10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C.  20549
FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended		March 31, 2011
	or
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from		to
Commission File No.		Exact Name of Registrants as Specified in their Charters, Address and Telephone Number	States of Incorporation		I.R.S. Employer Identification Nos.		Former name, former address and former fiscal year, if changed since last report
1-14201		SEMPRA ENERGY	California		33-0732627		No change
		101 Ash Street
		San Diego, California 92101
		(619)696-2000
1-3779		SAN DIEGO GAS & ELECTRIC COMPANY	California		95-1184800		No change
		8326 Century Park Court
		San Diego, California 92123
		(619)696-2000
1-40		PACIFIC ENTERPRISES	California		94-0743670		No change
		101 Ash Street
		San Diego, California 92101
		(619)696-2020
1-1402		SOUTHERN CALIFORNIA GAS COMPANY	California		95-1240705		No change
		555 West Fifth Street
		Los Angeles, California 90013
		(213)244-1200
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
			Yes	X		No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
Sempra Energy				Yes	X		No
San Diego Gas & Electric Company				Yes			No
Pacific Enterprises				Yes			No
Southern California Gas Company				Yes			No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
	Large accelerated filer		Accelerated filer			Non-accelerated filer		Smaller reporting company
Sempra Energy	[  X  ]		[      ]			[       ]		[      ]
San Diego Gas & Electric Company	[       ]		[      ]			[  X  ]		[      ]
Pacific Enterprises	[       ]		[      ]			[  X  ]		[      ]
Southern California Gas Company	[       ]		[      ]			[  X  ]		[      ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Sempra Energy				Yes			No		X
San Diego Gas & Electric Company				Yes			No		X
Pacific Enterprises				Yes			No		X
Southern California Gas Company				Yes			No		X
Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date.
Common stock outstanding on May 5, 2011:
Sempra Energy		239,445,387 shares
San Diego Gas & Electric Company		Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Pacific Enterprises		Wholly owned by Sempra Energy
Southern California Gas Company		Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy

SEMPRA ENERGY FORM 10-Q SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q PACIFIC ENTERPRISES FORM 10-Q SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q TABLE OF CONTENTS
		Page
Information Regarding Forward-Looking Statements		4
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	62
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	83
Item 4.	Controls and Procedures	84
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	85
Item 1A.	Risk Factors	85
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	85
Item 6.	Exhibits	86
Signatures		89

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

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

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. These forward-looking statements represent our estimates and assumptions only as of the date of this report.

In this report, when we use words such as "believes," "expects," "anticipates," "plans," "estimates," "projects," "contemplates," "intends," "depends," "should," "could," "would," "will," "may," "potential," "target," "goals," or similar expressions, or when we discuss our strategy, plans or intentions, we are making forward-looking statements.

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

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

§   actions by the California Public Utilities Commission, California State Legislature, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, California Energy Commission, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;

§   capital markets conditions and inflation, interest and exchange rates;

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

§   the availability of electric power, natural gas and liquefied natural gas;

§   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 our control.

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

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Three months ended March 31,
	2011		2010
	(unaudited)
REVENUES
Sempra Utilities	$	1,881	$	1,912
Sempra Global and parent		553		622
Total revenues		2,434		2,534
EXPENSES AND OTHER INCOME
Sempra Utilities:
Cost of natural gas		(609)		(758)
Cost of electric fuel and purchased power		(171)		(148)
Sempra Global and parent:
Cost of natural gas, electric fuel and purchased power		(263)		(338)
Other cost of sales		(23)		(25)
Litigation expense		(7)		(168)
Other operation and maintenance		(632)		(576)
Depreciation and amortization		(231)		(210)
Franchise fees and other taxes		(95)		(90)
Equity earnings, before income tax		1		15
Other income, net		43		8
Interest income		3		4
Interest expense		(108)		(109)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		342		139
Income tax expense		(109)		(58)
Equity earnings, net of income tax		31		19
Net income		264		100
(Earnings) losses attributable to noncontrolling interests		(4)		8
Preferred dividends of subsidiaries		(2)		(2)
Earnings	$	258	$	106
Basic earnings per common share	$	1.07	$	0.43
Weighted-average number of shares outstanding, basic (thousands)		240,128		246,083
Diluted earnings per common share	$	1.07	$	0.42
Weighted-average number of shares outstanding, diluted (thousands)		241,903		250,373
Dividends declared per share of common stock	$	0.48	$	0.39
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	1,219	$	912
Restricted cash			318		131
Trade accounts receivable			922		891
Other accounts and notes receivable			136		141
Due from unconsolidated affiliates			17		34
Income taxes receivable			261		248
Deferred income taxes			36		75
Inventories			176		258
Regulatory assets			73		90
Fixed-price contracts and other derivatives			97		81
Settlement receivable related to wildfire litigation			―		300
Other			171		192
Total current assets			3,426		3,353
Investments and other assets:
Restricted cash			―		27
Regulatory assets arising from pension and other postretirement
benefit obligations			885		869
Regulatory assets arising from wildfire litigation costs			348		364
Other regulatory assets			932		934
Nuclear decommissioning trusts			796		769
Investment in RBS Sempra Commodities LLP			779		787
Other investments			2,163		2,164
Goodwill and other intangible assets			537		540
Sundry			630		600
Total investments and other assets			7,070		7,054
Property, plant and equipment:
Property, plant and equipment			27,556		27,087
Less accumulated depreciation and amortization			(7,356)		(7,211)
Property, plant and equipment, net ($510 and $516 at March 31, 2011 and             December 31, 2010, respectively, related to VIE)			20,200		19,876
Total assets		$	30,696	$	30,283
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	566	$	158
Accounts payable - trade			607		755
Accounts payable - other			102		109
Due to unconsolidated affiliates			37		36
Dividends and interest payable			251		188
Accrued compensation and benefits			211		311
Regulatory balancing accounts, net			379		241
Current portion of long-term debt			89		349
Fixed-price contracts and other derivatives			91		106
Customer deposits			131		129
Reserve for wildfire litigation			489		639
Other			701		765
Total current liabilities			3,654		3,786
Long-term debt ($352 and $355 at March 31, 2011 and December 31, 2010, respectively,         related to VIE)			9,174		8,980
Deferred credits and other liabilities:
Customer advances for construction			132		154
Pension and other postretirement benefit obligations, net of plan assets			1,114		1,105
Deferred income taxes			1,633		1,561
Deferred investment tax credits			49		50
Regulatory liabilities arising from removal obligations			2,671		2,630
Asset retirement obligations			1,469		1,449
Other regulatory liabilities			130		138
Fixed-price contracts and other derivatives			285		290
Deferred credits and other			903		823
Total deferred credits and other liabilities			8,386		8,200
Contingently redeemable preferred stock of subsidiary			79		79
Commitments and contingencies (Note 10)
Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 239 million and 240 million shares
outstanding at March 31, 2011 and December 31, 2010, respectively; no par
value)			2,052		2,036
Retained earnings			7,472		7,329
Deferred compensation			(6)		(8)
Accumulated other comprehensive income (loss)			(332)		(330)
Total Sempra Energy shareholders' equity			9,186		9,027
Preferred stock of subsidiaries			100		100
Other noncontrolling interests			117		111
Total equity			9,403		9,238
Total liabilities and equity		$	30,696	$	30,283
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	264	$	100
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization		231		210
Deferred income taxes and investment tax credits		88		61
Equity earnings		(32)		(34)
Fixed-price contracts and other derivatives		(9)		―
Other		(13)		7
Net change in other working capital components		286		534
Changes in other assets		(5)		18
Changes in other liabilities		(5)		(8)
Net cash provided by operating activities		805		888
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(607)		(446)
Expenditures for investments		(4)		(74)
Distributions from investments		21		24
Purchases of nuclear decommissioning and other trust assets		(45)		(44)
Proceeds from sales by nuclear decommissioning and other trusts		46		46
Decrease in restricted cash		160		14
Increase in restricted cash		(320)		(23)
Other		(7)		7
Net cash used in investing activities		(756)		(496)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(94)		(86)
Preferred dividends paid by subsidiaries		(2)		(2)
Issuances of common stock		15		14
Repurchases of common stock		(18)		(2)
Issuances of debt (maturities greater than 90 days)		803		12
Payments on debt (maturities greater than 90 days)		(260)		(507)
(Decrease) increase in short-term debt, net		(192)		294
Other		6		(3)
Net cash provided by (used in)  financing activities		258		(280)
Increase in cash and cash equivalents		307		112
Cash and cash equivalents, January 1		912		110
Cash and cash equivalents, March 31	$	1,219	$	222
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	63	$	71
Income tax payments (refunds), net		37		(73)
SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES
Accrued capital expenditures	$	233	$	191
Dividends declared but not paid		118		99
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
Operating revenues
Electric	$	665	$	563
Natural gas		175		179
Total operating revenues		840		742
Operating expenses
Cost of electric fuel and purchased power		171		148
Cost of natural gas		83		89
Operation and maintenance		273		232
Depreciation and amortization		103		92
Franchise fees and other taxes		47		43
Total operating expenses		677		604
Operating income		163		138
Other income, net		16		―
Interest expense		(36)		(31)
Income before income taxes		143		107
Income tax expense		(49)		(31)
Net income		94		76
(Earnings) losses attributable to noncontrolling interests		(4)		8
Earnings		90		84
Preferred dividend requirements		(1)		(1)
Earnings attributable to common shares	$	89	$	83
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	272	$	127
Restricted cash			318		116
Accounts receivable - trade			266		248
Accounts receivable - other			34		59
Due from unconsolidated affiliates			1		12
Income taxes receivable			59		37
Deferred income taxes			113		129
Inventories			67		71
Regulatory assets arising from fixed-price contracts and other derivatives			54		66
Other regulatory assets			6		5
Fixed-price contracts and other derivatives			35		28
Settlement receivable related to wildfire litigation			―		300
Other			38		50
Total current assets			1,263		1,248
Other assets:
Deferred taxes recoverable in rates			514		502
Regulatory assets arising from fixed-price contracts and other derivatives			220		233
Regulatory assets arising from pension and other postretirement
benefit obligations			285		279
Regulatory assets arising from wildfire litigation costs			348		364
Other regulatory assets			72		73
Nuclear decommissioning trusts			796		769
Sundry			85		56
Total other assets			2,320		2,276
Property, plant and equipment:
Property, plant and equipment			11,551		11,247
Less accumulated depreciation and amortization			(2,744)		(2,694)
Property, plant and equipment, net ($510 and $516 at March 31, 2011 and             December 31, 2010, respectively, related to VIE)			8,807		8,553
Total assets		$	12,390	$	12,077
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	269	$	292
Due to unconsolidated affiliates			44		16
Accrued compensation and benefits			59		115
Regulatory balancing accounts, net			72		61
Current portion of long-term debt			19		19
Fixed-price contracts and other derivatives			50		51
Customer deposits			55		54
Reserve for wildfire litigation			489		639
Other			168		136
Total current liabilities			1,225		1,383
Long-term debt ($352 and $355 at March 31, 2011 and December 31, 2010,     respectively, related to VIE)			3,474		3,479
Deferred credits and other liabilities:
Customer advances for construction			21		21
Pension and other postretirement benefit obligations, net of plan assets			315		309
Deferred income taxes			1,073		1,001
Deferred investment tax credits			24		25
Regulatory liabilities arising from removal obligations			1,443		1,409
Asset retirement obligations			628		619
Fixed-price contracts and other derivatives			236		248
Deferred credits and other			356		283
Total deferred credits and other liabilities			4,096		3,915
Contingently redeemable preferred stock			79		79
Commitments and contingencies (Note 10)
Equity:
Common stock (255 million shares authorized; 117 million shares outstanding;
no par value)			1,338		1,138
Retained earnings			2,069		1,980
Accumulated other comprehensive income (loss)			(10)		(10)
Total SDG&E shareholder's equity			3,397		3,108
Noncontrolling interest			119		113
Total equity			3,516		3,221
Total liabilities and equity		$	12,390	$	12,077
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended
	March 31,
	2011		2010
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	94	$	76
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		103		92
Deferred income taxes and investment tax credits		75		9
Fixed price contracts and other derivatives		(4)		―
Other		(12)		―
Net change in other working capital components		241		101
Changes in other assets		7		5
Changes in other liabilities		(3)		(8)
Net cash provided by operating activities		501		275
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(348)		(290)
Purchases of nuclear decommissioning trust assets		(44)		(43)
Proceeds from sales by nuclear decommissioning trusts		42		40
Decrease in loans to affiliates, net		―		2
Decrease in restricted cash		109		14
Increase in restricted cash		(311)		(23)
Net cash used in investing activities		(552)		(300)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution		200		―
Preferred dividends paid		(1)		(1)
Issuances of long-term debt		―		3
Payments on long-term debt		(3)		(3)
Increase in short-term debt, net		―		27
Net cash provided by financing activities		196		26
Increase in cash and cash equivalents		145		1
Cash and cash equivalents, January 1		127		13
Cash and cash equivalents, March 31	$	272	$	14
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	17	$	10
Income tax payments (refunds), net		24		(26)
SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES
Accrued capital expenditures	$	145	$	80
Dividends declared but not paid		1		1
See Notes to Condensed Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
Operating revenues	$	1,056	$	1,182
Operating expenses
Cost of natural gas		531		674
Operation and maintenance		288		261
Depreciation		81		75
Franchise fees and other taxes		37		37
Total operating expenses		937		1,047
Operating income		119		135
Other income, net		3		4
Interest expense		(17)		(17)
Income before income taxes		105		122
Income tax expense		(37)		(57)
Net income/Earnings		68		65
Preferred dividend requirements		(1)		(1)
Earnings attributable to common shares	$	67	$	64
See Notes to Condensed Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	33	$	417
Accounts receivable - trade			521		534
Accounts receivable - other			63		49
Due from unconsolidated affiliates			383		68
Income taxes receivable			13		36
Inventories			28		105
Regulatory assets			10		12
Other			37		39
Total current assets			1,088		1,260
Other assets:
Due from unconsolidated affiliate			505		502
Regulatory assets arising from pension and other postretirement
benefit obligations			596		586
Other regulatory assets			124		123
Sundry			49		36
Total other assets			1,274		1,247
Property, plant and equipment:
Property, plant and equipment			9,944		9,826
Less accumulated depreciation and amortization			(3,854)		(3,802)
Property, plant and equipment, net			6,090		6,024
Total assets		$	8,452	$	8,531
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable - trade		$	234	$	327
Accounts payable - other			71		79
Due to unconsolidated affiliates			85		96
Deferred income taxes			27		16
Accrued compensation and benefits			76		98
Regulatory balancing accounts, net			307		180
Current portion of long-term debt			9		262
Customer deposits			73		73
Temporary LIFO liquidation			66		―
Other			187		163
Total current liabilities			1,135		1,294
Long-term debt			1,318		1,320
Deferred credits and other liabilities:
Customer advances for construction			111		133
Pension and other postretirement benefit obligations, net of plan assets			625		613
Deferred income taxes			462		416
Deferred investment tax credits			25		25
Regulatory liabilities arising from removal obligations			1,216		1,208
Asset retirement obligations			798		788
Deferred taxes refundable in rates			130		138
Deferred credits and other			199		180
Total deferred credits and other liabilities			3,566		3,501
Commitments and contingencies (Note 10)
Equity:
Preferred stock			80		80
Common stock (600 million shares authorized; 84 million shares outstanding;
no par value)			1,462		1,462
Retained earnings			893		876
Accumulated other comprehensive income (loss)			(22)		(22)
Total Pacific Enterprises shareholders' equity			2,413		2,396
Preferred stock of subsidiary			20		20
Total equity			2,433		2,416
Total liabilities and equity		$	8,452	$	8,531
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	68	$	65
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation		81		75
Deferred income taxes and investment tax credits		48		16
Other		(2)		(1)
Net change in other working capital components		177		339
Changes in other assets		12		1
Changes in other liabilities		(4)		(3)
Net cash provided by operating activities		380		492
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(168)		(114)
Increase in loans to affiliates, net		(295)		(146)
Net cash used in investing activities		(463)		(260)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(50)		(100)
Preferred dividends paid		(1)		(1)
Payment of long-term debt		(250)		―
Net cash used in financing activities		(301)		(101)
(Decrease) increase in cash and cash equivalents		(384)		131
Cash and cash equivalents, January 1		417		49
Cash and cash equivalents, March 31	$	33	$	180
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	8	$	9
Income tax refunds, net		14		23
SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES
Dividends declared but not paid	$	1	$	1
Accrued capital expenditures		76		52
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
Operating revenues	$	1,056	$	1,182
Operating expenses
Cost of natural gas		531		674
Operation and maintenance		288		262
Depreciation		81		75
Franchise fees and other taxes		37		37
Total operating expenses		937		1,048
Operating income		119		134
Other income, net		3		4
Interest expense		(17)		(17)
Income before income taxes		105		121
Income tax expense		(37)		(56)
Net income/Earnings attributable to common shares	$	68	$	65
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	33	$	417
Accounts receivable - trade			521		534
Accounts receivable - other			63		49
Due from unconsolidated affiliates			378		63
Income taxes receivable			9		28
Inventories			28		105
Regulatory assets			10		12
Other			36		39
Total current assets			1,078		1,247
Other assets:
Regulatory assets arising from pension and other postretirement
benefit obligations			596		586
Other regulatory assets			124		123
Sundry			22		8
Total other assets			742		717
Property, plant and equipment:
Property, plant and equipment			9,942		9,824
Less accumulated depreciation and amortization			(3,854)		(3,802)
Property, plant and equipment, net			6,088		6,022
Total assets		$	7,908	$	7,986
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2011		2010(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable - trade		$	234	$	327
Accounts payable - other			71		79
Due to unconsolidated affiliate			―		11
Deferred income taxes			28		17
Accrued compensation and benefits			76		98
Regulatory balancing accounts, net			307		180
Current portion of long-term debt			9		262
Customer deposits			73		73
Temporary LIFO liquidation			66		―
Other			186		163
Total current liabilities			1,050		1,210
Long-term debt			1,318		1,320
Deferred credits and other liabilities:
Customer advances for construction			111		133
Pension and other postretirement benefit obligations, net of plan assets			625		613
Deferred income taxes			464		418
Deferred investment tax credits			25		25
Regulatory liabilities arising from removal obligations			1,216		1,208
Asset retirement obligations			798		788
Deferred taxes refundable in rates			130		138
Deferred credits and other			198		178
Total deferred credits and other liabilities			3,567		3,501
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock			22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)			866		866
Retained earnings			1,107		1,089
Accumulated other comprehensive income (loss)			(22)		(22)
Total shareholders' equity			1,973		1,955
Total liabilities and shareholders' equity		$	7,908	$	7,986
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	68	$	65
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation		81		75
Deferred income taxes and investment tax credits		48		16
Other		(2)		(1)
Net change in other working capital components		168		346
Changes in other assets		12		1
Changes in other liabilities		(4)		(1)
Net cash provided by operating activities		371		501
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(168)		(114)
Increase in loans to affiliates, net		(287)		(156)
Net cash used in investing activities		(455)		(270)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(50)		(100)
Payment of long-term debt		(250)		―
Net cash used in financing activities		(300)		(100)
(Decrease) increase in cash and cash equivalents		(384)		131
Cash and cash equivalents, January 1		417		49
Cash and cash equivalents, March 31	$	33	$	180
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	8	$	9
Income tax refunds, net		14		23
SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES
Accrued capital expenditures	$	76	$	52
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy's Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 holding company, and its consolidated subsidiaries and a variable interest entity (VIE). Sempra Energy’s principal subsidiaries are

