at December 31
OPTIONS WITHOUT DIVIDEND EQUIVALENTS
December 31, 2002		13,011,187		$ 22.18	5,287,437
	Granted	1,848,000		$ 24.44
	Exercised	(1,050,199	)	$ 20.16
	Cancelled	(111,906	)	$ 23.83
	Transferred (see table above)	1,536,775		$ 23.24
December 31, 2003		15,233,857		$ 22.69	8,610,732
	Granted	1,389,000		$ 30.33
	Exercised	(3,837,541	)	$ 20.96
	Cancelled	(73,110	)	$ 25.79
December 31, 2004		12,712,206		$ 24.06	7,771,556
	Granted	946,000		$ 37.01
	Exercised	(3,900,573	)	$ 22.29
	Cancelled	(101,839	)	$ 28.00
December 31, 2005		9,655,794		$ 26.00	6,205,644

Additional information on options outstanding at December 31, 2005, is as follows:

		Weighted	Weighted
	Number	Average	Average
	of	Remaining	Exercise
Range of Exercise Prices	Shares	Life	Price
Outstanding Options
$ 17.00 - $ 23.45	2,629,506	4.48	$ 21.65
$ 24.27 - $ 29.96	5,062,130	5.61	$ 24.97
$ 30.20 - $ 44.64	2,204,075	8.47	$ 33.21
	9,895,711		$ 25.92
Exercisable Options
$ 17.00 - $ 23.45	2,629,506		$ 21.65
$ 24.27 - $ 29.96	3,480,955		$ 25.14
$ 30.20 - $ 44.64	335,100		$ 30.77
	6,445,561		$ 24.01

The grant-date fair value of each option grant (including dividend equivalents where applicable) was estimated using a modified Black-Scholes option-pricing model. Weighted average grant-date fair values for options granted in 2005, 2004 and 2003 were $8.28, $6.32 and $4.31, respectively.

The assumptions that were used to determine these grant-date fair values were as follows:

	2005	2004	2003
Stock price volatility	25%	25%	25%
Risk-free rate of return	3.9%	3.7%	3.4%
Annual dividend yield	2.8%	3.3%	4.1%
Expected life	6 Years	6 Years	6 Years

NOTE 10. FINANCIAL INSTRUMENTS

Fair Value Hedges

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 swaps are discussed in Note 5.

Commodity Fair Value Hedges

For commodity derivative instruments designated as fair value hedges, the company recognized net unrealized pre-tax gains of $103 million, $68 million and $16 million for 2005, 2004 and 2003, respectively, which represents portions of gains on hedging instruments determined to be ineffective. These pre-tax gains include $98 million in 2005, $74 million in 2004 and $16 million in 2003, which represent the time value of money which is excluded for hedge assessment purposes. The ineffectiveness gain related to hedges of commodity inventory is included in Operating Revenues from Sempra Global and Parent in the Statements of Consolidated Income.

Cash Flow Hedges

Interest-Rate Swaps

The company's interest-rate swaps to hedge cash flows are discussed in Note 5.

Other Cash Flow Hedges

For other derivative instruments designated as cash flow hedges, the company recognized a net unrealized pre-tax gain of $1 million in 2005, a pre-tax loss of $3 million in 2004 and a pre-tax loss of $1 million in 2003, which represents portions of gains or losses on hedging instruments determined to be ineffective. The ineffectiveness pre-tax gain and loss related to potential phase-out of Section 29 income tax credits, as well as hedges of natural gas purchases and sales related to transportation and storage capacity arrangements. The gain and losses are included in Operating Revenues from Sempra Global and Parent in the Statements of Consolidated Income.

The balances in Accumulated Other Comprehensive Income (Loss) at December 31, 2005 and 2004 related to all cash flow hedges were losses of $57 million and $39 million, respectively. The company expects that $12 million, which is net of income tax, that is currently recorded in Accumulated Other Comprehensive Income related to these cash flow hedges will be reclassified into earnings in 2006 as the hedged items affect earnings.

Sempra Commodities

The carrying values of trading assets and trading liabilities, primarily at Sempra Commodities, approximate the following:

			December 31,
(Dollars in millions)			2005		2004
TRADING ASSETS
Trading-related receivables and deposits, net:
	Due from trading counterparties		$	3,300	$	2,371
	Due from commodity clearing organizations and clearing brokers			70		235
				3,370		2,606
Derivative trading instruments:
	Unrealized gains on swap and forwards			2,554		1,607
	OTC commodity options purchased			1,948		732
				4,502		2,339
Commodities owned				2,498		1,547
Total trading assets			$	10,370	$	6,492
TRADING LIABILITIES
Trading-related payables			$	4,127	$	3,182
Derivative trading instruments sold, not yet purchased:
		Unrealized losses on swaps and forwards		2,560		1,232
		OTC commodity options written		686		252
				3,246		1,484
Commodities and securities sold with agreement to repurchase				634		513
Total trading liabilities			$	8,007	$	5,179

Based on quarterly measurements, the average fair values during 2005 for trading assets and liabilities approximate $8.8 billion and $7.2 billion, respectively. For 2004, the amounts were $5.7 billion and $4.6 billion, respectively.

Sempra Commodities' credit risk from physical and financial instruments as of December 31, 2005 is represented by their positive fair value after consideration of collateral. Options written do not expose Sempra Commodities to credit risk. Exchange traded futures and options are not deemed to have significant credit exposure since the exchanges guarantee that every contract will be properly settled on a daily basis. Credit risk is also associated with its retail customers.

The following table summarizes the counterparty credit quality and exposure for Sempra Commodities at December 31, 2005 and 2004, expressed in terms of net replacement value. These exposures are net of collateral in the form of customer margin and/or letters of credit of $2.3 billion and $1.1 billion at December 31, 2005 and 2004, respectively.

			December 31,
(Dollars in millions)			2005		2004
Counterparty credit quality*
	Commodity exchanges		$	70		$	235
	AAA			6			7
	AA			440			259
	A			1,072			562
	BBB			1,142			680
	Below investment grade and not rated			815			532
		Total	$	3,545		$	2,275

* As determined by rating agencies or internal models intended to approximate rating-agency determinations.

Sempra Utilities

At the California Utilities, 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 customers. The California Utilities record transactions for natural gas and electric energy contracts in Cost of Natural Gas and in Cost of Electric Fuel and Purchased Power, respectively, in the Statements of Consolidated Income. Unrealized gain and losses related to these derivatives have offsetting regulatory assets and liabilities on the Consolidated Balance Sheets to the extent derivative gains and losses will be recoverable from or payable to customers in future rates.

Fair Value of Financial Instruments

The fair values of certain of the company's financial instruments (cash, temporary investments, notes receivable, dividends payable, short-term debt and customer deposits) approximate their carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at December 31:

	2005					2004
		Carrying Amount			Fair Value		Carrying Amount			Fair Value
(Dollars in millions)
Investments in limited partnerships	$	145		$	208	$	194		$	262
Total long-term debt	$	4,930		$	4,989	$	4,594		$	4,923
Due to unconsolidated affiliates	$	160		$	171	$	362	*	$	383
Preferred stock of subsidiaries	$	198	**	$	181	$	200	**	$	186

* Includes $200 million of mandatorily redeemable trust preferred securities.

** $19 million and $21 million in 2005 and 2004, respectively, of mandatorily redeemable preferred stock of subsidiaries is included in Deferred Credits and Other Liabilities and in Other Current Liabilities on the Consolidated Balance Sheets.

The fair values of investments in limited partnerships were based on the present value of estimated future cash flows, discounted at rates available for similar investments. The fair values of debt incurred to acquire limited partnerships were estimated based on the present value of the future cash flows, discounted at rates available for similar notes with comparable maturities. The fair values of the other long-term debt, preferred stock and mandatorily redeemable trust preferred securities are based on their quoted market prices or quoted market prices for similar securities.

NOTE 11. PREFERRED STOCK OF SUBSIDIARIES

							Call/
					Redemption			December 31,
							Price	2005		2004
Not subject to mandatory redemption:									(in millions)
	Pacific Enterprises:
		Without par value, authorized 15,000,000 shares:
			$4.75 Dividend, 200,000 shares outstanding			$	100.00	$	20	$	20
			$4.50 Dividend, 300,000 shares outstanding			$	100.00		30		30
			$4.40 Dividend, 100,000 shares outstanding			$	101.50		10		10
			$4.36 Dividend, 200,000 shares outstanding			$	101.00		20		20
			$4.75 Dividend, 253 shares outstanding			$	101.00		--		--
				Total					80		80
	SoCalGas:
		$25 par value, authorized 1,000,000 shares:
			6% Series, 28,041 shares outstanding						1		1
			6% Series A, 783,032 shares outstanding						19		19
		Without par value, authorized 10,000,000 shares							--		--
				Total					20		20
	SDG&E:
		$20 par value, authorized 1,375,000 shares:
			5% Series, 375,000 shares outstanding			$	24.00		8		8
			4.5% Series, 300,000 shares outstanding			$	21.20		6		6
			4.4% Series, 325,000 shares outstanding			$	21.00		7		7
			4.6% Series, 373,770 shares outstanding			$	20.25		7		7
		Without par value:
			$1.70 Series, 1,400,000 shares outstanding			$	25.85		35		35
			$1.82 Series, 640,000 shares outstanding			$	26.00		16		16
				Total					79		79
				Total not subject to mandatory redemption					179		179
Subject to mandatory redemption:
	SDG&E:
		Without par value: $1.7625 Series, 750,000 and 850,000
		shares outstanding at December 31, 2005
		and December 31, 2004, respectively				$	25.00		19	*	21	*
				Total preferred stock				$	198	$	200

* At December 31, 2005 and 2004, $16 million and $19 million, respectively, were included in Deferred Credits and Other Liabilities and $3 million and $2 million, respectively, were included in Other Current Liabilities on the Consolidated Balance Sheets. Since December 31, 2002, the $6 million of activity related to subsidiaries' preferred stock has all applied to mandatorily redeemable preferred stock.