§   San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which we collectively refer to as the Sempra Utilities; and

§   Sempra Global, which is the holding company for Sempra Generation, Sempra Pipelines & Storage and Sempra LNG.

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated subsidiaries in Note 4 below and Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2010.

SDG&E

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

Pacific Enterprises and SoCalGas

Pacific Enterprise’s Condensed Consolidated Financial Statements include the accounts of Pacific Enterprises (PE) and its subsidiary, SoCalGas.  Sempra Energy owns all of PE’s common stock and PE owns all of SoCalGas’ common stock. SoCalGas’ Condensed Consolidated Financial Statements include its subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations.

PE's operations consist solely of those of SoCalGas and additional items (e.g., cash, intercompany accounts and equity) attributable to serving as a holding company for SoCalGas.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E, PE and SoCalGas. We provide separate information for SDG&E, PE and SoCalGas as required. In the Notes to Condensed Consolidated Financial Statements (except in Note 11), when only information for SoCalGas is provided, it is the same for PE. References in this report to "we," "our" and "Sempra Energy Consolidated" are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.

We have prepared the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after March 31, 2011 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation.  These adjustments are only of a normal, recurring nature.

All December 31, 2010 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2010 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of GAAP and the Securities and Exchange Commission.

You should read the information in this Quarterly Report in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010 (the Annual Report), which is a combined report for Sempra Energy, SDG&E, PE and SoCalGas.

Our significant accounting policies are described in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.

The Sempra Utilities and Sempra Pipelines & Storage's Mobile Gas Service Corporation and Ecogas Mexico, S de RL de CV prepare their financial statements in accordance with GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 2. NEW ACCOUNTING STANDARDS

There are no recent accounting pronouncements that are anticipated to have an impact on or are related to our financial condition, results of operations, or disclosures.

NOTE 3. RECENT INVESTMENT ACTIVITY

SEMPRA PIPELINES & STORAGE

In the three months ended March 31, 2010, Sempra Pipelines & Storage contributed $65 million to Rockies Express, a joint venture to own and operate the Rockies Express Pipeline. The contribution was the last required for the construction phase of the project.

On April 30, 2010, Sempra Pipelines & Storage completed the acquisition of the Mexican pipeline and natural gas infrastructure assets of El Paso Corporation for $307 million ($292 million, net of cash acquired). Proforma impacts on revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010 were additional revenues and earnings of $2 million and $6 million, respectively, for the three months ended March 31, 2010.

We provide information about Sempra Pipelines & Storage’s recent investment activity in Chile and Peru in Note 12.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

RBS SEMPRA COMMODITIES

RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings in Parent and Other.

We and our partner in the joint venture, The Royal Bank of Scotland (RBS), sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We expect our share of remaining proceeds to approximate $779 million, the amount of our investment in RBS Sempra Commodities as of March 31, 2011.

On April 15, 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities.  The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets.  In accordance with the Letter Agreement, we received a $329 million distribution on April 15, 2011.  This distribution included sales proceeds and our portion of 2010 distributable income totaling $357 million, less amounts to settle certain liabilities that we owed to RBS of $28 million.  The Letter Agreement affirms that RBS Sempra Commodities will consider additional distributions of capital after taking into account various factors including available cash, the need for prudent reserves, potential payouts to the purchasers of the partnership’s businesses, and any accrued or projected future operating losses or other wind-down expenses of the partnership.  The availability of cash is also impacted by the transfer of trading accounts to JP Morgan, one of the buyers in the sales transactions.  These transfers and the related collection of accounts receivable and net margin continue as planned, and will be done as promptly as practicable during 2011.  Future distributions will generally be made 51 percent to RBS, and 49 percent to us. The Letter Agreement also allows RBS Sempra Commodities to make capital calls to us, subject to certain limits, if necessary to support the remaining operations, for other liabilities or for other payments owed in connection with the sales transactions (subject to additional limitations). We do not anticipate any such capital calls.

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

For the three months ended March 31, 2011 and 2010, we recorded a pretax equity loss of $8 million and earnings of $7 million, respectively, from RBS Sempra Commodities.

We discuss the RBS Sempra Commodities sales transactions and other matters concerning the partnership in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 5. OTHER FINANCIAL DATA

TEMPORARY LIFO LIQUIDATION

SoCalGas values natural gas inventory by the last-in first-out (LIFO) method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. Temporary LIFO liquidation represents the difference between the carrying value of natural gas inventory withdrawn during the period for delivery to customers and the projected cost of the replacement of that inventory during summer months.

VARIABLE INTEREST ENTITIES (VIE)

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

§   the purpose and design of the VIE;

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

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

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

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

Otay Mesa VIE

SDG&E has a 10-year agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-MW generating facility that began commercial operations in October 2009. In addition to tolling, the agreement provides SDG&E with the option to purchase the power plant at the end of the contract term in 2019, or upon earlier termination of the purchased-power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, under certain circumstances, it may be required to purchase the power plant at a predetermined price.

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary.  SDG&E has no OMEC LLC voting rights and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Sempra Energy and SDG&E have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE's equity of $119 million at March 31, 2011 and $113 million at December 31, 2010 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $362 million at March 31, 2011, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC's property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.

Other Variable Interest Entities

SDG&E's power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates these contracts to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than that relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary as of March 31, 2011. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.

Sempra Energy’s other business units also enter into arrangements which could include variable interests.  We evaluate these contracts based upon the qualitative and quantitative analyses described above.  We have determined that these contracts are not variable interests in a VIE and therefore are not subject to the requirements of GAAP concerning the consolidation of VIEs.

PENSION AND OTHER POSTRETIREMENT BENEFITS

Net Periodic Benefit Cost

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

NET PERIODIC BENEFIT COST -- SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended March 31,				Three months ended March 31,
	2011		2010		2011		2010
Service cost	$	22	$	22	$	7	$	7
Interest cost		43		43		17		15
Expected return on assets		(37)		(36)		(12)		(12)
Amortization of:
Prior service cost		1		1		―		―
Actuarial loss		9		8		4		2
Regulatory adjustment		(29)		(29)		2		2
Total net periodic benefit cost	$	9	$	9	$	18	$	14

NET PERIODIC BENEFIT COST -- SDG&E
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended March 31,				Three months ended March 31,
	2011		2010		2011		2010
Service cost	$	7	$	7	$	2	$	2
Interest cost		13		12		2		2
Expected return on assets		(12)		(10)		(2)		(2)
Amortization of:
Prior service cost		1		1		1		1
Actuarial loss		2		3		―		―
Regulatory adjustment		(9)		(12)		1		1
Total net periodic benefit cost	$	2	$	1	$	4	$	4

NET PERIODIC BENEFIT COST -- SOCALGAS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended March 31,				Three months ended March 31,
	2011		2010		2011		2010
Service cost	$	12	$	12	$	5	$	5
Interest cost		25		25		13		12
Expected return on assets		(22)		(23)		(10)		(10)
Amortization of:
Prior service cost (credit)		1		1		(1)		(1)
Actuarial loss		4		3		5		2
Regulatory adjustment		(20)		(17)		1		1
Total net periodic benefit cost	$	―	$	1	$	13	$	9

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2011:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Contributions through March 31, 2011:
Pension plans	$	11	$	―	$	1
Other postretirement benefit plans		19		4		14
Total expected contributions in 2011:
Pension plans	$	266	$	82	$	118
Other postretirement benefit plans		76		16		55

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months ended March 31, 2011 and 2010. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Three months ended March 31,
	2011		2010
Numerator:
Earnings/Income attributable to common shareholders	$	258	$	106
Denominator:
Weighted-average common shares outstanding for basic EPS		240,128		246,083
Dilutive effect of stock options, restricted stock awards and restricted stock units		1,775		4,290
Weighted-average common shares outstanding for diluted EPS		241,903		250,373
Earnings per share:
Basic	$	1.07	$	0.43
Diluted	$	1.07	$	0.42

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits and minus tax shortfalls are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation excludes options for which the exercise price on common stock was greater than the average market price during the period. We had 2,120,225 and 2,180,900 such stock options outstanding during the three months ended March 31, 2011 and 2010, respectively.

We had 10,800 and 9,900 stock options outstanding during the three months ended March 31, 2011 and 2010, respectively, that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Assumed proceeds equal to the unearned compensation and windfall tax benefits and minus tax shortfalls related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. During the three months ended March 31, 2011, we had 997,609 RSUs that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method. There were no such antidilutive RSUs for the three months ended March 31, 2010 and no such antidilutive RSAs for the three months ended March 31, 2011 or 2010.

Because our RSAs and RSUs are performance based, they are included in potential dilutive shares at zero to 100 percent and zero to 150 percent, respectively, to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. For the three months ended March 31, 2011, 762,592 shares related to RSU grants were excluded from potential dilutive shares, as the performance goal had not been met for these grants. The remaining 1,597,632 shares related to RSU grants were included at 70 to 88 percent, and 26,733 shares related to the RSA grants were included at 100 percent. For the three months ended March 31, 2010, 2,353,535 shares related to RSU grants were included in potential dilutive shares at 150 percent, and 850,349 shares related to RSA grants were included at 100 percent based on the applicable performance threshold.

COMMON STOCK REPURCHASE PROGRAM

In September 2010, we entered into a share repurchase program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The program was completed in March 2011 with a total of 9,574,435 shares repurchased at an average price of $52.22 per share. Our outstanding shares used to calculate earnings per share were reduced by the number of shares repurchased when they were delivered to us, and the $500 million purchase price was recorded as a reduction in shareholders’ equity upon its prepayment. We received 5,670,006 shares during the quarter ended September 30, 2010; 2,407,994 shares on October 4, 2010 and 1,496,435 shares on March 22, 2011. We discuss the repurchase program further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 9 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $6 million and $7 million for the three months ended March 31, 2011 and 2010, respectively. Pursuant to our share-based compensation plans, we granted 999,200 restricted stock units and 11,876 restricted stock awards during the three months ended March 31, 2011, primarily in January.

CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and, at the Sempra Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects.  The following table shows capitalized financing costs for the three months ended March 31, 2011 and 2010.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended March 31,
	2011		2010
Sempra Energy Consolidated:
AFUDC related to debt	$	8	$	5
AFUDC related to equity		19		13
Other capitalized financing costs		6		7
Total Sempra Energy Consolidated	$	33	$	25
SDG&E:
AFUDC related to debt	$	6	$	3
AFUDC related to equity		15		9
Total SDG&E	$	21	$	12
SoCalGas:
AFUDC related to debt	$	2	$	2
AFUDC related to equity		4		4
Total SoCalGas	$	6	$	6

COMPREHENSIVE INCOME

The following table provides a reconciliation of net income to comprehensive income.

COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended March 31,
		2011						2010
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Net income (loss)(2)		$	260	$	4	$	264	$	108	$	(8)	$	100
Foreign currency translation
adjustments			(6)		―		(6)		(4)		―		(4)
Financial instruments			2		1		3		―		2		2
Net actuarial gain			2		―		2		1		―		1
Comprehensive income (loss)		$	258	$	5	$	263	$	105	$	(6)	$	99
SDG&E:
Net income (loss)		$	90	$	4	$	94	$	84	$	(8)	$	76
Financial instruments			―		1		1		―		2		2
Comprehensive income (loss)		$	90	$	5	$	95	$	84	$	(6)	$	78
PE:
Net income(2)		$	68	$	―	$	68	$	65	$	―	$	65
Comprehensive income		$	68	$	―	$	68	$	65	$	―	$	65
SoCalGas:
Net income		$	68	$	―	$	68	$	65	$	―	$	65
Comprehensive income		$	68	$	―	$	68	$	65	$	―	$	65
(1)	Shareholders' equity of Sempra Energy Consolidated, SDG&E, PE or SoCalGas as indicated in left margin.
(2)	Before preferred dividends of subsidiaries.

The amounts for comprehensive income in the table above are net of income tax expense as follows:

INCOME TAX EXPENSE ASSOCIATED WITH OTHER COMPREHENSIVE INCOME

(Dollars in millions)

Three months ended March 31,

2011

2010

Share-

Non-

Share-

Non-

holders'

controlling

Total

holders'

controlling

Total

Equity

Interests

Equity

Equity

Interests

Equity

Sempra Energy Consolidated:

Financial instruments

$

1

$

―

$

1

$

―

$

―

$

―

Net actuarial gain

1

―

1

1

―

1

Income tax amounts associated with other comprehensive income during the three months ended March 31, 2011 and 2010 at SDG&E, PE and SoCalGas were negligible.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following two tables provide a reconciliation of Sempra Energy and SDG&E shareholders’ equity and noncontrolling interests for the three months ended March 31, 2011 and 2010. There were no changes in the equity of PE's noncontrolling interests for the three months ended March 31, 2011 or 2010.

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
(Dollars in millions)
		Sempra
		Energy		Non-
		Shareholders'		controlling		Total
		Equity		Interests		Equity
Balance at December 31, 2010	$	9,027	$	211	$	9,238
Comprehensive income		258		5		263
Share-based compensation expense		11		―		11
Common stock dividends declared		(115)		―		(115)
Preferred dividends of subsidiaries		(2)		―		(2)
Issuance of common stock		15		―		15
Tax benefit related to share-based compensation		2		―		2
Repurchase of common stock		(17)		―		(17)
Common stock released from ESOP		7		―		7
Equity contributed by noncontrolling interests		―		1		1
Balance at March 31, 2011	$	9,186	$	217	$	9,403
Balance at December 31, 2009	$	9,007	$	244	$	9,251
Comprehensive income (loss)		105		(6)		99
Share-based compensation expense		13		―		13
Common stock dividends declared		(96)		―		(96)
Preferred dividends of subsidiaries		(2)		―		(2)
Issuance of common stock		27		―		27
Tax benefit related to share-based compensation		1		―		1
Repurchase of common stock		(2)		―		(2)
Common stock released from ESOP		7		―		7
Distributions to noncontrolling interests		―		(3)		(3)
Balance at March 31, 2010	$	9,060	$	235	$	9,295

SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST
(Dollars in millions)
		SDG&E		Non-
		Shareholder's		controlling		Total
		Equity		Interest		Equity
Balance at December 31, 2010	$	3,108	$	113	$	3,221
Comprehensive income		90		5		95
Preferred stock dividends declared		(1)		―		(1)
Capital contribution		200		―		200
Equity contributed by noncontrolling interest		―		1		1
Balance at March 31, 2011	$	3,397	$	119	$	3,516
Balance at December 31, 2009	$	2,739	$	146	$	2,885
Comprehensive income (loss)		84		(6)		78
Preferred stock dividends declared		(1)		―		(1)
Distributions to noncontrolling interest		―		(2)		(2)
Balance at March 31, 2010	$	2,822	$	138	$	2,960

TRANSACTIONS WITH AFFILIATES

Loans to Unconsolidated Affiliates

Sempra Pipelines & Storage has a U.S. dollar-denominated loan to Camuzzi Gas del Sur S.A., an affiliate of Sempra Pipelines & Storage’s Argentine investments, which we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. The loan has a $29 million balance outstanding at a variable interest rate (7.3 percent as of March 31, 2011). In May 2010, the maturity date of the loan was extended from June 2010 to June 30, 2011. The loan is fully reserved at March 31, 2011.

Investments

Sempra Pipelines & Storage has an investment in bonds issued by Chilquinta Energía S.A. that we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Affiliate Transactions

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E, PE AND SOCALGAS
(Dollars in millions)
		March 31,		December 31,
		2011		2010
SDG&E
Current:
Due from SoCalGas		$	―	$	11
Due from various affiliates			1		1
		$	1	$	12
Due to Sempra Energy		$	23	$	16
Due to SoCalGas			21		―
		$	44	$	16
Income taxes due from Sempra Energy(1)		$	36	$	25
PE
Current:
Due from Sempra Energy		$	357	$	60
Due from SDG&E			21		―
Due from various affiliates			5		8
		$	383	$	68
Due to affiliate		$	85	$	85
Due to SDG&E			―		11
		$	85	$	96
Income taxes due from Sempra Energy(1)		$	1	$	6
Noncurrent:
Promissory note due from Sempra Energy, variable rate based on
short-term commercial paper rates (0.19% at March 31, 2011)		$	505	$	502
SoCalGas
Current:
Due from Sempra Energy		$	357	$	60
Due from SDG&E			21		―
Due from various affiliates			―		3
		$	378	$	63
Due to SDG&E		$	―	$	11
Income taxes due to Sempra Energy(1)		$	(4)	$	(3)
(1)	SDG&E, PE and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies' having always filed a separate return.

Revenues from unconsolidated affiliates at the Sempra Utilities are as follows:

REVENUES FROM UNCONSOLIDATED AFFILIATES AT THE SEMPRA UTILITIES
(Dollars in millions)
	Three months ended March 31,
	2011		2010
SDG&E	$	2	$	1
SoCalGas		13		11

Transactions with RBS Sempra Commodities

Several of our business units have engaged in transactions with RBS Sempra Commodities. As a result of the divestiture of substantially all of RBS Sempra Commodities’ businesses, transactions between our business units and RBS Sempra Commodities will be assigned over time to the buyers of the joint venture businesses. Amounts in our Condensed Consolidated Financial Statements related to these transactions are as follows:

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended March 31,
		2011		2010
Revenues:
SoCalGas		$	―	$	4
Sempra Generation(1)			9		9
Sempra LNG			36		73
Total revenues		$	45	$	86
Cost of natural gas:
SDG&E		$	―	$	1
SoCalGas			―		12
Sempra Generation			26		16
Sempra Pipelines & Storage			7		9
Sempra LNG			28		67
Total cost of natural gas		$	61	$	105
(1)	Includes amounts in 2010 for Sempra Rockies Marketing, previously reported in the Sempra Commodities segment, as we discuss in Note 11.
		March 31,		December 31,
		2011		2010
Fixed-price contracts and other derivatives - Net Asset (Liability):
Sempra Generation		$	19	$	17
Sempra LNG			(28)		(35)
Total		$	(9)	$	(18)
Due to unconsolidated affiliates:
Sempra Generation		$	7	$	11
Sempra LNG			17		13
Parent and other			11		11
Total		$	35	$	35
Due from unconsolidated affiliates:
SoCalGas		$	―	$	3
Sempra Generation			4		13
Sempra LNG			8		13
Parent and other			5		5
Total		$	17	$	34

OTHER INCOME, NET

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

OTHER INCOME, NET
(Dollars in millions)
		Three months ended March 31,
		2011		2010
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	19	$	13
Investment gains(1)			8		3
Gains (losses) on interest rate and foreign exchange instruments(2)			10		(9)
Regulatory interest, net			―		(1)
Sundry, net			6		2
Total		$	43	$	8
SDG&E:
Allowance for equity funds used during construction		$	15	$	9
Losses on interest rate instruments(3)			―		(9)
Regulatory interest, net			―		(1)
Sundry, net			1		1
Total		$	16	$	―
SoCalGas and PE:
Allowance for equity funds used during construction		$	4	$	4
Sundry, net			(1)		―
Total at SoCalGas and PE		$	3	$	4
(1)	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Sempra Energy Consolidated includes Otay Mesa VIE and additional instruments.
(3)	Related to Otay Mesa VIE.

INCOME TAXES

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended March 31,
		2011				2010
		Income Tax	Effective Income			Income Tax	Effective Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	109	32	%	$	58	42	%
SDG&E		49	34			31	29
PE		37	35			57	47
SoCalGas		37	35			56	46

Changes in Effective Income Tax Rates

Sempra Energy Consolidated

The decrease in the effective income tax rate for the three months ended March 31, 2011 was primarily due to:

§   a $16 million write-down in 2010 of the deferred tax assets related to other postretirement benefits, as a result of a change in U.S. tax law that eliminates a future deduction, starting in 2013, for retiree healthcare funded by the Medicare Part D subsidy;

§   lower tax expense in 2011 due to Mexican currency translation and inflation adjustments;

§   higher planned investment tax credits;

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

§   higher deductions for self-developed software costs; offset by

§   lower favorable adjustments related to prior years' income tax issues;

§   higher pretax book income; and

§   an increase in the amount by which book depreciation for the Sempra Utilities exceeds normalized tax depreciation, which is not treated as a deferred tax asset for ratemaking purposes.

SDG&E

The increase in SDG&E's effective income tax rate for the three months ended March 31, 2011 was primarily due to:

§   lower favorable adjustments related to prior years’ income tax issues; and

§   higher pretax book income; offset by

§   a $3 million write-down in 2010 of the deferred tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above;

§   the impact of Otay Mesa VIE, as we discuss below; and

§   higher exclusions from taxable income of the equity portion of AFUDC.

Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.

PE and SoCalGas

The decrease in PE's and SoCalGas' effective income tax rates for the three months ended March 31, 2011 was primarily due to:

§   a $13 million write-down in 2010 of the deferred tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above; and

§   higher deductions for self-developed software costs; offset by

§   an increase in the amount by which book depreciation exceeds normalized tax depreciation, which is not treated as a deferred tax asset for ratemaking purposes.

NOTE 6. DEBT AND CREDIT FACILITIES

COMMITTED LINES OF CREDIT

At March 31, 2011, Sempra Energy Consolidated had $3.8 billion in committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes, the major components of which we detail below. Available unused credit on these lines at March 31, 2011 was $2.8 billion.

Sempra Energy

Sempra Energy has a $1 billion, four-year syndicated revolving credit agreement expiring in October 2014. Citibank, N.A. serves as administrative agent for the syndicate of 23 lenders. No single lender has greater than a 7-percent share.

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy's credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.

At March 31, 2011, Sempra Energy had $26 million of variable-rate demand notes outstanding supported by the facility.

Sempra Global

Sempra Global has a $2 billion, four-year syndicated revolving credit agreement expiring in October 2014. Citibank, N.A. serves as administrative agent for the syndicate of 23 lenders. No single lender has greater than a 7-percent share.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter.

At March 31, 2011, Sempra Global had $766 million of commercial paper outstanding supported by the facility. At March 31, 2011, $200 million of the commercial paper outstanding is classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt.

Sempra Utilities

SDG&E and SoCalGas have a combined $800 million, four-year syndicated revolving credit agreement expiring in October 2014. JPMorgan Chase Bank serves as administrative agent for the syndicate of 22 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $600 million, subject to a combined limit of $800 million for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $200 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit.

Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility's credit ratings. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter.

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

At March 31, 2011, SDG&E and SoCalGas had no outstanding borrowings and SDG&E had $237 million of variable-rate demand notes outstanding supported by the facility. Available unused credit on the lines at March 31, 2011 was $363 million at SDG&E and $563 million at SoCalGas; SoCalGas' availability reflects the impact of SDG&E's use of the combined credit available on the line.

GUARANTEES

RBS Sempra Commodities

As we discuss in Note 4, in 2010 and early 2011, Sempra Energy, RBS and RBS Sempra Commodities sold substantially all of the businesses and assets within the partnership in four separate transactions. In connection with each of these transactions, the buyers are, subject to certain qualifications, obligated to replace any guarantees that we have issued in connection with the applicable businesses sold with guarantees of their own. During the process of replacing these guarantees, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees. With respect to the transaction with Noble Group, for those guarantees that Noble Group is not able to replace, we have agreed to allow Noble Group to continue trading under such guarantees until June 1, 2011.

We have indemnified the partnership for certain litigation and tax liabilities related to the businesses purchased by the partnership from us. We recorded these obligations at a fair value of $5 million on April 1, 2008, the date we formed the partnership. This liability was amortized over its expected life.

RBS is obligated to provide RBS Sempra Commodities with certain of its working-capital requirements. We provide back-up guarantees for a portion of RBS Sempra Commodities’ remaining trading obligations. Some of these back-up guarantees may continue for a prolonged period of time. RBS has fully indemnified us for any claims or losses in connection with these arrangements, with the exception of those obligations for which JP Morgan has agreed to indemnify us. We discuss the indemnification release in Note 4.

RBS Sempra Commodities’ net trading liabilities supported by Sempra Energy’s guarantees at March 31, 2011 were $286 million, consisting of guaranteed trading obligations net of collateral. The amount of guaranteed net trading liabilities varies from day to day with the value of the trading obligations and related collateral.

Other Guarantees

Sempra Generation and BP Wind Energy currently hold 50-percent ownership interests in Fowler Ridge II. In August 2010, Fowler Ridge II obtained a $348 million term loan expiring in August 2022. The proceeds were used to return $180 million of each owner’s investment in the joint venture. The loan agreement requires Sempra Generation and BP Wind Energy to return cash to the project in the event that the project does not meet certain cash flow criteria or in the event that the project’s debt service and operation and maintenance reserve accounts are not maintained at specific thresholds. Sempra Generation recorded a liability of $9 million for the fair value of its obligation associated with the cash flow requirements, which constitutes a guarantee. This liability is being amortized over its expected life. The outstanding loan is not guaranteed by the partners.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.49 percent and 0.46 percent at March 31, 2011 and December 31, 2010, respectively. The weighted average interest rates at both March 31, 2011 and December 31, 2010 include commercial paper borrowings classified as long-term, as we discuss above.

LONG-TERM DEBT

In March 2011, Sempra Energy publicly offered and sold $500 million of 2-percent notes and $300 million of floating rate notes (1.069 percent as of March 31, 2011), both maturing in 2014. The floating rate notes bear interest at a rate equal to the three-month London interbank offered rate (LIBOR) plus 0.76 percent. The interest rate is reset quarterly.

INTEREST RATE SWAPS

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

NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

HEDGE ACCOUNTING

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

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

ENERGY DERIVATIVES

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

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

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

§   Sempra Generation uses natural gas and electricity instruments to market energy products and optimize the earnings of its power generation fleet. Gains and losses associated with these undesignated derivatives are recognized in Sempra Global and Parent Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

§   Sempra LNG and Sempra Pipelines & Storage use natural gas derivatives to market energy products and optimize the earnings of our liquefied natural gas business and Sempra Pipelines & Storage's natural gas storage and transportation assets. Sempra Pipelines & Storage also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. Sempra Pipelines & Storage’s derivatives are either undesignated or are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. The impacts on earnings are recognized in Sempra Global and Parent Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Sempra LNG’s derivatives are undesignated, and their impact on earnings is recorded in Sempra Global and Parent Revenues on the Condensed Consolidated Statements of Operations.