PE preferred stock is callable at the applicable redemption price of each series, plus any unpaid dividends. The preferred stock is subject to redemption at PE's option at any time upon at least 30 days' notice, at the applicable redemption price for each series plus any unpaid dividends. All series have one vote per share, cumulative preferences as to dividends, and a liquidation value of $100 per share plus any unpaid dividends.

None of SoCalGas' preferred stock is callable. All series have one vote per share, cumulative preferences as to dividends and liquidation values of $25 per share plus any unpaid dividends.

All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par. The no-par-value preferred stock is nonvoting and has a liquidation value of $25 per share plus any unpaid dividends. SDG&E is authorized to issue 10,000,000 shares of no-par-value preferred stock (both subject to and not subject to mandatory redemption). All series are callable. The $1.7625 Series has a sinking fund requirement to redeem 50,000 shares at $25 per share in each of 2006 and 2007; all remaining shares must be redeemed in 2008. On each of January 15, 2005 and January 15, 2006, SDG&E redeemed 100,000 shares.

NOTE 12. SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE (EPS)

The following table provides the per share computations for income from continuing operations for the years ended December 31,:

		2005					2004
		Income (millions) (numerator)		Shares (thousands) (denominator)	Per Share Amounts		Income (millions) (numerator)		Shares (thousands) (denominator)	Per Share Amounts
Basic EPS:
Income from continuing operations		$	929	245,906	$	3.78	$	920	228,271	$	4.03
Effect of dilutive
securities:
	Stock options and	--		4,308			--		3,595
	restricted stock awards
	Equity Units	--		1,874			--		1,986
Diluted EPS:
Income from continuing operations		$	929	252,088	$	3.69	$	920	233,852	$	3.93

The only difference between basic and diluted earnings per share in 2003 was the effect of common stock options, which was equivalent to an additional 2,742,000 shares. The dilution from common stock options is based on the treasury stock method, whereby the proceeds from the exercise price are assumed to be used to repurchase shares on the open market at the average market price for the year. The calculation excludes options covering an average of 0.1 million shares for 2003 for which the exercise price was greater than the average market price for common stock during the year. In 2005 and 2004, there were no such options.

The dilution from unvested restricted stock awards is based on the treasury stock method, whereby assumed proceeds equivalent to the unearned compensation related to the awards are assumed to be used to repurchase shares on the open market at the average market price for the year. Restricted awards that did not affect the calculation, because their grant price was greater than the average market price for common stock during the year, represented 1.3 million shares in 2003 and immaterial amounts thereafter.

The company is authorized to issue 750,000,000 shares of no-par-value common stock and 50,000,000 shares of preferred stock.

Excluding shares held by the ESOP, common stock activity consisted of the following:

		2005		2004		2003
Common shares outstanding, January 1		234,175,980		226,598,619		204,911,572
	Public issuance	19,655,999		--		16,500,000
	Savings plan issuance	376,418		1,638,581		1,436,526
	Shares released from ESOP	228,407		236,620		170,613
	Stock options exercised	4,023,167		4,124,080		1,926,590
	Restricted stock issuances	1,170,800		1,223,000		1,359,500
	Common stock investment plan*	127,983		611,259		728,241
	Shares repurchased	(2,453,346	)	(181,819	)	(262,286	)
	Shares forfeited and other	(117,465	)	(74,360	)	(172,137	)
Common shares outstanding, December 31		257,187,943		234,175,980		226,598,619

* Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.

The payment of future dividends and the amount thereof are within the discretion of the company's board of directors. The CPUC's regulation of the California Utilities' capital structure limits the amounts that are available for dividends and loans to the company from the California Utilities. At December 31, 2005, SoCalGas could have provided a total of $118 million to Sempra Energy, through dividends and loans, and no amounts were available from SDG&E.

Equity Units

In 2002, the company issued $600 million of Equity Units. The units included $600 million of the company's 5.60% senior notes due May 17, 2007 and a contract to purchase shares of the company stock on May 17, 2005 at a price per share determined by the then-prevailing market price. In 2005, 19,655,999 shares of common stock were issued in settlement of the contracts to purchase the company's common stock for $600 million.

Company Repurchases of Common Stock

On April 5, 2005, the board of directors authorized the expenditure of up to $250 million for the purchase of shares of common stock, at any time and from time to time, in the open market, in negotiated transactions and otherwise, of which $88.2 million has been expended through December 31, 2005. No such purchases have been made since June 30, 2005.

Common Stock Offering

On October 14, 2003, Sempra Energy completed a common stock offering of 16.5 million shares priced at $28 per common share, resulting in net proceeds of $448 million. The proceeds were used primarily to pay off short-term debt.

NOTE 13. ELECTRIC INDUSTRY REGULATION

Background

One legislative response to the 2000-2001 power crisis resulted in the purchase by the California DWR of a substantial portion of the power requirements of California's electricity users. In 2001, the DWR entered into long-term contracts with suppliers, including Sempra Generation, to provide power for the utility procurement customers of each of the California investor-owned utilities (IOUs). The CPUC has established the allocation of the power and its administrative responsibility, including collection of power contract costs from utility customers, among the IOUs. Beginning on January 1, 2003, the IOUs resumed responsibility for electric commodity procurement above their allocated share of the DWR's long-term contracts.

Department of Water Resources

The DWR operating agreement with SDG&E, approved by the CPUC, provides that SDG&E is acting as a limited agent on behalf of the DWR in undertaking energy sales and natural gas procurement functions under the DWR contracts allocated to SDG&E's customers. Legal and financial responsibility associated with these activities continues to reside with the DWR. Therefore, commodity costs associated with long-term contracts allocated to SDG&E from the DWR (and the revenues to recover those costs) are not included in the Statements of Consolidated Income.

In October 2003, the CPUC initiated a proceeding to consider a permanent methodology for allocating the DWR's revenue requirement beginning in 2004 through the remaining life of the DWR contracts (2013). On June 30, 2005, the CPUC changed its prior decision and assigned SDG&E customers $422 million of the costs (instead of the $790 million pursuant to the prior decision). Such allocation does not affect SDG&E's net income, but does affect its customers' commodity rates. In August 2005, Southern California Edison (Edison), The Utility Reform Network and the California Large Energy Consumers Association (collectively the Parties) filed a Petition for Modification, not disputing the allocation of the DWR decision, but rather the schedule for reallocation. On December 1, 2005, the CPUC approved a decision that denied the Parties' petition to modify.

In December 2005, the CPUC approved a draft decision reallocating one of the state's DWR power contracts (Williams Energy "Power D") from SDG&E to Edison. The decision was modified to make the reallocation effective January 1, 2007, allowing SDG&E an additional year to plan for and acquire the necessary replacement resources. In the same decision, the CPUC rejected Edison's request to reallocate administration of Sempra Generation's DWR contract to SDG&E.

Power Procurement and Resource Planning

In 2001, the CPUC directed the IOUs to resume electric commodity procurement to cover their net short energy requirements by January 1, 2003 and also implemented legislation regarding procurement and renewables portfolio standards. In addition, the CPUC established a process for review and approval of the utilities' long-term resource and procurement plans, which is intended to identify forecasted needs for generation and transmission resources within a utility's service territory to support transmission grid reliability and to serve customers.

In June 2004, the CPUC approved a request by SDG&E to enter into new electric resource contracts to meet its short-term and long-term grid reliability needs, including the ten-year 573-MW Otay Mesa Power Purchase Agreement (OMPPA) with Calpine Corp. (Calpine). The OMPPA was to begin January 1, 2008. In June 2005, the CPUC granted limited rehearing of its approval of the OMPPA and on February 16, 2005, the CPUC re-affirmed its approval of the OMPPA. However, several conditions precedent required by the OMPPA have not yet been satisfied. In lieu of the OMPPA, SDG&E and Calpine have entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of the Otay Mesa power plant to SDG&E. Any final, definitive agreement would require the approval of the CPUC and the bankruptcy court having jurisdiction over the Calpine case.

In July 2005, the CPUC also approved SDG&E's request for the construction (CPCN application) of $209 million in transmission facilities needed, in part, to provide full dispatchability of the Otay Mesa generation project. SDG&E has commenced construction of the OMPPA transmission upgrade project, spending $8 million through December 31, 2005.