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

We summarize net energy derivative volumes as of March 31, 2011 and December 31, 2010 as follows:

Business Unit and Commodity		March 31, 2011	December 31, 2010
Sempra Utilities:
SDG&E:
Natural gas		48 million MMBtu	51 million MMBtu	(1)
Congestion revenue rights		17 million MWh	21 million MWh	(2)
Sempra Global:
Sempra Generation - electric power		1 million MWh	1 million MWh
Sempra Pipelines & Storage - natural gas		3 million MMBtu	8 million MMBtu
Sempra LNG - natural gas		6 million MMBtu	7 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

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

INTEREST RATE DERIVATIVES

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

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

The net notional amounts of our interest rate derivatives as of March 31, 2011 and December 31, 2010 were:

		March 31, 2011			December 31, 2010
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	15-305	2013-2019	$	215-355	2011-2019
SDG&E(1)			285-362	2019		285-365	2019
SoCalGas			―	―		150	2011
(1)	Includes Otay Mesa VIE. All of SDG&E's interest rate derivatives relate to Otay Mesa VIE.

FINANCIAL STATEMENT PRESENTATION

The following table provides the fair values of derivative instruments, without consideration of margin deposits held or posted, on the Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010:

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	March 31, 2011
								Deferred
								credits
		Current				Current		and other
		assets:				liabilities:		liabilities:
		Fixed-price		Investments		Fixed-price		Fixed-price
		contracts		and other		contracts		contracts
		and other		assets:		and other		and other
Derivatives designated as hedging instruments		derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments	$	6	$	―	$	―	$	(9)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments(3)	$	9	$	19	$	(25)	$	(49)
Commodity contracts not subject to rate recovery		54		16		(39)		(30)
Associated offsetting commodity contracts		(8)		(2)		8		2
Commodity contracts subject to rate recovery		7		2		(30)		(23)
Associated offsetting commodity contracts		(4)		(1)		4		1
Total	$	58	$	34	$	(82)	$	(99)
SDG&E:
Interest rate instruments(3)	$	―	$	―	$	(17)	$	(36)
Commodity contracts not subject to rate recovery		1		―		―		―
Commodity contracts subject to rate recovery		5		2		(25)		(23)
Associated offsetting commodity contracts		(2)		(1)		2		1
Total	$	4	$	1	$	(40)	$	(58)
SoCalGas:
Commodity contracts not subject to rate recovery	$	2	$	―	$	―	$	―
Commodity contracts subject to rate recovery		2		―		(3)		―
Associated offsetting commodity contracts		(2)		―		2		―
Total	$	2	$	―	$	(1)	$	―

		December 31, 2010
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments		$	3	$	―	$	―	$	―
SoCalGas:
Interest rate instrument		$	3	$	―	$	―	$	―
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments(3)		$	9	$	22	$	(25)	$	(57)
Commodity contracts not subject to rate recovery			59		20		(44)		(34)
Associated offsetting commodity contracts			(2)		(8)		2		8
Commodity contracts subject to rate recovery			5		―		(43)		(27)
Associated offsetting commodity contracts			(37)		(26)		37		26
Total		$	34	$	8	$	(73)	$	(84)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(41)
Commodity contracts not subject to rate recovery			1		―		―		―
Commodity contracts subject to rate recovery			2		―		(35)		(27)
Associated offsetting commodity contracts			(34)		(26)		34		26
Total		$	(31)	$	(26)	$	(18)	$	(42)
SoCalGas:
Commodity contracts not subject to rate recovery		$	1	$	―	$	―	$	―
Commodity contracts subject to rate recovery			3		―		(3)		―
Associated offsetting commodity contracts			(3)		―		3		―
Total		$	1	$	―	$	―	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E's amounts relate to Otay Mesa VIE.

The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010 were:

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain (loss) on derivatives recognized in earnings
			Three months ended March 31,
		Location	2011		2010
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	3	$	2
Interest rate instruments		Other Income, Net		(5)		(2)
Total(1)			$	(2)	$	―
SoCalGas:
Interest rate instrument		Interest Expense	$	1	$	2
Interest rate instrument		Other Income, Net		(3)		(2)
Total(1)			$	(2)	$	―
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax gain (loss) recognized					Gain (loss) reclassified from AOCI
		in OCI (effective portion)					into earnings (effective portion)
		Three months ended March 31,					Three months ended March 31,
		2011		2010		Location	2011		2010
Sempra Energy Consolidated:
Interest rate instruments(1)		$	―	$	―	Interest Expense	$	(2)	$	(3)
Interest rate instruments			1		―	Equity Earnings, Net of Income Tax		(1)		―
Commodity contracts not subject
to rate recovery			―		1	Equity Earnings, Before Income Tax		―		2
Total		$	1	$	1		$	(3)	$	(1)
SDG&E:
Interest rate instruments(1)		$	―	$	―	Interest Expense	$	(1)	$	(2)
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(1)	$	(1)
(1)	Amounts include Otay Mesa VIE. All of SDG&E's interest rate derivative activity relates to Otay Mesa VIE.

Sempra Energy expects that losses of $10 million, which are net of income tax benefit, that are currently recorded in Accumulated Other Comprehensive Income (Loss) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified to earnings depend on the commodity prices and interest rates in effect when derivative contracts that are currently outstanding mature.

SDG&E and SoCalGas expect that losses of $4 million and $1 million, respectively, which are net of income tax benefit, that are currently recorded in Accumulated Other Comprehensive Income (Loss) related to these cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.

The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010 were:

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain (loss) on derivatives recognized in earnings
			Three months ended March 31,
		Location	2011		2010
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments(1)		Other Income, Net	$	10	$	(9)
Commodity contracts not subject
to rate recovery		Revenues: Sempra Global and Parent		6		15
Commodity contracts not subject		Cost of Natural Gas, Electric
to rate recovery		Fuel and Purchased Power		1		(6)
Commodity contracts not subject
to rate recovery		Other Operation and Maintenance		2		―
Commodity contracts subject		Cost of Electric Fuel
to rate recovery		and Purchased Power		9		(52)
Commodity contracts subject
to rate recovery		Cost of Natural Gas		―		(2)
Commodity contracts subject		Cost of Natural Gas, Electric
to rate recovery		Fuel and Purchased Power		―		(3)
Total			$	28	$	(57)
SDG&E:
Interest rate instruments(1)		Other Income, Net	$	―	$	(9)
Commodity contracts not subject
to rate recovery		Operation and Maintenance		1		―
Commodity contracts subject		Cost of Electric Fuel
to rate recovery		and Purchased Power		9		(52)
Total			$	10	$	(61)
SoCalGas:
Commodity contracts not subject
to rate recovery		Operation and Maintenance	$	1	$	―
Commodity contracts subject
to rate recovery		Cost of Natural Gas		―		(2)
Total			$	1	$	(2)
(1)	Amount for 2010 related to Otay Mesa VIE. Sempra Energy Consolidated also includes additional instruments.

CONTINGENT FEATURES

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

For Sempra Energy, the total fair value of this group of derivative instruments in a net liability position at March 31, 2011 is $5 million. As of March 31, 2011, if the credit ratings of Sempra Energy were reduced below investment grade, $5 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position at March 31, 2011 is $2 million. As of March 31, 2011, if the credit ratings of SDG&E were reduced below investment grade, $2 million of additional assets could be required to be posted as collateral for these derivative contracts.

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

NOTE 8. FAIR VALUE MEASUREMENTS

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at March 31, 2011 and December 31, 2010:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		March 31, 2011				December 31, 2010
		Carrying		Fair		Carrying		Fair
		Amount		Value		Amount		Value
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	26	$	56	$	28	$	58
Total long-term debt(2)			8,868		9,320		8,330		8,883
Due to unconsolidated affiliate(3)			2		2		2		2
Preferred stock of subsidiaries			179		163		179		166
SDG&E:
Total long-term debt(4)		$	3,303	$	3,285	$	3,305	$	3,300
Contingently redeemable preferred stock			79		78		79		78
PE and SoCalGas:
Total long-term debt(5)		$	1,312	$	1,353	$	1,566	$	1,638
PE:
Preferred stock		$	80	$	65	$	80	$	68
Preferred stock of subsidiary			20		20		20		20
SoCalGas:
Preferred stock		$	22	$	21	$	22	$	21
(1)	We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
(2)	Before reductions for unamortized discount of $22 million at March 31, 2011 and December 31, 2010, and excluding capital leases of $217 million at March 31, 2011 and $221 million at December 31, 2010, and commercial paper classified as long-term debt of $200 million at March 31, 2011 and $800 million at December 31, 2010. We discuss our long-term debt in Note 6 above and Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(3)	Note payable to Chilquinta Energía S.A. due April 1, 2011 is included in Due to Unconsolidated Affiliates, Current at March 31, 2011 and December 31, 2010.
(4)	Before reductions for unamortized discount of $10 million at March 31, 2011 and $9 million at December 31, 2010, and excluding capital leases of $200 million at March 31, 2011 and $202 million at December 31, 2010.
(5)	Before reductions for unamortized discount of $2 million at March 31, 2011 and $3 million at December 31, 2010, and excluding capital leases of $17 million at March 31, 2011 and $19 million at December 31, 2010.

Sempra Energy based the fair values of investments in affordable housing partnerships on the present value of estimated future cash flows, discounted at rates available for similar investments. All entities based the fair values of long-term debt and preferred stock on their quoted market prices or quoted market prices for similar securities.

Nuclear Decommissioning Trusts

We discuss SDG&E's investments in nuclear decommissioning trust funds in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report. The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds:

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
			Cost		Gains		Losses		Value
As of March 31, 2011:
Debt securities
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	162	$	12	$	(3)	$	171
Municipal bonds(2)			95		2		(3)		94
Other securities(3)			36		3		―		39
Total debt securities			293		17		(6)		304
Equity securities			220		264		(1)		483
Cash and cash equivalents			9		―		―		9
Total		$	522	$	281	$	(7)	$	796
As of December 31, 2010:
Debt securities
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	162	$	14	$	(2)	$	174
Municipal bonds			101		2		(3)		100
Other securities			22		3		―		25
Total debt securities			285		19		(5)		299
Equity securities			219		242		(1)		460
Cash and cash equivalents			10		―		―		10
Total		$	514	$	261	$	(6)	$	769
(1)	Maturity dates are 2011-2040.
(2)	Maturity dates are 2013-2057.
(3)	Maturity dates are 2011-2049.

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

SALES OF SECURITIES
(Dollars in millions)
	Three months ended March 31,
	2011		2010
Proceeds from sales	$	42	$	40
Gross realized gains		1		1
Gross realized losses		(1)		(2)

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

Derivative Positions Net of Cash Collateral

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.

The following table provides the amount of fair value of cash collateral receivables that were not offset in the Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010:

	March 31,		December 31,
(Dollars in millions)	2011		2010
Sempra Energy Consolidated	$	42	$	32
SDG&E		31		25
SoCalGas		4		3

Fair Value Hierarchy

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Notes 1 and 2 of the Notes to Consolidated Financial Statements in the Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the three months ended March 31, 2011.

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2011 and December 31, 2010. We also discuss our financial assets and liabilities recorded at fair value on a non-recurring basis. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels.

The fair value of commodity derivative assets and liabilities is determined in accordance with our netting policy, as discussed above under "Derivative Positions Net of Cash Collateral."

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

We provide detail about our financial assets and liabilities that were accounted for at fair value on a recurring basis in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

RECURRING FAIR VALUE MEASURES -- SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of March 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	483	$	―	$	―	$	―	$	483
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			143		28		―		―		171
Municipal bonds			―		94		―		―		94
Other securities			―		39		―		―		39
Total debt securities			143		161		―		―		304
Total nuclear decommissioning trusts(1)			626		161		―		―		787
Interest rate instruments			―		34		―		―		34
Commodity contracts subject to rate recovery			32		1		3		―		36
Commodity contracts not subject to rate recovery			14		56		―		(9)		61
Investments			14		―		―		―		14
Total		$	686	$	252	$	3	$	(9)	$	932
Liabilities:
Interest rate instruments		$	―	$	83	$	―	$	―	$	83
Commodity contracts subject to rate recovery			44		5		―		(44)		5
Commodity contracts not subject to rate recovery			1		58		―		(1)		58
Total		$	45	$	146	$	―	$	(45)	$	146
		At fair value as of December 31, 2010
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	460	$	―	$	―	$	―	$	460
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			144		30		―		―		174
Municipal bonds			―		100		―		―		100
Other securities			―		25		―		―		25
Total debt securities			144		155		―		―		299
Total nuclear decommissioning trusts(1)			604		155		―		―		759
Interest rate instruments			―		34		―		―		34
Commodity contracts subject to rate recovery			25		1		2		―		28
Commodity contracts not subject to rate recovery			9		66		―		(22)		53
Investments			1		―		―		―		1
Total		$	639	$	256	$	2	$	(22)	$	875
Liabilities:
Interest rate instruments		$	―	$	82	$	―	$	―	$	82
Commodity contracts subject to rate recovery			60		8		―		(60)		8
Commodity contracts not subject to rate recovery			―		67		―		―		67
Total		$	60	$	157	$	―	$	(60)	$	157
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES -- SDG&E
(Dollars in millions)
		At fair value as of March 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	483	$	―	$	―	$	―	$	483
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			143		28		―		―		171
Municipal bonds			―		94		―		―		94
Other securities			―		39		―		―		39
Total debt securities			143		161		―		―		304
Total nuclear decommissioning trusts(1)			626		161		―		―		787
Commodity contracts subject to rate recovery			30		1		3		―		34
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	658	$	162	$	3	$	―	$	823
Liabilities:
Interest rate instruments		$	―	$	53	$	―	$	―	$	53
Commodity contracts subject to rate recovery			44		2		―		(44)		2
Total		$	44	$	55	$	―	$	(44)	$	55
		At fair value as of December 31, 2010
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	460	$	―	$	―	$	―	$	460
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			144		30		―		―		174
Municipal bonds			―		100		―		―		100
Other securities			―		25		―		―		25
Total debt securities			144		155		―		―		299
Total nuclear decommissioning trusts(1)			604		155		―		―		759
Commodity contracts subject to rate recovery			24		―		2		―		26
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	630	$	155	$	2	$	―	$	787
Liabilities:
Interest rate instruments		$	―	$	58	$	―	$	―	$	58
Commodity contracts subject to rate recovery			60		2		―		(60)		2
Total		$	60	$	60	$	―	$	(60)	$	60
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES -- SOCALGAS
(Dollars in millions)
	At fair value as of March 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	2	$	―	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		4		―		―		―		4
Total	$	6	$	―	$	―	$	―	$	6
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
	At fair value as of December 31, 2010
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Interest rate instruments	$	―	$	3	$	―	$	―	$	3
Commodity contracts subject to rate recovery		1		1		―		―		2
Commodity contracts not subject to rate recovery		3		―		―		―		3
Total	$	4	$	4	$	―	$	―	$	8

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

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of net trading and other derivatives classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

	Three months ended March 31,
(Dollars in millions)	2011		2010
Balance as of January 1	$	2	$	10
Realized and unrealized gains (losses)		6		(2)
Allocated transmission instruments		1		―
Settlements		(6)		1
Balance as of March 31	$	3	$	9
Change in unrealized gains relating to
instruments still held at March 31	$	―	$	―

There were no transfers into or out of Level 3 during the periods presented.