The CPUC requires SDG&E to achieve a 20% renewable energy portfolio by 2010. SDG&E has entered into contracts with four developers for the purchase of energy from projects scheduled to begin operation between 2007 and 2016. SDG&E has entered into a 20-year contract to develop a 900-MW solar project in the Imperial Valley area of California. The first phase would provide 300 MW of power beginning in 2008 - 2010. The second phase would provide an option for an additional 300 MW beginning in 2010 - 2012. The third phase would provide the right of first refusal for another 300 MW of power beginning after 2012. The first two phases received CPUC approval in December 2005. SDG&E has also entered into a 20-year contract for development of a 205.5-MW wind project scheduled to begin in 2007 - 2008. The projects are expected to raise SDG&E's overall renewable portfolio to 13.3 % in 2010. The projects are contingent upon successful completion of new transmission lines.

San Onofre Nuclear Generating Station (SONGS)

On May 5, 2005, the CPUC granted SDG&E a rehearing to resolve what SDG&E has contended was a computational error in the CPUC's setting of revenue for SDG&E's share of the operating costs of SONGS. Any adjustment would be retroactive to January 1, 2004. If SDG&E is fully successful, its revenue for the period in which the rehearing is concluded would be increased by $10 million for each of 2004 and 2005. Final resolution is expected in the first half of 2006.

With the end of the Incremental Cost Incentive Mechanism in 2003, SDG&E's SONGS ratebase restarted at $0 on January 1, 2004 and, therefore, SDG&E's earnings from SONGS are now generally limited to a return on new additions to ratebase.

In 2004 Edison, the operator of SONGS, applied for CPUC approval to replace the steam generators at SONGS, stating that the work needed to be done in 2009 and 2010 for Units 2 and 3, respectively, and would require an estimated capital expenditure of $680 million (in 2004 dollars). As provided for in the SONGS Operating Agreement, SDG&E elected not to participate in the steam generator replacement project, which triggered a dispute under the operating agreement over the extent to which SDG&E's ownership share and its related share of SONGS's output would be reduced from its existing 20% interest if SDG&E does not participate in the project. In February 2005, an arbitrator issued a decision that would result in SDG&E's ownership interest in SONGS and its related share of SONGS's output being reduced to zero if SDG&E continues to decline to participate in the project.

SDG&E intervened in Edison's CPUC application and requested that the CPUC either deny Edison's application as premature, direct Edison to purchase the new steam generators but defer the replacement until it is warranted, or direct Edison to purchase SDG&E's share in the facility and offer back a long-term power purchase agreement in an amount equal to SDG&E's current share (430 MW). Hearings before the CPUC on Edison's application were completed in February 2005, and a final decision approving the steam generator project was issued on December 15, 2005. That decision sets cost recovery at a maximum cap of $782 million and requires a reasonableness review of all costs if total costs exceed $680 million. The decision also approves Edison's revised schedule, which provides for completion of the project for Unit 2 and Unit 3 by early 2010 and late 2010, respectively. To relinquish its ownership share and to address the arbitrator's decision, SDG&E is required to file by April 14, 2006, an application with the CPUC to determine the reasonableness of the transfer of all or part of SDG&E's share of SONGS to Edison, with a decision expected in 2007. The CPUC could require SDG&E to participate in the project and retain a share of SONGS or SDG&E could elect to participate in the project and retain its current 20-percent ownership share of SONGS. If SDG&E's ownership share of SONGS is reduced, SDG&E would seek to recover its net investment in SONGS made since January 1, 2004 ($86 million at December 31, 2005, including materials and supplies of $31 million) and any future SONGS investments made prior to the time the ownership reduction becomes effective, and a return on its investment in SONGS ratebase (including that portion of the $31 million that is transferred to plant by that time).

Spent Nuclear Fuel

SONGS owners have responsibility for the interim storage of spent nuclear fuel generated at SONGS until it is accepted by the Department of Energy (DOE) for final disposal. Spent nuclear fuel has been stored in the SONGS Units 1, 2 and 3 spent fuel pools and in the ISFSI. Movement of all spent fuel to the ISFSI was completed as of December 31, 2005, providing sufficient space for the Units 2 and 3 spent fuel pools to meet storage requirements through mid-2007 and mid-2008, respectively. The ISFSI has adequate storage capacity through 2022.

NOTE 14. OTHER REGULATORY MATTERS

Utility Ratemaking Incentive Awards

Performance-Based Regulation (PBR) consists of three primary components. The first is a mechanism to adjust rates in years between general rate cases or cost of service cases. It annually adjusts base rates from those of the prior year to provide for inflation based on the most recent Consumer Price Index (CPI) forecast, subject to minimum and maximum percentage increases that change annually.

The second component is a mechanism whereby any earnings in excess of those authorized plus a narrow band above that are shared with customers in varying degrees depending upon the amount of the additional earnings.

The third component consists of a series of measures of utility performance. Generally, if performance is outside of a band around specified benchmarks, the utility is rewarded or penalized certain dollar amounts. The three areas that have been eligible for PBR rewards or penalties are operational incentives based on measurements of safety, reliability and customer service; demand-side management (DSM) rewards based on the effectiveness of the DSM programs; and natural gas procurement rewards or penalties. As noted below, the latest Cost of Service proceeding established formula-based performance measures for customer service, safety and reliability.

PBR, DSM and Gas Cost Incentive Mechanism (GCIM) awards are not included in the company's earnings until CPUC approval of the award is received. During 2005, the incentive rewards approved and included in earnings consisted of $2.4 million related to SoCalGas' Year 10 (2003-2004) GCIM and $0.2 million related to SDG&E's Year 11 (2003-2004) natural gas PBR.

On October 27, 2005, the CPUC approved the settlement agreement between the California Utilities and the CPUC's DRA, resolving all outstanding shareholder earnings claims associated with DSM, energy efficiency and low-income energy efficiency programs through various dates, depending on the program. The decision provides for $73 million and $14 million, respectively, in awards for SDG&E and SoCalGas, including interest, franchise fees, uncollectible amounts and awards earned in prior years that had not yet then been requested. Approximately $37 million of the $73 million award for SDG&E and the $14 million award for SoCalGas were included in fourth quarter 2005 income.

In October 2005, the CPUC also approved $8.2 million in PBR incentive awards for SDG&E's 2003 Distribution PBR performance report, relating to employee safety, customer service and electric reliability. This award is subject to refund in the event the current investigation of Edison's service quality incentive awards warrants a further investigation of PBR incentives for other utilities, including SDG&E. The CPUC's Consumer Protection and Safety Division is conducting an ongoing investigation of Edison's PBR incentive data reporting.

The cumulative amount of these awards that is subject to refund based on the outcome of the Border Price Investigation discussed in "Legal Proceedings" in Note 15 below is $67.9 million, the majority of which has been included in income.

Cost of Service

The California Utilities' proposed settlement of Phase II of their cost of service proceedings, addressing attrition allowances and performance-based incentive mechanisms, was approved by the CPUC and related performance measures and incentives were adopted. The CPUC's decision establishes an indexing methodology for post-test-year ratemaking that includes inflation adjustments and earnings-sharing mechanisms. The decision is retroactive to January 1, 2005 and is applicable to years 2005-2007. It eliminates earnings sharing and incentive awards for 2004.

For 2005-2007, the California Utilities' authorized base-rate revenues will be annually increased by the increase in the CPI, subject to minimum and maximum percentage increases that vary with the particular utility and increase yearly. The annual minimum increases range from 2.0% to 3.8% and the annual maximum percentage increases range from 3.0% to 4.8%. Pursuant to the indexing mechanisms, SDG&E and SoCalGas increased their 2006 base margin revenue requirements by $33 million and $52 million, respectively. The base margin adjustments included the recalibration of the 2005 base margin escalation to reflect actual index values before calculating the 2006 base margin revenue. For 2005-2007, any utility base-rate earnings that exceed the CPUC-authorized rate of return on ratebase plus 0.5 percentage point will be shared with customers, in proportions that vary with the amount of the excess, beginning with customers' receiving 75% of the excess, declining to 25% as the excess increases. The decision authorizes either utility to file for a suspension of the indexing and sharing mechanisms if its base-rate earnings for any year are at least 1.75 percentage points below its authorized rate of return and authorizes others to file for a suspension if either utility's base-rate earnings for any year are at least 1.75 percentage points above its authorized rate of return. The mechanisms would be automatically suspended for either utility if its base-rate earnings for 2005 or 2006 are at least 3 percentage points above or below its authorized rate of return.

The decision also establishes formula-based performance measures for customer service, safety and reliability. These provide symmetrical annual reward and penalty potentials aggregating approximately $22 million.

Cost of Capital

On December 15, 2005, the CPUC approved a return on equity (ROE) of 10.7% for SDG&E, an increase from its current ROE of 10.37%. SDG&E's authorized capital structure remains unchanged at 45.25% debt, 5.75% preferred stock and 49% common equity.

CPUC Investigation of Compliance with Affiliate Rules

In November 2004, the CPUC initiated the independent audit (known as the GDS audit) to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of the California Utilities. A draft audit report covering years 1997 through 2003 was provided to the CPUC's Energy Division in December 2005. The Energy Division is reviewing the draft audit report and plans to make the final audit report available in the first half of 2006. The scope of the audit is broader than the annual affiliate audit.

In May 2005, the California Utilities filed with the CPUC the results of the annual independent audit of the California Utilities' 2004 transactions with other Sempra Energy affiliates. Although the company does not agree with a finding of the auditor that utility procurement information was improperly provided to an affiliated risk-management consulting firm employed by Sempra Energy, the California Utilities have adopted the auditor's recommendation to perform risk management functions themselves rather than utilizing Sempra Energy's Risk Management Department.

"CPUC Investigation of Energy-Utility Holding Companies" and "Natural Gas Market OIR" (below) also discuss issues related to affiliate relationships.

CPUC Investigation of Energy-Utility Holding Companies

On October 27, 2005, the CPUC initiated a proceeding to re-examine the relationships between the California IOUs and their respective parent holding companies and other non-utility affiliates. It contemplates a review of the capital budgets, capital allocation processes, and dividend and capital retention policies of the utilities and their non-utility affiliates to better understand the amount of capital to be allocated for investment in energy infrastructure to meet California's need for reliable energy. The CPUC has broadly determined that, in appropriate circumstances, it could require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent it is not adequately funded through retail rates. The CPUC may propose additional rules or regulations to ensure that the utilities retain sufficient capital and the ability to access such capital to meet their customers' needs, and to address potential conflicts between the interests of utility ratepayers and those of non-utility affiliates to ensure that they do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. A preliminary schedule contemplates that any proposed rules and final rules would be issued for comment and final rules be adopted in the first half of 2006. 

Natural Gas Industry Restructuring (GIR)

In December 2001, the CPUC issued a decision related to GIR, with implementation anticipated during 2002. On April 1, 2004, after many delays and changes, the CPUC issued a decision that adopts tariffs to implement the 2001 decision. However, that decision stayed implementation of the GIR tariffs until the CPUC issued a decision in Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR) discussed below. At that time, the CPUC ordered the California Utilities to file a new proposal for system integration, firm access rights and off-system deliveries, as referenced below. The California Utilities are required to file new Biennial Cost Allocation Proceeding (BCAP) applications after the stay in the GIR implementation proceeding is lifted.

Natural Gas Market OIR

The CPUC's Natural Gas Market OIR was instituted in January 2004 and is being addressed in two phases. The focus of the Natural Gas Market OIR is the period from 2006 to 2016. The California Utilities have made comprehensive filings in the OIR, outlining a proposed market structure that is intended to create access to new natural gas supply sources, such as LNG, for California. In their filings, the California Utilities proposed a framework to provide firm tradable access rights for intrastate natural gas transportation; provide SoCalGas with continued balancing account protection for intrastate transmission and distribution revenues, thereby eliminating throughput risk; and integrate their transmission systems so as to have common rates and rules. The California Utilities also proposed that the capital expenditures necessary to access new sources of supply be included in ratebase and that the total amount of the expenditures would be $200 million to $300 million. A decision on Phase I was issued in September 2004. The California Utilities were required to file separate applications to address system integration, firm access rights and off-system deliveries. The CPUC also determined that the ratemaking treatment and cost responsibility for any access-related infrastructure will be addressed in future applications to be filed when more is known about the particular project.

Evidentiary hearings on the system integration proposal were held in September 2005 to consider whether the transmission component of the natural gas transportation rates of the California Utilities should be equalized. System integration would allow customers in the California Utilities' service territories to access upstream supplies of natural gas on an equal basis. A decision on this phase is expected during the first quarter of 2006. Evidentiary hearings on infrastructure adequacy were held in August 2005 and addressed a variety of issues including the infrastructure adequacy of the California Utilities' transmission and storage facilities. Natural gas quality standards and interconnection requirements are being addressed in separate phases. In the second phase, to be addressed in mid-2006, the CPUC will consider establishing a system of firm access rights into the California Utilities' system and off-system deliveries.

The California Utilities proposed a methodology and framework to be used by the CPUC for granting pre-approval of new interstate transportation agreements. The Phase I decision approved the California Utilities' transportation capacity pre-approval procedures with some modifications. SoCalGas' existing pipeline capacity contracts with Transwestern Pipeline Company (Transwestern) expired in November 2005 and its primary contracts with El Paso Natural Gas Company (El Paso) expire in August 2006. SoCalGas was granted pre-approval by the CPUC of a contract for released capacity on the Kern River Gas Transmission Company (Kern River) system, and four capacity contracts with El Paso. The contracts would expire between 2007 and 2011. In 2005, SDG&E was granted approval for capacity contracts with El Paso, Transwestern and Kern River, enabling the company to meet its identified goal to operate within the CPUC's approved planning range by November 1, 2006. In 2005, SoCalGas was granted pre-approval of two new capacity contracts with Transwestern that expire in 2009 and 2011. All interstate transportation capacity under the pre-approved contracts will be used to transport natural gas supplies on behalf of the California Utilities' core residential and small commercial customers, and all costs of the capacity will be recovered in the customers' procurement rates.

Recovery of Certain Disallowed Transmission Costs

In September 2005, the FERC approved SDG&E's May 2005 settlement with the California Independent System Operator (ISO), which provides for refunds of ISO charges on the Arizona Public Service Co. and the Imperial Irrigation District ownership shares of the Southwest Powerlink, and resolves such unreimbursed charges going forward. Therefore, SDG&E recorded pre-tax income of $44 million in the third quarter of 2005.

California Utilities' Structural Changes

On January 4, 2006, the company announced an agreement that, subject to court approval, would settle the Continental Forge antitrust litigation, an identical proceeding in Nevada and class action lawsuits alleging price misreporting and wash trading. The agreement included that the California Utilities will 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 firm storage capacity rights on SoCalGas' underground natural gas storage system. Additional discussion of the settlement is provided in Note 15 under "Legal Proceedings."

Gain on Sale Rulemaking

A rulemaking was issued in September 2004 to standardize the treatment of gains on sales of property by the IOUs. This rulemaking may result in the adoption of a general ratemaking policy for allocation between utility shareholders and ratepayers of any gain or loss on sale of utility property. The CPUC will consider adopting a standard percentage allocation, probably between 5 percent and 50 percent to shareholders, rather than resolving such allocations on a case-by-case basis, as is now its practice. In unusual circumstances the CPUC would be able to depart from the standard allocation to be adopted. The CPUC intends to apply this standard percentage to sales of both depreciable and non-depreciable property. The rulemaking states that the new policy would replace the CPUC's current policy of allocating to shareholders all gain or loss to shareholders on sale to a municipality of a utility operating system. In November 2005, a proposed decision was issued that, if approved, would adopt a process for allocating gains on sale received by certain electric, natural gas, telecommunications and water utilities when they sell utility land, assets such as buildings, or other tangible or intangible assets formerly used to serve utility customers. In most cases, utility customers should receive 75% of the gain. The utilities' shareholders should receive the remaining 25% of the gain on sale. Opening and reply comments to the proposed decision were filed in January 2006. The final outcome of the rulemaking may be different than that proposed for comment in the order instituting the rulemaking.

Southern California Wildfires

In August 2005, the CPUC granted SDG&E full recovery, via its catastrophic event memorandum account (CEMA), of incurred costs ($40.8 million) associated with the fires.

NOTE 15. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

In January 2006, the company reached agreements, subject to court approval, to settle certain litigation arising out of the 2000 - 2001 California energy crisis. As a result of that settlement, the company increased its reserves at December 31, 2005, to $743 million, of which $585 million relates to the settled matters.

Other reserves of $158 million have been established for the litigation that is continuing at February 22, 2006. The uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these 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.

Settlement Agreements

The litigation that is the subject of the settlement agreements is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge litigation, consisting of class-action and individual antitrust and unfair competition lawsuits consolidated in San Diego Superior Court, allege that Sempra Energy and the California Utilities, along with El Paso and several of its affiliates, unlawfully sought to control natural gas and electricity markets and claim damages of $23 billion after applicable trebling. Plaintiff class members include virtually all natural gas and electric consumers served by the California IOUs. The settlement of Continental Forge would also include the settlement of class action price reporting litigation, consisting of antitrust and unfair competition lawsuits coordinated in the San Diego Superior Court, alleging that Sempra Energy and its subsidiaries unlawfully misreported natural gas transactions to publishers of price indices and engaged in natural gas wash trading transactions. A second settlement agreement relates to class-action litigation brought by the Nevada Attorney General in Nevada Clark County District Court and involves virtually identical allegations to those in the Continental Forge litigation.

To settle the California and Nevada litigation, the company would 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. Of the $377 million, $83 million would be paid within thirty days of final approval of the settlement by the San Diego County Superior Court and an additional $83 million would be paid on the first anniversary of that approval. Of the remaining amount, $27.3 million would be paid on the closing date of the settlement and $26.3 million would be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date. At any time after the first anniversary of the closing date, the company would have the option to prepay all or any portion of the remaining unpaid settlement amounts at a discount rate of 7%, with any partial prepayment applied to and reducing each remaining payment on an equal and proportionate basis.