Level 3 recurring items are related to CRRs. These instruments are recorded at fair value based on the most current annual auction prices published by the California Independent System Operator (ISO). The earnings impact of CRRs are deferred and recorded in regulatory accounts to the extent they are recoverable or refundable through rates. Upon settlement, CRRs are included in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010.

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

We discuss non-recurring fair value measures and the associated accounting impact on our investments in RBS Sempra Commodities and Argentina in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 9. SEMPRA UTILITIES' REGULATORY MATTERS

POWER PROCUREMENT AND RESOURCE PLANNING

Renewable Energy

In 2010, certain California electric retail sellers, including SDG&E, were required to deliver 20 percent of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC), are known as the Renewables Portfolio Standard (RPS) Program. In April 2011, the Governor of California signed Senate Bill X1 2 (2011 RPS Program) which, when in effect, will supersede the RPS Program and require each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. We expect the 2011 RPS Program to become effective in the second quarter of 2011, and certain implementation details will be addressed by the CPUC.

The 2011 RPS Program contains new flexible compliance mechanisms, more restrictive than the prior mechanisms, that can be used to comply with or meet the 2011 RPS Program mandates in 2011 and beyond. The new mechanisms provide for a CPUC waiver under certain conditions, including: 1) a finding of inadequate transmission or 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection.

SDG&E continues to procure renewable energy supplies to achieve the 2011 RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including:

§   access to electric transmission infrastructure;

§   timely regulatory approval of contracted renewable energy projects;

§   the renewable energy project developers' ability to obtain project financing and permitting; and

§   successful development and implementation of the renewable energy technologies.

For 2010, SDG&E satisfied its RPS procurement requirements through a combination of contracted deliveries and application of the flexible compliance mechanism, including the application of certain mechanisms that are no longer available under the 2011 RPS Program. For 2011 and beyond, SDG&E believes it will be able to comply with the 2011 RPS Program requirements based on its contracting activity and, if necessary, application of the new flexible compliance mechanisms. SDG&E's failure to comply with the RPS Program requirements could subject it to a CPUC-imposed penalty of 5 cents per kilowatt hour of renewable energy under-delivery.

GENERAL RATE CASE (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the Sempra Utilities to recover their reasonable cost of operations and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the Sempra Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. The CPUC issued a ruling in March 2011 setting the proceeding scope and schedule that projected a final CPUC decision around the month of March 2012 and granted the utilities' requests to establish regulatory accounts to allow recovery of their authorized 2012 revenue requirements retroactive to January 1, 2012.

We provide further detail about the GRC applications in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

UTILITY INCENTIVE MECHANISMS

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

We provide additional information regarding these incentive mechanisms in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report, and updates below.

Natural Gas Procurement

In June 2010, SoCalGas applied to the CPUC for approval of a Gas Cost Incentive Mechanism (GCIM) award of $6 million for natural gas procured for our core customers during the 12-month period ending March 31, 2010. SoCalGas expects a CPUC decision in the third quarter of 2011.

In the first quarter of 2010, SoCalGas recorded a GCIM award of $12 million for SoCalGas' procurement activities during the 12-month period ending March 31, 2009, approved by the CPUC in January 2010.

Energy Efficiency

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency and demand side management programs. The Sempra Utilities plan to file requests with the CPUC in June 2011 for any incentive awards for the 2009 program year with a decision expected in 2012. The CPUC is also considering modifications to the incentive mechanism that would apply to the 2012 – 2014 program period. We expect a decision on these program modifications in 2011.

SDG&E REQUEST FOR AUTHORITY TO INVEST IN WIND FARM

In July 2010, SDG&E filed a request with the CPUC seeking authority to make a tax equity investment in the holding company of a wind farm project. In April 2011, SDG&E filed a settlement agreement with the CPUC resolving all issues with the parties in the proceeding. If the CPUC approves the settlement agreement as filed, SDG&E would make an investment, after the wind farm project has met all of the conditions precedent set forth in the definitive documents and upon the initiation of commercial operation of the project, which would be included in the utility’s rate base in an amount not to exceed 64.99 percent of the project costs or an aggregate amount of $250 million. SDG&E would also make an incremental investment, to be excluded from the utility’s rate base, of no less than 10 percent of the project costs. We expect a CPUC decision on the settlement agreement in mid-2011, and the project to be in commercial operation in the second half of 2012.

INSURANCE COST RECOVERY

SDG&E filed a request with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E requested a $29 million revenue requirement for the incremental increase in its general liability and wildfire liability insurance premium costs for the 2009/2010 policy period and proposed a mechanism for recovery of future liability insurance costs incurred in the 2010/2011 policy period and the first six months of the 2011/2012 policy period. SDG&E made the filing under the CPUC’s rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings resulting from unforeseen circumstances. The CPUC's rules allow a utility to seek recovery of incurred costs that meet certain criteria, subject to a $5 million deductible per event. In December 2010, the CPUC approved SDG&E’s request for the $29 million revenue requirement, which was implemented in rates effective January 1, 2011, and authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods, with a $5 million deductible applied to each policy renewal period. SDG&E filed a request in April 2011 for an incremental revenue requirement of $63 million for the 2010/2011 policy period. We expect a CPUC decision on the request in the second half of 2011. SDG&E also plans to file a request in the third quarter of 2011 for any incremental insurance premiums incurred for the first six months of the 2011/2012 policy period.

EXCESS WILDFIRE CLAIMS COST RECOVERY

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in rates. This application was made jointly with Southern California Edison (SCE) and Pacific Gas & Electric (PG&E). In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory accounts to record the subject expenses while the joint utility application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. A February 2011 ruling directing the utilities to show cause why the application should not be dismissed was stayed to permit continued settlement discussions between the four utilities and the CPUC and with the other parties to the proceeding.

SDG&E will also seek the recovery of costs incurred by SDG&E for the 2007 wildfire losses that are in excess of amounts recovered from its insurance coverage and other potentially responsible third parties. SDG&E believes that the approval of a new mechanism for cost recovery for future wildfires will provide a framework for discussions on recovery of these costs.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10.

NATURAL GAS PIPELINE OPERATIONS SAFETY ASSESSMENTS

As a result of recent natural gas pipeline explosions in the U.S., including the September 2010 rupture in San Bruno, California of a natural gas pipeline owned and operated by PG&E (the San Bruno incident), various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures.

In February 2011, the CPUC opened a forward-looking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The Sempra Utilities are parties to this proceeding. The CPUC also appointed an independent review panel to make recommendations for possible actions by the CPUC in light of the San Bruno incident. Those recommendations may include changes to design, construction, operation and maintenance practices of natural gas facilities in California. The report of the independent review panel is expected in the second quarter of 2011.

In January 2011, the National Transportation Safety Board (NTSB) issued seven safety recommendations in connection with its investigation into the cause of the San Bruno incident. According to the NTSB, these safety recommendations “were issued to address record-keeping problems that could create conditions in which a pipeline is operated at a higher pressure than the pipe was built to withstand.” In response to a request from the CPUC, each of the Sempra Utilities reviewed its pipeline facilities located or operating in populated or high consequence areas, as defined by the NTSB, to identify those segments that have not had the maximum allowable operating pressure (MAOP) established through prior hydrostatic testing. Federal and state regulations allow natural gas pipelines installed prior to July 1, 1970 to establish MAOPs through prior operating history rather than through a strength test, but strength tests are required on natural gas pipelines installed subsequent to June 30, 1970 as an element in establishing MAOPs.

In response to the CPUC’s request, the Sempra Utilities conducted a detailed review of 1,622 miles of pipelines (1,416 miles for SoCalGas and 206 miles for SDG&E) installed in the subject class locations, and on April 15, 2011, the Sempra Utilities submitted a report to the CPUC on the results of their review and the actions they are taking in response to the NTSB recommendations.

The Sempra Utilities’ records review process did not reveal any significant concerns with the currently established MAOP for their pipelines, and the Sempra Utilities intend to continue to operate their pipelines in a safe and prudent manner.

NOTE 10. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

At March 31, 2011, Sempra Energy’s accrued liabilities for material legal proceedings, on a consolidated basis, were $764 million, of which $48 million is for resolved matters. We provide detail regarding the resolved matters in Note 16 of the Notes to Consolidated Financial Statements in the Annual Report. At March 31, 2011, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $684 million and $25 million, respectively.

At March 31, 2011, liabilities of $683 million at Sempra Energy and SDG&E related to wildfire litigation may be paid using restricted cash of $312 million received in connection with a wildfire litigation settlement discussed below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E "power line caused" and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications' (Cox) fiber optic cable came into contact with an SDG&E power line "causing an arc and starting the fire." Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and approximately 1,141 homes destroyed.

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

Numerous parties have sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. These include owners and insurers of properties that were destroyed or damaged in the fires and public entities seeking recovery of firefighting, emergency response, and environmental costs. They assert various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines.

In October 2010, the Court of Appeal affirmed the trial court's ruling that these claims must be pursued in individual lawsuits, rather than as class actions on behalf of all persons who incurred wildfire damages. In February 2011, the California Supreme Court denied a petition for review of the affirmance. The trial court has scheduled a Witch fire and Guejito fire trial to begin in February 2012.

SDG&E filed cross-complaints against Cox seeking indemnification for any liability that SDG&E might incur in connection with the Guejito fire, two SDG&E contractors seeking indemnification in connection with the Witch fire, and one SDG&E contractor seeking indemnification in connection with the Rice fire.

In December 2010, SDG&E and Cox reached an agreement settling SDG&E's claims against Cox and Cox’s insurers in the wildfire litigation (Cox Settlement). Among other things, the settlement agreement provides that SDG&E will receive approximately $444 million, which it will use for wildfire related expenditures, and SDG&E will defend and indemnify Cox against all compensatory damage claims and related costs arising out of the wildfires.

At December 31, 2010, the $300 million Settlement Receivable Related to Wildfire Litigation on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E represented cash to be receivedin accordance with the terms of the Cox Settlement in several payments through March 2011 and which was received. Restricted cash of $312 million at March 31, 2011 on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E represents amounts received from Cox not yet applied to wildfire related expenditures.

SDG&E has settled substantially all of the 19,000 claims of homeowner insurers relating to the three fires. Under the settlement agreements, SDG&E has paid or will pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers’ claims against other parties potentially responsible for the fires.

The wildfire litigation also includes claims of non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has settled the claims of approximately 1,190 of these plaintiffs. Approximately 1,000 of the approximately 2,000 remaining individual and business plaintiffs have submitted settlement demands and damage estimates totaling approximately $800 million and government entity claims total approximately $140 million. SDG&E expects to receive additional settlement demands and damage estimates as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.

SDG&E's settlement of claims and defense costs have exceeded its $1.1 billion of liability insurance coverage.  It expects that its wildfire reserves and amounts paid to resolve wildfire claims will continue to increase as it obtains additional information; it is presently unable to reasonably estimate the amount or timing of recoveries from other potentially responsible parties, other than Cox.

SDG&E has concluded, however, that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and any amounts recovered from other potentially responsible parties. Accordingly, although such recovery will require future regulatory actions, as of December 31, 2010 and March 31, 2011, SDG&E recorded a regulatory asset in an amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts received or to be received from Cox. SDG&E will increase the regulatory asset as additional amounts are paid or reserves are recorded and reduce it by any amounts recovered from other potentially responsible parties.

As a consequence of the expected recovery of wildfire costs from utility customers, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. However, SDG&E’s cash flow may be adversely affected due to the timing differences between the resolution of claims and the recoveries from other potentially responsible parties and utility customers, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy's and SDG&E's cash flows and results of operations.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries from other potentially responsible parties and utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory asset as additional information becomes available.

In 2010 and 2011, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. The impact of this liability at December 31, 2010 and March 31, 2011 is offset by (1) current receivables for amounts to be received from Cox (December 31, 2010), (2) $312 million of restricted cash received from Cox (March 31, 2011) and (3) the recognition of a regulatory asset, as discussed above, for reserves in excess of the insurance coverage and the Cox settlement. The impact of the reserves on SDG&E's and Sempra Energy's after-tax earnings for the three months ended March 31, 2011 and 2010, was $1 million and $3 million, respectively. At March 31, 2011, wildfire litigation reserves were $683 million ($489 million in current and $194 million in long-term).

Sunrise Powerlink Electric Transmission Line

SDG&E commenced construction on the Sunrise Powerlink in the fall of 2010. The Sunrise Powerlink is a new 117-mile, 500-kilovolt (kV) electric transmission line that is being built between the Imperial Valley and the San Diego region, along a route that generally runs south of the Anza-Borrego Desert State Park. The current project plan provides for the transmission line to be completed and in-service in the second half of 2012.

The Sunrise Powerlink project was originally approved by the CPUC in December 2008, including approval of the environmental impact review conducted jointly with the Bureau of Land Management (BLM). The CPUC has subsequently denied or dismissed all requests for rehearing of its approval of the project.

In February 2011, the California Supreme Court denied a petition filed jointly by the Utility Consumers' Action Network (UCAN) and the Center for Biological Diversity/Sierra Club (CBD). The petition challenged the CPUC's decision with regard to implementation of the California Environmental Quality Act (CEQA). In addition, in August 2010 the California Court of Appeal denied a petition previously filed by UCAN with the Court of Appeal challenging the CPUC decision on other legal grounds.

In January 2009, the BLM issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The Interior Board of Land Appeals (IBLA) subsequently denied or dismissed all administrative appeals that were filed challenging the BLM’s approval of the project.

The CPUC and BLM jointly approved the final Project Modification Report for Sunrise Powerlink in September 2010, accepting all of the proposed modifications to the approved route and finding that no additional environmental review was required. In December 2010, the IBLA dismissed an appeal challenging the BLM’s approval of the Project Modification Report. On March 3, 2011, opponents of the Sunrise Powerlink filed a petition for writ of review or mandamus with the California Supreme Court challenging the CPUC’s acceptance of the Project Modification Report. The California Supreme Court denied the petition on April 13, 2011.

In February 2010, parties opposed to the project filed a lawsuit in Federal District Court in San Diego seeking declaratory and injunctive relief and alleging that the BLM failed to properly assess the environmental impacts of the approved Sunrise Powerlink route and the related potential development of renewable resources in east San Diego County and Imperial County. The plaintiffs have filed a motion for a preliminary injunction regarding construction on BLM land and the plaintiffs, the federal government and SDG&E have each filed separate motions for summary judgment with the Court.

In July 2010, the United States Forest Service (USFS) issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The USFS has subsequently denied all administrative appeals challenging its approval of the project.

In January 2011, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the federal approvals for construction of the project on USFS land and BLM land violated the National Environmental Policy Act and other federal environmental laws. The lawsuit asks the Court for injunctive relief preventing the USFS and the BLM from approving any ongoing or future construction activities.

On February 7, 2011, opponents of the Sunrise Powerlink filed a lawsuit in California Superior Court in Sacramento, California against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated CEQA. The complaint seeks to have the certification set aside and requests an injunction be issued.

We provide additional information concerning Sunrise Powerlink in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SoCalGas

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

Sempra Pipelines & Storage

Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. in February 2011 related to a sublease agreement. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million. We discuss other matters related to these caverns in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra LNG

Sempra LNG has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul liquefied natural gas (LNG) receipt terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility. In June 2010, a Mexican federal appeals court revoked a district court order, issued at the behest of the claimant, directing Mexican regulatory authorities to provisionally suspend authorizations for the operation of the LNG terminal. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally.