Additional consideration for the California settlement includes an agreement that Sempra LNG would sell to the California Utilities, subject to CPUC approval, re-gasified liquefied natural gas from its liquefied natural gas terminal being constructed in Baja California, Mexico at the California border index price minus $0.02. The volumes to be purchased and sold would be up to 500 million cubic feet per day that Sempra Energy subsidiaries currently have contractual rights to purchase and that is not delivered or sold to Mexican entities. The California Utilities also would 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. In addition, as described below, 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.

The California settlement is subject to the approval of the San Diego Superior Court, which has preliminarily approved the settlement, and authorized providing notice to the plaintiff class. The Los Angeles City Council has not yet voted to approve the City of Los Angeles's participation in the settlement and it may elect to continue pursuing its individual case against Sempra Energy and the California Utilities. If the City of Los Angeles decides not to participate, the company may, at its option, either proceed with the settlement of the class action and other individual cases or terminate the entire agreement. The California Attorney General, the DWR, the California Energy Oversight Board, Edison, and Pacific Gas & Electric Company unsuccessfully challenged the proposed notice to the class based on their concern that, among other things, the releases in the settlement agreement may be sufficiently broad to encompass other proceedings against Sempra Energy and its subsidiaries to which they are parties. The final approval hearing for the Continental Forge settlement is scheduled to occur on June 8, 2006. The Nevada settlement is subject to approval by the Nevada Clark County District Court, which has not yet approved notice to the class or scheduled a final approval hearing. Both the California and Nevada settlements must be approved for either settlement to take effect, but the company 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.

Sempra Energy recorded an after-tax charge of $116 million for the quarter ended December 31, 2005 (all at the parent company) to provide additional reserves to reflect the costs of the settlements that exceed amounts previously reserved. The additional and previously reserved amounts for the California and Nevada settlements aggregate $585 million (including $76 million at SDG&E and $155 million at SoCalGas) and 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 expected to be delivered under the DWR contract.

DWR Contract

In 2003, Sempra Generation was awarded summary judgment in its favor in a state civil action between Sempra Generation and the DWR, in which the DWR sought to void its 10-year contract expiring in 2011, under which the company sells electricity to the DWR. On June 21, 2005, the California Court of Appeal reversed the summary judgment decision, concluding that the contract language was ambiguous and that the claims raised by Sempra Generation's complaint and the DWR's cross-complaint for breach of contract and misrepresentation present triable issues of material fact that must be addressed by further evidence and proceedings in the trial court. The case has now been remanded back to the trial court for further proceedings, with a September 15, 2006 trial date.

In 2003, the FERC rejected federal regulatory challenges to Sempra Generation's contract with the DWR, as well as contracts between the DWR and other power suppliers, and upheld the contracts as consistent with the public interest. The FERC found no evidence of unfairness, bad faith or duress in the original contract negotiations and said there was no credible evidence that the contracts placed the complainants in financial distress or that ratepayers will bear an excessive burden. In December 2003, appeals of this matter were filed by a number of parties, including the California Energy Oversight Board and the CPUC. Oral argument on the appeal from the FERC decision was held in December 2004, with a decision by the Ninth Circuit Court of Appeals pending. There is no timetable for the court to render its decision.

The DWR continues to accept scheduled power from Sempra Generation and has paid all amounts billed. However, the DWR has commenced an arbitration proceeding disputing Sempra Generation's performance on various operational matters. The DWR has disputed a portion of the billings and the manner of certain deliveries and is seeking termination of the contract. Sempra Generation disputes these claims and an arbitration panel heard the matter in November 2005, with a decision expected in late April 2006. In addition, the DWR has indicated its intention to commence another arbitration disputing payment for energy it claims it did not receive.

In connection with the Continental Forge settlement agreement described above, Sempra Generation would voluntarily limit the places to which it delivers energy to the DWR and reduce the price it charges for electricity under the contract in the form of a $4.15 per megawatt-hour discount to its energy charge effective for deliveries after December 31, 2005. Based on the expected volumes of power to be delivered under the contract, this discount would have potential value aggregating $300 million over the remaining six-year term of the contract. In lieu of continuing to provide the discount, Sempra Generation would be permitted to elect, at the end of any calendar month, to make a one-time payment to the Continental Forge litigation settlement fund equal to the present value of a stream of payments of approximately $4.35 million per month over the remaining term of the contract using a 7% annualized discount rate. In addition, the discount in power prices provided by the settlement would be reduced by amounts in excess of $150 million 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.

As a result of reflecting the price discount of the DWR contract in 2005, earnings reported on the DWR contract for subsequent years will continue to reflect original rather than discounted power prices.

Other Natural Gas Cases

On November 21, 2005, the California Attorney General and the CPUC filed a lawsuit against Sempra Energy and the California Utilities in San Diego County Superior Court alleging that in 1998 Sempra Energy and the California Utilities had intentionally misled the CPUC in ultimately obtaining CPUC approval to use the utilities' California natural gas pipeline capacity to enable Sempra Energy's non-utility subsidiaries to deliver natural gas to a power plant in Mexico. It further alleges that, as a result of insufficient utility pipeline capacity to serve both the power plant and California customers, SDG&E curtailed natural gas service to electric generators and large California commercial and industrial customers 17 times in 2000 - 2001, with service disruptions resulting in increased air pollution and higher electricity prices for California consumers from the use of oil as an alternate fuel source by electric generating plants. The lawsuit seeks statutory penalties of not less than $1 million, $2,500 for each of an unspecified number of instances of unfair business practices, and unspecified amounts of actual and punitive damages. It also seeks an injunction to require divestiture by Sempra Energy of non-utility subsidiaries to an extent to be determined by the court.

In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, and included Sempra Energy, the California Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The U.S. District Court dismissed the case in November 2004, determining that the FERC had exclusive jurisdiction to resolve the claims. In January 2005, plaintiffs filed an appeal with the Ninth Circuit Court of Appeals.

Between May 2003 and December 2004, 20 antitrust actions were filed against Sempra Energy, and one or more of its affiliates (the California Utilities and Sempra Commodities, depending on the lawsuit) and various, 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. Several of those lawsuits seek class action certification. On April 8, 2005, one of those lawsuits, filed in the Nevada U.S. District Court, was dismissed, on the grounds that the claims asserted were preempted by federal law and the Filed Rate Doctrine. In June 2005, the three remaining lawsuits pending in the Nevada U.S. District Court were amended to name the California Utilities as defendants and to include conspiracy allegations similar to those made in the Continental Forge litigation. On December 27, 2005, the District Court dismissed these three actions, on the grounds that the claims asserted in these suits were preempted under federal law and the Filed Rate Doctrine. In addition, in June 2005, a class action lawsuit similar to the pending individual suits in the Nevada federal court was filed in the U.S. District Court for the Eastern District of California and has now been coordinated with the Nevada federal court proceeding. That action was stayed pending the court's determination of the motions to dismiss in the other federal cases. The company will proceed to seek the dismissal of this action as well. With respect to the lawsuits coordinated before the San Diego Superior Court, on June 29, 2005, the court denied the defendants' motion to dismiss on preemption and Filed Rate Doctrine grounds. A separate motion to dismiss filed by Sempra Energy for improper joinder remains pending resolution by the court. On January 4, 2006, the parties agreed to settle the class action cases coordinated in the San Diego Superior Court as part of the overall Continental Forge settlement described above.

Electricity Cases

Various antitrust lawsuits, which seek class-action certification, allege that numerous entities, including Sempra Energy and certain subsidiaries that participated in the wholesale electricity markets unlawfully manipulated those markets. Collectively, these lawsuits allege damages against all defendants in an aggregate amount in excess of $16 billion (before trebling). In January 2003, the federal court granted a motion to dismiss one of these lawsuits, filed by the Snohomish County, Washington Public Utility District against Sempra Energy and certain non-utility subsidiaries, among others, on the grounds that the claims contained in the complaint were subject to the Filed Rate Doctrine and were preempted by the Federal Power Act. In September 2004, the Ninth Circuit U.S. Court of Appeals affirmed the district court's ruling, finding that the FERC, not civil courts, has exclusive jurisdiction over the matter. Snohomish County appealed the Ninth Circuit decision to the U.S. Supreme Court, which, in June 2005, declined to review the decision. The company believes that this decision provides a precedent for the dismissal on the basis of federal preemption and the Filed Rate Doctrine of the other lawsuits against the Sempra Energy companies claiming manipulation of the electricity markets. On October 4, 2005, on the basis of federal preemption and Filed Rate grounds, the San Diego Superior Court dismissed with prejudice the initial consolidated cases that claimed that energy companies, such as the Sempra Energy companies, manipulated the wholesale electricity markets. In December 2005, plaintiffs filed an appeal in that case.

In May 2003, the Port of Seattle filed a similar complaint against a number of energy companies, including Sempra Energy, Sempra Generation and Sempra Commodities. That action was dismissed by the San Diego U.S. District Court in May 2004. Plaintiff has appealed the decision and oral argument has been scheduled for March 7, 2006. In May and June 2004, two lawsuits substantially identical to the Port of Seattle case were filed in Washington and Oregon U.S. District Courts. These cases were transferred to the San Diego U.S. District Court and motions to dismiss were granted in both cases on February 11, 2005, and plaintiffs have appealed. Oral argument on these appeals have not yet been scheduled. In October 2004, another case was filed in Santa Clara Superior Court against Sempra Generation, alleging claims substantively identical to those in the Port of Seattle case. This action was removed to the U.S. District Court in April 2005. A similar action against Sempra Generation, alleging that various entities coerced the DWR into long-term contracts to supply electricity that contained unfair and unreasonable terms in violation of California law, was dismissed with prejudice in September 2005, on federal preemption and Filed Rate grounds. The plaintiff did not appeal this dismissal.

On November 16, 2005, the California Attorney General filed litigation against Sempra Commodities, alleging that its traders manipulated wholesale electricity prices during the California energy crisis. The complaint does not specify an amount of damages and civil penalties, although the Attorney General issued a press release indicating that the damages and penalties "should total hundreds of millions of dollars." The case was removed to federal District Court and the Attorney General has filed a motion to remand the case back to the state superior court. The FERC has previously investigated numerous energy trading companies, including Sempra Commodities, regarding manipulation of energy prices. As further discussed in "FERC Manipulation Investigation" below, Sempra Commodities settled with the FERC in August 2004, reaching a full, final and complete resolution of all issues relating to it.

CPUC Border Price Investigation

In November 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California - Arizona border between March 2000 and May 2001. The Administrative Law Judge's (ALJ) proposed decision highly critical of SoCalGas' natural gas purchase, sales, hedging and storage activities during the period was rejected by the CPUC in December 2004.

The portion of this investigation relating to the California Utilities is still open. If the investigation were to determine that the conduct of either of the California Utilities contributed to the natural gas price spikes that occurred during the investigation period, the CPUC may modify the party's natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the party to issue a refund to ratepayers. At December 31, 2005, the cumulative amount of these shareholder awards, substantially all of which has been included in income, was $67.9 million.

The CPUC may hold additional hearings to consider whether other companies, including other California utilities, as well as the company and its non-utility subsidiaries, contributed to the natural gas price spikes, or issue an order terminating the investigation. Discovery is ongoing and initial testimony was filed in November 2005. Hearings are expected to begin in late July 2006.

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 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. The March 2003 order estimates that the replacement formula for estimating natural gas prices will increase the refund obligations from $1.8 billion to more than $3 billion for the same time period. Pending in the Ninth Circuit are various parties' appeals on aspects of the FERC's order. In April 2005, the Ninth Circuit heard oral argument on issues relating to the scope of the refund proceeding and whether the FERC had jurisdiction to order refunds from governmental entities. The Ninth Circuit determined in September 2005 that FERC did not have jurisdiction to order refunds from governmental entities. The California IOUs, including SDG&E, have now filed claims with the various governmental entities to recoup monies paid over and above the just and reasonable rate for power in the 2000-2001 time frame. A decision on the remaining issues argued before the Court in April 2005 remains pending. Sempra Commodities previously established reserves for its likely share of the original $1.8 billion discussed above. During 2004 and 2005, Sempra Commodities recorded additional reserves to reflect the estimated effect of the FERC's revision of the benchmark prices to be used by the FERC to calculate refunds, and Sempra Generation recorded its share of the 2004 and 2005 amounts related to its transactions with Sempra Commodities.

In a separate complaint filed with the FERC in 2002, the California Attorney General challenged the FERC's authority to establish a market-based rate regime, and further contended that, even if such a regime were valid, electricity sellers had failed to comply with the FERC's quarterly reporting requirements. The Attorney General requested that the FERC order refunds from suppliers. The FERC dismissed the complaint and instead ordered sellers to restate their reports. After an appeal by the California Attorney General, the Ninth Circuit Court of Appeals upheld the FERC's authority to establish a market-based rate regime, but ordered remand of the case to the FERC for further proceedings, stating that failure to file transaction-specific quarterly reports gave the FERC authority to order refunds with respect to jurisdictional sellers. In October 2004, the FERC announced that it will not appeal the court's decision. Although a group of sellers has requested the Ninth Circuit to rehear this matter, the timing and substance of the FERC's response to the remand is not yet known. However, it is possible that the FERC could order refunds or disgorgement of profits for periods in addition to those covered by its prior refund orders and substantially increase the refunds that ultimately may be required to be paid by Sempra Commodities and other power suppliers.

At December 31, 2005, Sempra Commodities remains due approximately $100 million from energy sales made in 2000 and 2001 through the ISO and the PX markets. The collection of these receivables depends on several factors, including the FERC refund case. The company believes adequate reserves have been recorded.

Settlement of Claims Associated with FERC Investigations

SDG&E has been awarded $137 million through December 31, 2005, in settlement of certain claims against electricity suppliers related to the 2000-01 California energy crisis. The net proceeds of these settlements are applied to reduce electric rates.

FERC Manipulation Investigation

The FERC is separately investigating whether there was manipulation of short-term energy markets in the western United States that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the periods relevant to the refund proceeding. In May 2002, the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs.

On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. First, the FERC directed 43 entities, including Sempra Commodities and SDG&E, to show cause why they should not disgorge profits from certain transactions between January 1, 2000 and June 20, 2001 that are asserted to have constituted gaming and/or anomalous market behavior under the California ISO and/or PX tariffs. Second, the FERC directed more than 20 entities, including Sempra Commodities, to show cause why their activities, in partnership or in alliance with others, during the same period did not constitute gaming and/or anomalous market behavior in violation of the tariffs. Remedies for confirmed violations could include disgorgement of profits and revocation of market-based rate authority. On October 31, 2003, Sempra Commodities agreed to pay $7.2 million in full resolution of these investigations. That liability was recorded as of December 31, 2003. The Sempra Commodities settlement was approved by the FERC on August 2, 2004. Certain California parties have sought rehearing on this order. SDG&E and the FERC resolved the matter through a settlement, which documents the ISO's finding that SDG&E did not engage in market activities in violation of the ISO or PX tariffs, and in which SDG&E agreed to pay $27,792 into a FERC-established fund.

Other Litigation

The company and several subsidiaries, along with three oil and natural gas companies, the City of Beverly Hills and the Beverly Hills Unified School District, are defendants in a toxic tort lawsuit filed in Los Angeles County Superior Court by approximately 1,000 plaintiffs claiming that various emissions resulted in cancer or fear of cancer. An initial twelve plaintiffs have a trial scheduled for October 2006 in which they seek unspecified compensatory and punitive damages. Sempra Energy has submitted the case to its insurers, who have reserved their rights with respect to coverage.

In 1998, Sempra Energy and the California Utilities converted their traditional pension plans (other than the SoCalGas union employee plan) to cash balance plans. On July 8, 2005, a lawsuit was filed against SoCalGas in the U.S. District Court for the Central District of California alleging that the conversion unlawfully discriminated against older employees and failed to provide required disclosure of a reduction in benefits. The lawsuit has been dismissed except for a single claim for alleged failure to make proper notification of plan changes. The company intends to seek to dismiss the remaining claim but believes that any adverse determination in the litigation would not be material.

In May 2003, a federal judge issued an order finding that the DOE's environmental assessment of Sempra Generation's Termoeléctrica de Mexicali (TDM) plant and another, unrelated Mexicali power plant failed to evaluate the plants' environmental impact adequately and called into question the U.S. permits they received to build their cross-border transmission lines. In July 2003, the judge ordered the DOE to conduct additional environmental studies and denied the plaintiffs' request for an injunction blocking operation of the transmission lines, thus allowing the continued operation of the TDM plant. The DOE undertook to perform an Environmental Impact Study, which was completed in December 2004, and the U.S. permits were reissued in April 2005. In August 2005, plaintiff filed an amended complaint that challenges the agency action on the reissued permits, claiming that the government failed to comply with federal environmental regulations in issuing new permits. On October 12, 2005, the court granted the company's request to intervene in the litigation.

Argentine Investments

As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent further declines, Sempra Pipelines & Storage reduced the carrying value of its investment downward by a cumulative total of $201 million as of December 31, 2005 ($198 million as of December 31, 2004), which does not affect the calculation of the company's net income unless the company were to dispose of its investment.

A decision is expected in late 2006 on Sempra Pipelines & Storage's arbitration proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of Sempra Pipelines & Storage's investments that has resulted from Argentine governmental actions. Sempra Energy also has a $48.5 million political-risk insurance policy under which it filed a claim to recover a portion of the investments' diminution in value, which could be resolved in mid 2006.

Natural Gas Contracts

The California Utilities buy natural gas under short-term and long-term contracts. Purchases are from various Southwest U.S. and Canadian suppliers and are primarily based on monthly spot-market prices. The California Utilities transport natural gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2011. Note 14 discusses the CPUC's Gas Market OIR.