Sempra LNG expects additional Mexican court proceedings and governmental actions regarding the claimant’s assertions as to whether the terminal’s permits should be modified or revoked in any manner.

The property claimant has also filed a lawsuit against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages and earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions.

Other Litigation

In August 2007, the U.S. Court of Appeals for the Ninth Circuit issued a decision reversing and remanding certain Federal Energy Regulatory Commission (FERC) orders declining to provide refunds regarding short-term bilateral sales up to one month in the Pacific Northwest for the December 2000 to June 2001 time period. The FERC has not yet acted on the court’s order.  In December 2010, the FERC approved a comprehensive settlement previously reached by Sempra Energy and RBS Sempra Commodities with the State of California. The settlement resolves all issues with regard to sales between the California Department of Water Resources (DWR) and Sempra Commodities (see Note 11) in the Pacific Northwest, but potential claims may exist regarding sales between Sempra Commodities and other buyers in the Pacific Northwest.    

Pursuant to the agreements related to the formation of RBS Sempra Commodities, we have indemnified RBS should the liability from the final resolution of these matters be greater than the reserves related to Sempra Commodities. Pursuant to our agreement with the Noble Group, we have also indemnified Noble Americas Gas & Power Corp. and its affiliates for all losses incurred by such parties resulting from these proceedings as related to Sempra Commodities.

Sempra Energy 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. This lawsuit claims that various emissions resulted in cancer or fear of cancer. We have submitted the case to our insurers, who have reserved their rights with respect to coverage. In November 2006, the court granted the defendants' summary judgment motions based on lack of medical causation for the 12 initial plaintiffs scheduled to go to trial first. The court also granted summary judgment excluding punitive damages. The court has stayed the case as to the remaining plaintiffs pending the appeal of the rulings. A mediation occurred in June 2010, after which the plaintiffs’ counsel agreed to recommend a settlement of the lawsuits as to Sempra Energy and its subsidiaries for an amount that is not significant. Any such settlement will require approval by each of the plaintiffs. If approval is obtained, finalization of the settlement is expected to occur within six months.

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

NUCLEAR INSURANCE

SDG&E and the other owners of San Onofre Nuclear Generating Station (SONGS) have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E's contribution would be up to $47 million. This amount is subject to an annual maximum of $7 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $8.5 million.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

CONTRACTUAL COMMITMENTS

Sempra Energy Consolidated

In the first quarter of 2011, significant increases in commitments at Sempra Energy were

§   the issuance of $500 million of 2.0-percent notes and $300 million of floating rate notes, both maturing in 2014, at Sempra Energy;

§   $62 million for purchased-power contracts at SDG&E;

§   $23 million for costs related to the replacement of the steam generators and other construction projects at SONGS;

§   $45 million for electric distribution systems, advanced metering infrastructure and electric generation plant and equipment at SDG&E;

§   $321 million at SDG&E for engineering, material procurement and construction costs associated with the Sunrise Powerlink project; and

§   $42 million for construction and infrastructure improvements for natural gas transmission and distribution operations and advanced metering at SoCalGas; offset by

§   $51 million in reductions at Sempra Generation for natural gas contracts.

We expect future payments for the contractual commitments listed above to be $341 million for 2011, $85 million for 2012, $31 million for 2013, $778 million for 2014, $2 million for 2015 and $57 million thereafter. These amounts include expected interest payments on the notes using the stated interest rate for the fixed-rate notes and forward rates in effect at March 31, 2011 for the floating rate notes.

We discuss reserves for Sempra Energy and SDG&E related to wildfire litigation above in “SDG&E – 2007 Wildfire Litigation.”

We discuss changes to SoCalGas’ natural gas purchase and pipeline capacity commitments below.

At March 31, 2011, Sempra LNG has various purchase agreements with major international companies for the supply of LNG to its Energía Costa Azul and Cameron receipt terminals. We discuss these agreements further in Note 16 of the Notes to Consolidated Financial Statements in the Annual Report. Sempra LNG’s commitments under all LNG purchase agreements, reflecting the termination effective September 2011 of an LNG supply option agreement by one of the suppliers, changes in forward prices since December 31, 2010, and actual transactions for the first three months of 2011, are expected to decrease by $336 million in 2011, $366 million in 2012, and $145 million in 2013, and to increase by $50 million in 2014, $83 million in 2015 and $2.3 billion thereafter compared to December 31, 2010.

The LNG commitment amounts above are based on Sempra LNG’s commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases for the three months ended March 31, 2011 have been significantly lower than the maximum amounts possible.

SDG&E

In the first quarter of 2011, significant increases to contractual commitments at SDG&E were $62 million for purchased-power contracts, $23 million for costs related to the replacement of the steam generators and other construction projects at SONGS, $45 million for electric distribution systems, advanced metering infrastructure and electric generation plant and equipment and $321 million for engineering, material procurement and construction costs associated with the Sunrise Powerlink project.

The future payments for these contractual commitments are expected to be $331 million for 2011, $56 million for 2012, $3 million for 2013, $2 million for 2014, $2 million for 2015 and $57 million thereafter.

SoCalGas

In the first quarter of 2011, significant increases to contractual commitments at SoCalGas were $42 million for construction and infrastructure improvements for natural gas transmission and distribution operations and advanced metering at SoCalGas.  The future payments for these contractual commitments are expected to be $25 million for 2011, $12 million for 2012 and $5 million for 2013.

SoCalGas’ natural gas purchase and pipeline capacity commitments have decreased by $97 million since December 31, 2010. The decrease, primarily due to a reduction of $237 million based on actual transactions for the first quarter of 2011, is offset by new natural gas purchase and pipeline capacity contracts of $140 million. Net future payments are therefore expected to decrease by $114 million for 2011 and to increase by $16 million for 2012 and $1 million for 2014 compared to December 31, 2010.

NOTE 11. SEGMENT INFORMATION

We have five separately managed reportable segments, as follows:

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

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

3.   Sempra Generation develops, owns and operates, or holds interests in, electric power plants and energy projects in Arizona, California, Colorado, Nevada, Indiana, Hawaii and Mexico to serve wholesale electricity markets in the United States and Mexico. Sempra Generation also includes the operating results of Sempra Rockies Marketing, which holds firm service capacity on the Rockies Express Pipeline.

4.   Sempra Pipelines & Storage develops, owns and operates, or holds interests in, natural gas and propane pipelines and natural gas storage facilities in the United States and Mexico, and companies that provide natural gas or electricity services in Argentina, Chile, Mexico and Peru. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. Sempra Pipelines & Storage also operates a natural gas distribution utility in Alabama.

In April 2011, Sempra Pipelines & Storage increased its interests in Chile and Peru, as we discuss in Note 12.

5.   Sempra LNG develops, owns and operates receipt terminals for importing LNG into the U.S. and Mexico, and has supply and marketing agreements to purchase and sell LNG and natural gas.

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

Prior to 2011, our Sempra Commodities segment contained our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities), which held commodities-marketing businesses previously owned by us.  Our investment in the partnership is reported on the equity method. We and RBS, our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We discuss these transactions and other matters concerning the partnership in Note 4 above and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

The activity in the partnership no longer meets the quantitative thresholds that require Sempra Commodities to be reported as a reportable segment under applicable generally accepted accounting principles, and we do not consider the remaining wind-down activities of the partnership to be of continuing significance. As a result, effective January 1, 2011, we are reporting the former Sempra Commodities segment in "All other" in the following tables and have restated prior year information to be consistent with this treatment.

Also, in the fourth quarter of 2010, we changed the composition of our reporting segments to include Sempra Rockies Marketing, which was previously included in the Sempra Commodities segment, in the Sempra Generation segment. We have revised segment disclosures for 2010 to reflect this.

The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as "All other" in the following tables consist primarily of parent organizations and the former commodities-marketing businesses.

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended March 31,
	2011				2010
REVENUES
SDG&E	$	840	35	%	$	742	29	%
SoCalGas		1,056	43			1,182	47
Sempra Generation		269	11			318	13
Sempra Pipelines & Storage		109	4			110	4
Sempra LNG		186	8			205	8
Adjustments and eliminations		―	―			3	―
Intersegment revenues(1)		(26)	(1)			(26)	(1)
Total	$	2,434	100	%	$	2,534	100	%
INTEREST EXPENSE
SDG&E	$	36			$	31
SoCalGas		17				17
Sempra Generation		2				4
Sempra Pipelines & Storage		8				9
Sempra LNG		11				12
All other		67				88
Intercompany eliminations		(33)				(52)
Total	$	108			$	109
INTEREST INCOME
Sempra Generation	$	5			$	2
Sempra Pipelines & Storage		2				4
Sempra LNG		1				―
All other		28				50
Intercompany eliminations		(33)				(52)
Total	$	3			$	4
DEPRECIATION AND AMORTIZATION
SDG&E	$	103	44	%	$	92	44	%
SoCalGas		81	35			75	36
Sempra Generation		19	8			15	7
Sempra Pipelines & Storage		13	6			11	5
Sempra LNG		13	6			12	6
All other		2	1			5	2
Total	$	231	100	%	$	210	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	49			$	31
SoCalGas		37				56
Sempra Generation		22				(38)
Sempra Pipelines & Storage		7				6
Sempra LNG		11				12
All other		(17)				(9)
Total	$	109			$	58

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		Three months ended March 31,
		2011				2010
EQUITY EARNINGS
Earnings recorded before tax:
Sempra Generation		$	1			$	―
Sempra Pipelines & Storage			9				10
All other			(9)				5
Total		$	1			$	15
Earnings recorded net of tax:
Sempra Pipelines & Storage		$	31			$	19
EARNINGS (LOSSES)
SDG&E(2)		$	89	35	%	$	83	78	%
SoCalGas(2)			68	26			65	61
Sempra Generation			44	17			(51)	(48)
Sempra Pipelines & Storage			54	21			38	36
Sempra LNG			33	13			32	30
All other			(30)	(12)			(61)	(57)
Total		$	258	100	%	$	106	100	%
EXPENDITURES FOR PROPERTY PLANT & EQUIPMENT
SDG&E		$	348	57	%	$	290	65	%
SoCalGas			168	28			114	26
Sempra Generation			52	9			4	1
Sempra Pipelines & Storage			36	6			36	8
Sempra LNG			3	―			2	―
Total		$	607	100	%	$	446	100	%
		March 31, 2011				December 31, 2010
ASSETS
SDG&E		$	12,390	40	%	$	12,077	40	%
SoCalGas			7,908	26			7,986	26
Sempra Generation			1,905	6			2,401	8
Sempra Pipelines & Storage			5,722	19			5,175	17
Sempra LNG			2,403	8			2,379	8
All other			1,399	4			1,691	6
Intersegment receivables			(1,031)	(3)			(1,426)	(5)
Total		$	30,696	100	%	$	30,283	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra Generation		$	185			$	185
Sempra Pipelines & Storage			1,775				1,777
All other			794				803
Total		$	2,754			$	2,765
(1)	Revenues for reportable segments in 2011 include intersegment revenues of $2 million, $13 million and $11 million for SDG&E, SoCalGas and Sempra Pipelines & Storage, respectively. Revenues for reportable segments in 2010 include intersegment revenues of $1 million, $11 million and $14 million for SDG&E, SoCalGas and Sempra Pipelines & Storage, respectively.
(2)	After preferred dividends.

NOTE 12. SUBSEQUENT EVENT

In January 2011, Sempra Pipelines & Storage agreed to acquire from AEI its interests in Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A. (Luz del Sur) in Peru. At March 31, 2011, Sempra Pipelines & Storage and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur. We completed the transaction on April 6, 2011, and Sempra Pipelines & Storage now owns 100 percent of Chilquinta Energía and approximately 76 percent of Luz del Sur, with the remaining shares of Luz del Sur held by institutional investors and the general public. The purchase price was $875 million (plus working capital adjustments of $13 million), which resulted from valuing the assets in Chile at $490 million and the assets in Peru at $385 million. As part of our acquisition of AEI’s interest in Luz del Sur, we are required to launch a tender offer to the minority shareholders of Luz del Sur to purchase their shares at a price as determined by an independent appraiser.  As part of the transaction, Sempra Pipelines & Storage also acquired AEI’s interests in two energy-services companies, Tecnored S.A. and Tecsur S.A. We provide additional information about Sempra Pipelines & Storage’s investments in Chilquinta Energía and Luz Del Sur in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Due to the limited time since the date of the acquisition, the initial accounting for this business combination is incomplete as of the date of this filing, including updated appraisal information for the acquisition. As such, it is impracticable for us to make certain business combination disclosures at this time, including:

§   the acquisition date fair value of the equity interest we held prior to the acquisition and any estimation of any gain or loss associated with the remeasurement of these equity interests; and

§   amounts to be recognized at the acquisition date for the major classes of assets acquired and liabilities assumed, including pre-acquisition contingencies, goodwill and other intangibles.

We will provide this information in our second quarter 2011 Form 10-Q.

Excluding the impact of purchase accounting to be determined, the incremental revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010 were $343 million and $23 million, respectively, for the three months ended March 31, 2011, and $277 million and $19 million, respectively, for the three months ended March 31, 2010.

We expect the acquisition to be accretive to our EPS in 2011 and beyond, based on historically strong operating performance of the companies within sound regulatory environments and stable and growing countries.

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

You should read the following discussion in conjunction with the financial statements contained in this Form 10-Q, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our 2010 Annual Report on Form 10-K (Annual Report), and "Risk Factors" contained in our Annual Report.

OVERVIEW

Sempra Energy is a Fortune 500 energy services holding company whose business units develop energy infrastructure, operate utilities and provide related products and services to their customers. Our operations are divided principally between the Sempra Utilities and Sempra Global. The Sempra Utilities consist of two California regulated public utility companies, (1) San Diego Gas & Electric Company (SDG&E) and (2) Southern California Gas Company (SoCalGas). Sempra Global consists of other businesses engaged in providing energy products and services.

This report includes information for the following separate registrants:

§   Sempra Energy and its consolidated entities

§   SDG&E

§   Pacific Enterprises (PE), the holding company for SoCalGas

§   SoCalGas

References in this report to "we," "our" and "Sempra Energy Consolidated" are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its context.

PE's operations consist solely of those of SoCalGas and additional items (e.g., cash, intercompany accounts and equity) attributable to serving as a holding company for SoCalGas.

Below are summary descriptions of our operating business units, which are also our reportable segments.

SEMPRA ENERGY BUSINESS UNITS

The Sempra Utilities consist of SDG&E and SoCalGas.