SDG&E has long-term natural gas transportation contracts with various interstate pipelines that expire on various dates between 2006 and 2023. SDG&E currently purchases natural gas on a spot basis to fill its long-term pipeline capacity, and purchases additional spot market supplies delivered directly to California for its remaining requirements. SDG&E continues its ongoing assessment of its long-term pipeline capacity portfolio, including the release of a portion of this capacity to third parties. In accordance with regulatory directives, SDG&E reconfigured its pipeline capacity portfolio in November 2005 to secure firm transportation rights from a diverse mix of U.S. and Canadian supply sources for its projected core customer natural gas requirements.

At December 31, 2005, the future minimum payments under existing natural gas contracts were:

(Dollars in millions)	Storage and Transportation		Natural Gas				Total
2006	$	185	$	1,898		$	2,083
2007	129		464				593
2008	122		3				125
2009	105		3				108
2010	80		2				82
Thereafter	196		--				196
Total minimum payments	$	817	$		2,370	$	3,187

Total payments under natural gas contracts were $3.5 billion in 2005, $2.8 billion in 2004 and $2.2 billion in 2003.

In October 2004, Sempra LNG signed a sale-and-purchase agreement with British Petroleum for the supply of 500 million cubic feet of natural gas per day from Indonesia's Tangguh liquefaction facility to Sempra LNG's Energía Costa Azul regasification terminal. The 20-year agreement provides for pricing tied to the Southern California border index for natural gas and will supply half of the capacity of Energía Costa Azul.

Purchased-Power Contracts

For 2006, SDG&E expects to receive 43 percent of its customer power requirements from DWR allocations. Of the remaining requirements, SONGS is expected to account for 17 percent, long-term contracts for 19 percent (of which 7 percent is provided by renewable contracts expiring on various dates through 2025), Palomar for 12 percent and spot market purchases for 9 percent. The long-term contracts expire on various dates through 2032.

Sempra Commodities is committed to purchasing $161 million of power from an unconsolidated affiliate in varying amounts through 2014.

At December 31, 2005, the estimated future minimum payments under the long-term contracts (not including the DWR allocations) were:

(Dollars in millions)
2006	$	285
2007		287
2008		327
2009		310
2010		286
Thereafter		2,641
Total minimum payments	$	4,136

The payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Excluding DWR-allocated contracts, total payments under the contracts were $363 million in 2005, $329 million in 2004 and $396 million in 2003.

Coal Commitments

At December 31, 2005, Sempra Generation had a contract that includes annual commitments to purchase lignite coal for Twin Oaks either until an aggregate minimum volume has been achieved or through 2025. Future minimum payments under the contract totaled $394 million, for which payments of $28 million are due for 2006, $28 million for 2007, $27 million for 2008, $27 million for 2009, $26 million for 2010 and $258 million thereafter. The minimum payments have been adjusted for allowed shortfalls and 90-percent minimum take-or-pay requirements under the contract. On January 18, 2006, the company announced an agreement to sell the plant, which would result in the buyer assuming the coal contract. On January 20, 2006, the contract was amended to extend the contract life and change the base price and the mechanism for future price adjustments.

Leases

The company has leases (primarily operating) on real and personal property expiring at various dates from 2006 to 2045. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 5 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options which are exercisable by the company. The company also has long-term capital leases on real property. Property, plant and equipment included $8 million at December 31, 2005 and $28 million at December 31, 2004, related to these leases. The associated accumulated amortization was $5 million and $24 million, respectively. The 2005 amounts are significantly smaller, primarily due to the expiration of a capital lease in 2005.

At December 31, 2005, the minimum rental commitments payable in future years under all noncancellable leases were as follows:

(Dollars in millions)		Operating Leases		Capitalized Leases
2006	$	113	$	1
2007		105		1
2008		95		1
2009		89		1
2010		77		--
Thereafter		155		1
Total future rental commitments	$	634	$	5
Imputed interest (6% to 10%)				(1	)
Net commitments			$	4

Rent expense for operating leases totaled $98 million in 2005, $88 million in 2004 and $90 million in 2003. Depreciation expense for capitalized leases is included in Depreciation and Amortization on the Statements of Consolidated Income.

Construction Projects

Sempra Global has several subsidiaries which have developed or are in the process of constructing various capital projects in the United States and in Mexico. The following is a summary of commitments related to the projects developed or under development. Additional information is provided in Note 2.

Sempra LNG

In December 2004, Sempra LNG entered into agreements for the construction of the Energía Costa Azul LNG receipt facility and for the project's breakwater. As of December 31, 2005, Sempra LNG expects to make payments under the contracts of $343 million, including $258 million in 2006 and $85 million in 2007. In August 2005, Sempra LNG entered into an agreement with a group of companies for the construction of the Cameron LNG receipt facility. As of December 31, 2005, expected payments under this contract include $305 million in 2006, $138 million in 2007 and $68 million in 2008, for a total of $511 million over the term of the contract.

Sempra Pipelines & Storage

During 2005, Sempra Pipelines & Storage entered into $31 million of contracts to purchase pipes and professional services related to the Liberty project.

Guarantees

In conjunction with the acquisition of the former AEP power plants, Sempra Energy provided AEP a guarantee for certain specified liabilities described in the acquisition agreement. As of December 31, 2005, substantially all of the company's guarantees were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries. The only other significant guarantee is the $25 million related to debt issued by Chilquinta Energía Finance Co., LLC, an unconsolidated affiliate. Like the AEP guarantee (as discussed in Note 3), this guarantee is also considered to have an immaterial fair value, due to the expectation that performance will not be required.

Sempra Generation's Contract with the DWR

In May 2001, Sempra Generation entered into a ten-year agreement with the DWR to supply up to 1,900 MW of power to California. Sempra Generation may, but is not obligated to, deliver this electricity from its portfolio of natural gas-fired plants in the western United States and Baja California, Mexico. Subsequent to the state's signing of this contract and electricity-supply contracts with other vendors, various state officials have contended that the rates called for by the contracts are too high. Based on current natural gas prices, the price of power under the long-term contracts exceeds the current spot market price for electricity.Information concerning the validity of this contract, the FERC's orders upholding this contract, the pending appeal of the orders, and a unilateral reduction in the contract price is provided under "Legal Proceedings - DWR Contract" above.

Department Of Energy Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay by the DOE will lead to increased costs for spent fuel storage. This cost will be recovered through SONGS revenue unless the company is able to recover the increased cost from the federal government.

Electric Distribution System Conversion

Under a CPUC-mandated program, the cost of which is included in utility rates, and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 2005, the aggregate unexpended amount of this commitment was $67 million. Capital expenditures for underground conversions were $32 million in 2005, $23 million in 2004 and $28 million in 2003.

Environmental Issues

The company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. Laws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and comparable state laws. The company is required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate its businesses, and must spend significant sums on environmental monitoring, pollution control equipment and emissions fees. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, that could adversely affect Sempra Generation. Costs incurred at the California Utilities to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates.

Significant costs incurred to mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $20 million in 2005, $22 million in 2004 and $14 million in 2003 (includes only the company's share in cases of non-wholly owned affiliates). The cost of compliance with these regulations over the next five years is not expected to be significant.

The company has identified no significant environmental issues outside the United States, except for the additional environmental impact studies the DOE conducted of the TDM power plant near Mexicali, Baja California, Mexico. Additional information regarding environmental issues is provided above under "Legal Proceedings."

At the California Utilities, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing the company or resolved during the last three years include investigation and remediation of the California Utilities' manufactured-gas sites (31 completed as of December 31, 2005 and 13 to be completed), cleanup of third-party waste-disposal sites used by the company, which has been identified as a PRP (investigations and remediations are continuing) and mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS (the requirements for enhanced fish protection, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands are in process).

Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the cost or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. Not including the liability for SONGS marine mitigation, which SDG&E is participating in jointly with Edison, at December 31, 2005, the company's accrued liability for environmental matters was $58.4 million, of which $44.2 million is related to manufactured-gas sites, $10.3 million to cleanup at SDG&E's former fossil-fueled power plants, $1.6 million to waste-disposal sites used by the company (which has been identified as a PRP) and $2.3 million to other hazardous waste sites. The majority of these accruals are expected to be paid ratably over the next two years.

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 $8.65 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.

Concentration Of Credit Risk

The company maintains credit policies and systems to manage overall credit risk. These policies include an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. The California Utilities grant credit to utility customers and counterparties, substantially all of whom are located in their service territories, which together cover most of Southern California and a portion of central California.

As described above, Sempra Generation has a contract with the DWR to supply up to 1,900 MW of power to the state over 10 years, beginning in 2001. Sempra Generation would be at risk for the amounts of outstanding billings and the continued viability of the contract if the DWR were to default on its payments under this contract. The average monthly billing related to this contract is $45 million and is normally collected by the end of the next month.

Sempra Commodities monitors and controls its credit-risk exposures through various systems which evaluate its credit risk, and through credit approvals and limits. To manage the level of credit risk, Sempra Commodities deals with a majority of counterparties with good credit standing, enters into netting arrangements whenever possible and, where appropriate, obtains collateral or other security such as lock-box liens and downgrade triggers. Netting agreements incorporate rights of setoff that provide for the net settlement of subject contracts with the same counterparty in the event of default.