SEMPRA UTILITIES
	MARKET	SERVICE TERRITORY
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E) A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution	§Provides electricity to 3.5 million consumers (1.4 million meters) §Provides natural gas to 3.2 million consumers (850,000 meters)	Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS) A regulated public utility; infrastructure supports natural gas distribution, transmission and storage	§Residential, commercial, industrial, utility electric generation and wholesale customers §Covers a population of 20.9 million (5.8 million meters)	Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles

Sempra Global is a holding company for most of our subsidiaries that are not subject to California utility regulation. Sempra Global's principal business units, which provide energy-related products and services, are

§   Sempra Generation

§   Sempra Pipelines & Storage

§   Sempra LNG

SEMPRA GLOBAL
	MARKET	GEOGRAPHIC REGION
SEMPRA GENERATION Develops, owns and operates, or holds interests in, electric power plants and energy projects	§Wholesale electricity	§U.S.A. §Mexico
SEMPRA PIPELINES & STORAGE Develops, owns and operates, or holds interests in, natural gas and propane pipelines, natural gas storage facilities, and natural gas and electric service providers	§Natural gas §Electricity	§U.S.A. §Mexico §Argentina §Chile §Peru
SEMPRA LNG Develops, owns and operates receipt terminals for importation of liquefied natural gas (LNG) and sale of natural gas	§Liquefied natural gas §Natural gas	§U.S.A. §Mexico §Global

Prior to 2011, our Sempra Commodities segment contained our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities), which held commodities-marketing businesses previously owned by us. Our investment in the partnership is reported on the equity method. We and The Royal Bank of Scotland (RBS), our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We discuss these transactions and other matters concerning the partnership in Note 4 of the Notes to Condensed Consolidated Financial Statements herein and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

The activity in the partnership no longer meets the quantitative thresholds that require Sempra Commodities to be reported as a reportable segment under applicable generally accepted accounting principles, and we do not consider the remaining wind-down activities of the partnership to be of continuing significance. As a result, effective January 1, 2011, we are reporting the former Sempra Commodities segment in Parent and Other, and have restated prior year information to be consistent with this treatment. Also, in the fourth quarter of 2010, we changed the composition of our reporting segments to include Sempra Rockies Marketing, which was previously included in the Sempra Commodities segment, in the Sempra Generation segment.

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

§   Overall results of our operations and factors affecting those results

§   Our business unit results

§   Significant changes in revenues, costs and earnings between periods

In the three months ended March 31, 2011, our earnings increased by $152 million (143%) to $258 million primarily due to:

§   litigation expense recorded in 2010 of $96 million related to an agreement to settle certain energy crisis litigation;

§   improved operating results at Sempra Generation and Sempra Pipelines & Storage; and

§   lower losses at Parent and Other.

Diluted earnings per share for the three-month period increased by $0.65 (155%) per share to $1.07 per share, due to higher earnings ($0.61 per share) and a decrease in the number of shares primarily as a result of our share repurchase program initiated in 2010 ($0.04 per share).

The following table shows our earnings (losses) by business unit, which we discuss below in "Business Unit Results."

SEMPRA ENERGY EARNINGS (LOSSES) BY BUSINESS UNIT
(Dollars in millions)
		Three months ended March 31,
		2011				2010
Sempra Utilities:
SDG&E(1)		$	89	35	%	$	83	78	%
SoCalGas(1)			68	26			65	61
Sempra Global:
Sempra Generation			44	17			(51)	(48)
Sempra Pipelines & Storage			54	21			38	36
Sempra LNG			33	13			32	30
Parent and other(2)			(30)	(12)			(61)	(57)
Earnings		$	258	100	%	$	106	100	%
(1)	After preferred dividends.
(2)	Includes after-tax interest expense ($34 million and $38 million for the three months ended March 31, 2011 and 2010, respectively), results from our former Sempra Commodities segment (losses of $5 million and $7 million for the three months ended March 31, 2011 and 2010, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

BUSINESS UNIT RESULTS

The following section is a discussion of earnings (losses) by business unit, as it appears in the table above.

EARNINGS BY BUSINESS UNIT -- SEMPRA UTILITIES

(Dollars in millions)

SDG&E

SDG&E business unit earnings were

§   $89 million in the first three months of 2011 ($90 million before preferred dividends)

§   $83 million in the first three months of 2010 ($84 million before preferred dividends)

The increase of $6 million (7%) was due to:

§   $5 million higher authorized margin for California Public Utilities Commission (CPUC)-regulated operations and lower operation and maintenance expenses (excluding insurance premiums for wildfire coverage and litigation-related expenses);

§   $3 million due to the write-down of deferred tax assets as a result of a change in U.S. tax law regarding the Medicare Part D subsidy in 2010;

§   $2 million lower litigation reserves; and

§   $2 million higher electric transmission margin; offset by

§   $5 million higher liability insurance premiums for wildfire coverage.

SoCalGas

SoCalGas business unit earnings were

§   $68 million in the first three months of 2011 (both before and after preferred dividends)

§   $65 million in the first three months of 2010 (both before and after preferred dividends)

The increase of $3 million (5%) was primarily due to:

§   $13 million due to the write-down of deferred tax assets as a result of the change in U.S. tax law regarding the Medicare Part D subsidy in 2010; offset by

§   $7 million lower regulatory awards.

EARNINGS (LOSSES) BY BUSINESS UNIT – SEMPRA GLOBAL

(Dollars in millions)

Sempra Generation

Sempra Generation recorded business unit earnings (losses) of:

§   $44 million in the first three months of 2011

§   $(51) million in the first three months of 2010

The increase in earnings of $95 million was due to:

§   $83 million decreased litigation expense primarily related to a 2010 agreement to settle energy crisis litigation, as we discuss in Note 16 of the Notes to Consolidated Financial Statements in the Annual Report; and

§   $11 million lower operation and maintenance costs primarily as a result of 2010 scheduled plant maintenance.

Sempra Pipelines & Storage

Sempra Pipelines & Storage recorded business unit earnings of:

§   $54 million in the first three months of 2011

§   $38 million in the first three months of 2010

The increase of $16 million (42%) was due to:

§   $8 million higher earnings related to a Mexican pipeline acquisition in April 2010;

§   $6 million higher operating results from its investments in Chile and Peru; and

§   $2 million higher earnings primarily related to natural gas storage placed into service in the second half of 2010.

Sempra LNG

Sempra LNG recorded earnings of:

§   $33 million in the first three months of 2011

§   $32 million in the first three months of 2010

Earnings for the first quarter of 2011 were consistent with the first quarter of the prior year. Both years included $11 million of earnings related to contractual counterparty obligations for non-delivery of cargoes.

Parent and Other

Losses for Parent and Other were

§   $30 million in the first three months of 2011

§   $61 million in the first three months of 2010

The decrease in losses of $31 million (51%) included:

§   $19 million lower income tax expense;

§   $12 million energy crisis litigation expense recorded in 2010 related to our former commodities-marketing businesses; and

§   $5 million Mexican peso exchange gain; offset by

§   $5 million equity losses from our former commodities-marketing businesses in 2011 compared to $8 million equity earnings in 2010.

CHANGES IN REVENUES, COSTS AND EARNINGS

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

Sempra Utilities Revenues

Sempra Utilities revenues are comprised of natural gas revenues at SDG&E and SoCalGas, and electric revenues at SDG&E. Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Condensed Consolidated Statements of Operations.

The current regulatory framework permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed on to customers substantially as incurred. However, SoCalGas' Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

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

Sempra Utilities: Natural Gas Revenues and Cost of Natural Gas

The tables below show natural gas revenues for Sempra Energy, SDG&E and SoCalGas for the three-month periods ended March 31, 2011 and 2010. The Sempra Energy Consolidated amounts reflect SDG&E and SoCalGas revenues, net of intercompany transactions. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs.  These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA ENERGY CONSOLIDATED — SEMPRA UTILITIES:
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural Gas Sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
2011:
Residential	104	$	958	1	$	1	105	$	959
Commercial and industrial	34		257	68		65	102		322
Electric generation plants	―		―	45		13	45		13
Wholesale	―		―	9		2	9		2
	138	$	1,215	123	$	81	261		1,296
Other revenues									23
Balancing accounts									(101)
Total								$	1,218
2010:
Residential	97	$	980	1	$	1	98	$	981
Commercial and industrial	35		289	68		62	103		351
Electric generation plants	―		―	41		11	41		11
Wholesale	―		―	7		1	7		1
	132	$	1,269	117	$	75	249		1,344
Other revenues									25
Balancing accounts									(19)
Total								$	1,350

During the three months ended March 31, 2011, our natural gas revenues decreased by $132 million (10%) to $1.2 billion, and the cost of natural gas decreased by $149 million (20%) to $609 million, due primarily to lower natural gas prices in 2011. We discuss the changes in the cost of natural gas individually for SDG&E and SoCalGas below.

SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural Gas Sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
2011:
Residential	12	$	133	―	$	―	12	$	133
Commercial and industrial	5		33	2		3	7		36
Electric generation plants	―		―	5		2	5		2
	17	$	166	7	$	5	24		171
Other revenues									10
Balancing accounts									(6)
Total								$	175
2010:
Residential	12	$	135	―	$	―	12	$	135
Commercial and industrial	4		36	2		3	6		39
Electric generation plants	―		―	6		2	6		2
	16	$	171	8	$	5	24		176
Other revenues									9
Balancing accounts									(6)
Total								$	179

During the three months ended March 31, 2011, SDG&E's natural gas revenues decreased by $4 million (2%) to $175 million, while the cost of natural gas decreased by $6 million (7%) to $83 million compared with the corresponding period in 2010. The average cost of natural gas for the three months ended March 31, 2011 was $4.83 per thousand cubic feet (Mcf) compared to $5.50 per Mcf for the corresponding period in 2010, a 12-percent decrease or $0.67 per Mcf, resulting in lower revenues and cost of $12 million. The decrease due to the lower average cost of natural gas delivered was partially offset by higher demand for natural gas, which resulted in higher revenues and cost of $6 million in 2011.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural Gas Sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
2011:
Residential	92	$	825	1	$	1	93	$	826
Commercial and industrial	29		224	66		62	95		286
Electric generation plants	―		―	40		11	40		11
Wholesale	―		―	43		6	43		6
	121	$	1,049	150	$	80	271		1,129
Other revenues									22
Balancing accounts									(95)
Total(1)								$	1,056
2010:
Residential	85	$	845	1	$	1	86	$	846
Commercial and industrial	31		253	66		59	97		312
Electric generation plants	―		―	35		9	35		9
Wholesale	―		―	44		4	44		4
	116	$	1,098	146	$	73	262		1,171
Other revenues									24
Balancing accounts									(13)
Total(1)								$	1,182
(1) Includes sales to affiliates of $13 million in 2011 and $11 million in 2010.

During the three months ended March 31, 2011, SoCalGas' natural gas revenues decreased by $126 million (11%) to $1.1 billion, and the cost of natural gas decreased by $143 million (21%) to $531 million. The decrease in revenues was primarily due to:

§   the decrease in cost of natural gas, which was caused primarily by lower natural gas prices, as we discuss below; and

§   $12 million lower regulatory awards; offset by

§   $19 million higher recovery of CPUC-authorized costs, which revenues are fully offset in operation and maintenance expenses; and

§   $13 million higher authorized base margin.

The average cost of natural gas for the three months ended March 31, 2011 was $4.36 per Mcf compared to $5.81 per Mcf for the corresponding period in 2010, a 25-percent decrease or $1.45 per Mcf, resulting in lower revenues and cost of $176 million. The decrease due to the lower average cost of natural gas delivered was partially offset by higher demand for natural gas, which resulted in higher revenues and cost of $33 million in 2011.

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

The table below shows electric revenues for Sempra Energy and SDG&E for the three-month periods ended March 31, 2011 and 2010. Sempra Energy Consolidated amounts are net of intercompany transactions. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues.

ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
	2011			2010
Customer class	Volumes	Revenue		Volumes	Revenue
Sempra Energy Consolidated:
Residential	1,959	$	314	1,913	$	276
Commercial	1,669		231	1,595		200
Industrial	490		57	524		56
Direct access	786		36	720		25
Street and highway lighting	27		4	23		3
	4,931		642	4,775		560
Other revenues			25			29
Balancing accounts			(4)			(27)
Total		$	663		$	562
SDG&E:
Residential	1,959	$	314	1,913	$	276
Commercial	1,669		231	1,595		200
Industrial	493		58	527		56
Direct access	786		36	720		25
Street and highway lighting	27		4	23		3
	4,934		643	4,778		560
Other revenues			26			30
Balancing accounts			(4)			(27)
Total(1)		$	665		$	563
(1) Includes sales to affiliates of $2 million in 2011 and $1 million in 2010.

During the three months ended March 31, 2011, electric revenues increased by $101 million (18%) to $663 million at Sempra Energy and by $102 million (18%) to $665 million at SDG&E, primarily due to:

§   $42 million higher recoverable expenses that are fully offset in operation and maintenance expenses;

§   $32 million increase in the cost of electric fuel and purchased power excluding Otay Mesa VIE;

§   $15 million higher authorized base margin on electric generation and distribution; and

§   $5 million higher authorized transmission margin; offset by

§   $11 million decrease due to tolling payments and natural gas supply costs in 2011 associated with the power generated by Otay Mesa.

At both Sempra Energy and SDG&E, the cost of electric fuel and purchased power increased by $23 million (16%) to $171 million in the three months ended March 31, 2011 primarily due to a $32 million increase in fuel and purchased-power costs (excluding Otay Mesa VIE), offset by a $9 million decrease in the cost of power purchased from Otay Mesa VIE.

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

Sempra Global and Parent Revenues and Cost of Sales

During the three months ended March 31, 2011, our Sempra Global and Parent revenues decreased by $69 million (11%) to $553 million. The decrease was primarily due to:

§   $49 million lower revenues at Sempra Generation due to decreased power sales; and

§   $19 million lower revenues at Sempra LNG primarily due to decreased natural gas sales and lower natural gas prices in 2011.

During the three months ended March 31, 2011, our cost of natural gas, electric fuel and purchased power decreased to $263 million. The $75 million (22%) decrease included $51 million at Sempra Generation and $13 million at Sempra LNG, primarily associated with their lower revenues.

Litigation Expense

Sempra Energy Consolidated

In the three months ended March 31, 2010, we recorded litigation expense of $168 million, which included $159 million related to the agreement to settle certain energy crisis litigation.

Other Operation and Maintenance

Sempra Energy Consolidated

For the three months ended March 31, 2011, our other operation and maintenance expenses increased by $56 million (10%) to $632 million. The increase included higher operation and maintenance expenses at SDG&E (discussed below) of $45 million (which excludes the $4 million of lower litigation expense separately reported as Litigation Expense on the Sempra Energy Condensed Consolidated Statements of Operations), and $26 million at SoCalGas, including $19 million higher recoverable expenses.

Operation and Maintenance

SDG&E

For the three months ended March 31, 2011, SDG&E's operation and maintenance expenses increased by $41 million (18%) to $273 million. The increase was primarily due to:

§   $43 million higher recoverable expenses; and

§   $8 million of higher liability insurance premiums for wildfire coverage; offset by

§   $4 million lower litigation reserves.

Other Income, Net

Sempra Energy Consolidated

In the three months ended March 31, 2011, other income, net, increased by $35 million to $43 million primarily due to:

§   $10 million of gains on interest rate and foreign exchange instruments in the first three months of 2011 compared to $9 million losses, all related to Otay Mesa VIE, in the first three months of 2010;

§   $6 million higher allowance for equity funds used during construction attributable to SDG&E; and

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

Income Taxes

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

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended March 31,
		2011				2010
		Income Tax	Effective Income			Income Tax	Effective Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	109	32	%	$	58	42	%
SDG&E		49	34			31	29
PE		37	35			57	47
SoCalGas		37	35			56	46

Sempra Energy Consolidated

The increase in income tax expense in the three months ended March 31, 2011 was due to higher pretax income, offset by a lower effective income tax rate primarily resulting from:

§   a $16 million write-down in 2010 of the deferred tax assets related to other postretirement benefits, as a result of a change in U.S. tax law that eliminates a future deduction, starting in 2013, for retiree healthcare funded by the Medicare Part D subsidy;

§   lower tax expense in 2011 due to Mexican currency translation and inflation adjustments;

§   higher planned investment tax credits;

§   higher exclusions from taxable income of the equity portion of allowance for funds used during construction (AFUDC); and

§   higher deductions for self-developed software costs; offset by

§   lower favorable adjustments related to prior years' income tax issues; and

§   an increase in the amount by which book depreciation for the Sempra Utilities exceeds normalized tax depreciation, which is not treated as a deferred tax asset for ratemaking purposes.