The developing LNG projects will result in significant reliance on the credit-worthiness of its major suppliers and customers of those projects.

NOTE 16. SEGMENT INFORMATION

The company has four separately managed reportable segments: SoCalGas, SDG&E, Sempra Commodities and Sempra Generation. The California Utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. SoCalGas is a natural gas distribution utility, serving customers throughout most of southern California and part of central California. SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County. Sempra Commodities, based in Stamford, Connecticut, is primarily a wholesale trader of physical and financial energy products and other commodities, and a trader and wholesaler of metals, serving a broad range of customers in the United States, Canada, Europe and Asia. Sempra Commodities' business also includes commodity sales on a retail basis to electricity and natural gas consumers. Sempra Generation primarily owns and operates power plants throughout the U.S. and Mexico, and also provides energy services and facilities management. Sempra Generation also owns mineral rights in properties that produce petroleum and natural gas. The "all other" amounts consist primarily of parent organizations, Sempra Pipelines & Storage, Sempra LNG, and Sempra Financial.

The accounting policies of the segments are described in Note 1, and segment performance is evaluated by management based on reported net income. California Utility transactions are based on rates set by the CPUC and the FERC.

Sales to the DWR, which is a customer of the Sempra Generation segment and which is discussed in various sections of this Annual Report, comprise 10% of Sempra Energy's operating revenues.

(Dollars in millions)			Years ended December 31,
			2005					2004					2003
OPERATING REVENUES
	SoCalGas		$	4,617		39	%	$	3,997		42	%	$	3,541		45	%
	SDG&E			2,512		22			2,274		24			2,308		29
	Sempra Commodities			2,724		23			1,689		18			1,227		15
	Sempra Generation			1,921		16			1,662		18			773		10
	All other			329		3			270		3			208		3
	Adjustments and eliminations			(139	)	(1	)		(124	)	(1	)		(109	)	(1	)
	Intersegment revenues			(227	)	(2	)		(334	)	(4	)		(57	)	(1	)
		Total	$	11,737		100	%	$	9,434		100	%	$	7,891		100	%
INTEREST EXPENSE
	SoCalGas		$	48				$	39				$	45
	SDG&E			74					68					73
	Sempra Commodities			49					23					31
	Sempra Generation			29					34					33
	All other			309					331					256
	Intercompany eliminations			(198	)				(173	)				(130	)
		Total	$	311				$	322				$	308
INTEREST INCOME
	SoCalGas		$	12				$	4				$	34
	SDG&E			23					25					42
	Sempra Commodities			14					8					12
	Sempra Generation			9					7					17
	All other			215					198					129
	Intercompany eliminations			(198	)				(173	)				(130	)
		Total	$	75				$	69				$	104
DEPRECIATION AND AMORTIZATION
	SoCalGas		$	264		41	%	$	255		41	%	$	289		47	%
	SDG&E			264		41			259		42			242		39
	Sempra Commodities			28		4			23		4			23		4
	Sempra Generation			57		9			44		7			21		3
	All other			33		5			40		6			40		7
		Total	$	646		100	%	$	621		100	%	$	615		100	%
INCOME TAX EXPENSE (BENEFIT)
	SoCalGas		$	97		231	%	$	154		80	%	$	150		319	%
	SDG&E			89		212			148		77			148		315
	Sempra Commodities			192		457			161		83			67		143
	Sempra Generation			111		264			91		47			27		57
	All other			(447	)	(1,064	)		(361	)	(187	)		(345	)	(734	)
		Total	$	42		100	%	$	193		100	%	$	47		100	%
NET INCOME (LOSS)
	SoCalGas*		$	211		23	%	$	232		26	%	$	209		32	%
	SDG&E*			262		28			208		23			334		52
	Sempra Commodities			460		50			320		36			128		20
	Sempra Generation			164		18			137		15			80		12
	All other			(177	)	(19	)		(2	)	--			(102	)	(16	)
		Total	$	920		100	%	$	895		100	%	$	649		100	%

*after preferred dividends

(Dollars in millions)				At December 31 or years ended December 31,
				2005					2004					2003
ASSETS
	SoCalGas		$		6,007		21	%	$	5,633		24	%	$	5,349		24	%
	SDG&E				7,492		26			6,834		29			6,461		29
	Sempra Commodities				11,262		39			7,574		32			6,144		28
	Sempra Generation				2,769		9			2,738		11			2,550		12
	All other				2,430		8			1,998		8			1,988		9
	Intersegment receivables				(747	)	(3	)		(1,002	)	(4	)		(504	)	(2	)
		Total	$		29,213		100	%	$	23,775		100	%	$	21,988		100	%
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
	SoCalGas		$		361		26	%	$	311		29	%	$	318		30	%
	SDG&E				464		33			414		38			444		42
	Sempra Commodities				57		4			126		12			51		5
	Sempra Generation				185		13			141		13			144		14
	All other				337		24			91		8			92		9
		Total	$		1,404		100	%	$	1,083		100	%	$	1,049		100	%
GEOGRAPHIC INFORMATION
Long-lived assets
	United States		$		11,612		88	%	$	10,975		89	%	$	10,380		89	%
	Latin America				1,493		11			1,177		10			1,121		10
	Europe				100		1			98		1			87		1
		Total	$		13,205		100	%	$	12,250		100	%	$	11,588		100	%
Operating revenues
	United States		$		10,382		89	%	$	8,542		91	%	$	7,215		92	%
	Latin America				658		6			311		3			315		4
	Europe				639		5			519		6			323		4
	Canada				33		--			37		--			10		--
	Asia				25		--			25		--			28		--
		Total	$		11,737		100	%	$	9,434		100	%	$	7,891		100	%

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

			Quarters ended
(Dollars and shares in millions, except per share amounts)		March 31					June 30	September 30			December 31
2005
Operating revenues				$	2,697	$	2,276		$	2,770		$	3,994
Operating expenses					2,419		2,066			2,596			3,545
Operating income				$	278	$	210		$	174		$	449
Income from continuing operations				$	223	$	123		$	222		$	361
Net income				$	223	$	121		$	221		$	355
Basic earnings per share:
	Income from continuing operations			$	0.96	$	0.51		$	0.87		$	1.42
	Net income			$	0.96	$	0.50		$	0.87		$	1.40
	Average common shares outstanding				232.9		243.9			253.0			253.5
Diluted earnings per share:
	Income from continuing operations			$	0.92	$	0.49		$	0.86		$	1.40
	Net income			$	0.92	$	0.48		$	0.86		$	1.38
	Average common shares outstanding				241.1		250.1			257.4			257.8
2004
Operating revenues				$	2,360	$	2,003		$	2,165		$	2,906
Operating expenses					2,028		1,786			1,810			2,529
Operating income				$	332	$	217		$	355		$	377
Income from continuing operations				$	221	$	129		$	231		$	339
Net income				$	197	$	121		$	231		$	346
Basic earnings per share:
	Income from continuing operations			$	0.97	$	0.56		$	1.01		$	1.47
	Net income			$	0.86	$	0.52		$	1.01		$	1.50
	Average common shares outstanding				228.1		230.4			229.4			230.8
Diluted earnings per share:
	Income from continuing operations			$	0.96	$	0.55		$	0.98		$	1.43
	Net income			$	0.85	$	0.52		$	0.98		$	1.46
	Average common shares outstanding				231.1		234.3			235.9			237.5

Operating revenues in the fourth quarter of 2005 included a $78 million before-tax mark-to-market gain on long-term forward contracts at Sempra Generation and $23 million before-tax related to the 2005 IRS decision relating to the sale of SDG&E's former South Bay power plant. Operating expenses in the fourth quarter of 2005 included $190 million before-tax California energy crisis litigation expense and $66 million before-tax of Sempra Generation impairment losses, primarily all of which was related to the write-down of unused gas and steam turbines. Operating expenses for the third quarter of 2005 included $308 million before-tax California energy crisis litigation expense and a $98 million before-tax gain on the sale of Sempra Commodities natural gas storage facilities. Net income for the third quarter of 2005 included the favorable resolution of prior years' income tax issues.

Operating revenues and expenses in the fourth quarter of 2004 included the favorable impact of the final Cost of Service decision and operating expenses included litigation costs recorded in the fourth quarter. Net income in the first and second quarters of 2004 included $24 million and $8 million, respectively, of losses related to the discontinuance and disposal of AEG. Net income in the fourth quarter of 2004 included the $38 million favorable impact of income tax issues related to the reduced estimate of federal and state income tax liabilities for certain prior years and the $7 million favorable tax adjustment related to AEG. Note 4 provides a discussion of discontinued operations.

QUARTERLY COMMON STOCK DATA (UNAUDITED)
		First Quarter	Second Quarter	Third Quarter	Fourth Quarter
2005
Market price
	High	$42.54	$41.71	$47.43	$47.86
	Low	$35.53	$37.07	$40.98	$41.10
2004
Market price
	High	$32.99	$34.90	$37.19	$37.93
	Low	$29.51	$30.80	$33.97	$31.00
Dividends declared were $0.29 and $0.25 per share in each quarter in 2005 and 2004, respectively.