SDG&E

SDG&E's income tax expense increased in the three months ended March 31, 2011 primarily due to higher pretax income and a higher effective income tax rate primarily resulting from:

§   lower favorable adjustments related to prior years’ income tax issues; offset by

§   a $3 million write-down in 2010 of the deferred tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above;

§   the impact of Otay Mesa VIE, as we discuss below; and

§   higher exclusions from taxable income of the equity portion of AFUDC.

Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.

PE and SoCalGas

Income tax expense decreased at PE and SoCalGas primarily due to lower pretax income, as well as lower effective income tax rates primarily due to:

§   a $13 million write-down in 2010 of the deferred tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above; and

§   higher deductions for self-developed software costs; offset by

§   an increase in the amount by which book depreciation exceeds normalized tax depreciation, which is not treated as a deferred tax asset for ratemaking purposes.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010

In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law.  The 2010 Tax Act included the extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 and an increase in the rate of bonus depreciation from 50 percent to 100 percent. This increased rate only applies to certain investments made after September 8, 2010 through December 31, 2012.

Additionally, the 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.) of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. If this rule is not extended beyond 2011, Sempra Energy’s effective income tax rate could potentially increase in subsequent years.

We provide further discussion regarding the 2010 Tax Act in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.

Equity Earnings, Net of Income Tax

Equity earnings, net of income tax, consisting of earnings from Sempra Pipelines & Storage’s equity method investments, were $31 million in the three months ended March 31, 2011 compared to $19 million for the corresponding period in 2010. The increase in 2011 was primarily due to:

§   $7 million in earnings related to the joint-venture interest acquired from El Paso Corporation in April 2010; and

§   $5 million higher earnings from investments in Chile and Peru.

(Earnings) Losses Attributable to Noncontrolling Interests

Sempra Energy Consolidated and SDG&E

Earnings attributable to noncontrolling interests, all related to Otay Mesa VIE, were $4 million in the first quarter of 2011 compared to losses of $8 million in the first quarter of 2010, primarily due to $9 million of losses on interest rate instruments in 2010.

Earnings

We discuss variations in Sempra Energy's earnings (losses) by business unit above in "Business Unit Results."

CAPITAL RESOURCES AND LIQUIDITY

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends.  In addition, we may meet our cash requirements through the issuance of short-term and long-term debt and the expected distributions from RBS Sempra Commodities related to proceeds from the transactions to sell certain businesses within the joint venture, as we discuss below.

Our committed lines of credit provide liquidity and support commercial paper.  As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global and the Sempra Utilities each have four-year revolving credit facilities, expiring in 2014. At Sempra Energy and Sempra Global, the agreements are syndicated broadly among 23 different lenders and at the Sempra Utilities, among 22 different lenders.  No single lender has greater than a 7-percent share in any facility.

The table below shows the amount of available funds at March 31, 2011:

AVAILABLE FUNDS AT MARCH 31, 2011
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		PE/SoCalGas
Unrestricted cash and cash equivalents		$	1,219	$	272	$	33
Available unused credit(1)			2,771		363		563
(1)	Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $600 million for each utility and $800 million in total. SDG&E's available funds reflect variable-rate demand notes outstanding of $237 million supported by the line. SoCalGas' availability reflects the impact of SDG&E's use of the combined credit available on the line.

Sempra Energy Consolidated

We believe thatthese available funds and cash flows from operations, distributions from equity method investments andsecurity issuances, combined with current cash balances, will be adequate to:

§   finance capital expenditures

§   meet liquidity requirements

§   fund shareholder dividends

§   fund new business acquisitions or start-ups

In March 2011, Sempra Energy publicly offered and sold $500 million of 2-percent notes and $300 million of floating rate notes, both maturing in 2014. SDG&E and SoCalGas issued long-term debt in 2010 in the aggregate principal amounts of $750 million and $300 million, respectively. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. If cash flows from operations were to be significantly reduced or we were to be unable to borrow under acceptable terms, we would reduce or postpone discretionary capital expenditures and investments in new businesses. If these measures were necessary, they would primarily impact our Sempra Global businesses, as credit availability for the Sempra Utilities has not been significantly impacted by the credit crisis. Discretionary expenditures at Sempra Global include projects that we have not yet made firm commitments to build, primarily renewable generation facilities. We continuously monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.

In three separate transactions during 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our joint-venture partnership that comprised our commodities-marketing businesses. As we conclude the transactions to divest the businesses, we expect to recover our remaining $779 million investment in the partnership throughout 2011, including $329 million received in April 2011. We are providing transitional back-up guarantees, some of which may continue for a prolonged period of time. RBS or JP Morgan, one of the buyers in the sales transactions, have fully indemnified us for any claims or losses in connection with the related transactions.

We provide additional information about RBS Sempra Commodities and the sales transactions and guarantees in Notes 4 and 6 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 3, 4, 5 and 16 of the Notes to Consolidated Financial Statements in the Annual Report.

We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. The value of the trust funds’ investments declined in 2008 and the first quarter of 2009 due to a decrease in the equity market and volatility in the fixed income market. Values increased from favorable market activity later in 2009 and in 2010. However, these markets continue to be volatile. The changes in asset values have not affected the trust funds’ abilities to make required payments, but may impact funding requirements for pension and other postretirement benefit plans. At the Sempra Utilities, funding requirements are generally recoverable in rates.

We discuss our principal credit agreements more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Utilities

SoCalGas expects that cash flows from operations and debt issuances will continue to be adequate to meet its capital expenditure requirements. In March 2011, Sempra Energy made a $200 million capital contribution to SDG&E, and SDG&E expects its cash flows from operations and debt issuances will be adequate to meet its future capital expenditure requirements.

SoCalGas declared and paid a $50 million common dividend to PE in 2011 and a $100 million common dividend in 2010. PE paid corresponding dividends to Sempra Energy in both years. In 2009, SDG&E declared and paid a $150 million common dividend to Sempra Energy.

However, the level of future common dividends from SDG&E and SoCalGas may be reduced or eliminated during periods of increased capital expenditures. The level of future common dividends from PE is dependent upon common dividends paid by SoCalGas. Sempra Energy may from time to time make additional equity contributions to SDG&E and SoCalGas to support the Sempra Utilities’ capital expenditure programs.

Sempra Generation

We expect Sempra Generation to require funds for the development of electric generation facilities, primarily renewable energy projects. Projects at Sempra Generation may be financed through a combination of operating cash flow, project financing, funds from the parent, external borrowings, partnering in joint ventures and the sale of its El Dorado natural gas power plant to SDG&E on October 1, 2011. Cash flows from operations at Sempra Generation are expected to decrease upon the expiration of its contract with the DWR in September 2011, due to less favorable pricing on replacement contracts, and the sale of El Dorado. Also, Sempra Generation may not be able to replace all of the lost revenue.

Some of Sempra Generation's long-term power sale contracts contain collateral requirements, although the DWR contracts do not contain such requirements. The collateral arrangements require 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 if Sempra Generation fails to deliver the contracted amounts. Sempra Generation had no outstanding collateral requirements under such contracts at March 31, 2011.

Sempra Pipelines & Storage

Sempra Pipelines & Storage is expected to require funding from the parent or from external sources to fund projects and investments, including development and expansion of its natural gas storage projects.

In April 2011, Sempra Pipelines & Storage acquired AEI’s interests in Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A. (Luz del Sur) for $875 million plus working capital adjustments of $13 million. This transaction was funded with excess funds from foreign operations, proceeds from divestitures and short-term debt.

We provide additional information about Sempra Pipelines & Storage’s investments in Chilquinta Energía and Luz del Sur in Note 12 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 4 and 19 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra LNG

We expect Sempra LNG to provide operating cash flow for further development within Sempra Global from the operations of its two LNG receipt terminals, Energía Costa Azul and Cameron.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	2011		2011 Change				2010
Sempra Energy Consolidated	$	805	$	(83)	(9)	%	$	888
SDG&E		501		226	82			275
PE		380		(112)	(23)			492
SoCalGas		371		(130)	(26)			501

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy decreased in 2011 primarily due to:

§   a $161 million decrease in accounts receivable in 2010, primarily at SoCalGas; and

§   $37 million of income tax payments in 2011 compared to $73 million of  income tax refunds in 2010; offset by

§   $185 million higher net income, adjusted for noncash items, in 2011 compared to 2010.

Other working capital changes in 2011 compared to 2010 reflect $300 million of funds received from a wildfire litigation settlement, offset by a $229 million reduction in accrued liabilities for the payment in 2011 of wildfire settlement claims ($99 million) and the settlement paid related to energy crisis litigation ($130 million), as well as the accrual of the latter in the first quarter of 2010.

SDG&E

Cash provided by operating activities at SDG&E increased in 2011 primarily due to:

§   $300 million of funds received from a wildfire litigation settlement, which is offset by an increase in restricted cash in cash flows from investing activities; and

§   $79 million higher net income, adjusted for noncash items, in 2011 compared to 2010; offset by

§   $99 million in settlement payments of accrued liabilities for the 2007 wildfires from our restricted funds in 2011, compared to $9 million net receipts from our liability insurance carriers in 2010 related to the 2007 wildfire litigation.

PE and SoCalGas

Cash provided by operating activities at PE and SoCalGas decreased in 2011 primarily due to:

§   an $89 million decrease in accounts receivable in 2010, primarily due to lower volumes and cost of natural gas billed; and

§   a $75 million decrease in accounts payable in 2011, primarily due to lower volumes and prices of natural gas purchased; offset by

§   $40 million higher net income, adjusted for noncash items, in 2011 compared to 2010.

The table below shows the contributions to pension and other postretirement benefit plans for the three months ended March 31, 2011.

			Other
	Pension		Postretirement
(Dollars in millions)	Benefits		Benefits
Sempra Energy Consolidated	$	11	$	19
SDG&E		―		4
PE/SoCalGas		1		14

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	2011		2011 Change				2010
Sempra Energy Consolidated	$	(756)	$	260	52	%	$	(496)
SDG&E		(552)		252	84			(300)
PE		(463)		203	78			(260)
SoCalGas		(455)		185	69			(270)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2011 primarily due to:

§   a $300 million increase in restricted cash due to funds received from a wildfire litigation settlement; and

§   a $161 million increase in capital expenditures; offset by

§   $99 million in payments for claims related to wildfire litigation using restricted funds received from a wildfire litigation settlement; and

§   lower contributions to Rockies Express. The $65 million contribution in the first quarter of 2010 was the last required for the construction phase of the project.

SDG&E

Cash used in investing activities at SDG&E increased in 2011 primarily due to:

§   a $300 million increase in restricted cash due to funds received from a wildfire litigation settlement; and

§   a $58 million increase in capital expenditures; offset by

§   $99 million in payments for claims related to wildfire litigation using restricted funds received from a wildfire litigation settlement.

PE and SoCalGas

Cash used in investing activities at PE and SoCalGas increased in 2011 primarily due to $131 million higher increase in advances from SoCalGas to Sempra Energy.

FUTURE CONSTRUCTION EXPENDITURES AND INVESTMENTS

The amounts and timing of capital expenditures are generally subject to approvals by the CPUC, the Federal Energy Regulatory Commission (FERC) and other regulatory bodies. However, in 2011, we expect to make capital expenditures and investments of approximately $3.8 billion, net of transferring Sempra Generation’s El Dorado facility to SDG&E. These expenditures include:

§   $2.6 billion at the Sempra Utilities for capital projects and plant improvements ($1.9 billion at SDG&E and $720 million at SoCalGas)

§   $1.4 billion at our other subsidiaries for the acquisition of AEI’s interests in Chile and Peru, development of natural gas storage facilities and pipelines, and renewable generation projects

The Sempra Utilities expect the $2.6 billion of capital expenditures to include:

§   $780 million for additions to SDG&E’s natural gas and electric distribution systems, advanced metering infrastructure, and electric generation plant and equipment

§   $680 million at SDG&E for the Sunrise Powerlink transmission line

§   $220 million for improvements to SDG&E’s electric transmission infrastructure

§   $200 million for the transfer of Sempra Generation’s El Dorado facility to SDG&E

§   $720 million at SoCalGas for improvements to distribution and transmission systems, and for advanced metering infrastructure

The Sempra Utilities expect to finance these expenditures and investments with cash flows from operations, cash on hand, debt issuances and at SDG&E, capital contributed by Sempra Energy.

The expected capital expenditures of $1.4 billion at our other subsidiaries include

Sempra Pipelines & Storage

§   approximately $875 million to acquire AEI’s interests in Chile and Peru

§   approximately $100 million to $150 million for capital projects in South America in the second half of 2011

§   approximately $100 million to $150 million for development of natural gas storage projects at Bay Gas and Mississippi Hub

Sempra Generation

§   approximately $100 million for investment in the first phase (150 megawatts (MW)) of Mesquite Solar, a solar project at our Mesquite Power plant near Arlington, Arizona

Our level of capital expenditures and investments in the next few years may vary substantially and will depend on the cost and availability of financing, regulatory approvals and business opportunities providing desirable rates of return. We intend to finance our capital expenditures in a manner that will maintain our strong investment-grade ratings and capital structure.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	2011		2011 Change				2010
Sempra Energy Consolidated	$	258	$	538	192	%	$	(280)
SDG&E		196		170	654			26
PE		(301)		(200)	(198)			(101)
SoCalGas		(300)		(200)	(200)			(100)

Sempra Energy Consolidated

Cash provided by financing activities at Sempra Energy increased in 2011 primarily due to:

§   $791 million higher issuances of long-term debt; and

§   $247 million lower debt payments; offset by

§   a $192 million decrease in short-term debt in 2011 compared to a $294 million increase in 2010.

SDG&E

Cash provided by financing activities at SDG&E increased in 2011 primarily due to a $200 million capital contribution from Sempra Energy in 2011; offset bya $27 million increase in short-term debt in 2010.

PE and SoCalGas

Cash used in financing activities at PE and SoCalGas increased in 2011 primarily due to:

§   a $250 million long-term debt payment at SoCalGas in 2011; and

§   $50 million in common dividends paid in 2011; offset by

§   $100 million in common dividends paid in 2010.

COMMITMENTS

We discuss significant changes to contractual commitments at Sempra Energy, SDG&E, PE and SoCalGas in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy and its principal subsidiaries remained at investment grade levels during the first quarter of 2011.

We provide additional information about our credit ratings at Sempra Energy, SDG&E, PE and SoCalGas in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

FACTORS INFLUENCING FUTURE PERFORMANCE

SEMPRA ENERGY OVERVIEW

The Sempra Utilities' operations generally provide relatively stable earnings and liquidity. However, for the next few years, SDG&E and SoCalGas intend to limit their common stock dividends to reinvest their earnings in significant capital projects.

Long-term contracts at Sempra Global's businesses generally provide relatively stable earnings and liquidity, but are subject to variability due to fluctuations in commodity prices. Also, Sempra Generation's contract with the DWR, which provides a significant portion of Sempra Generation's revenues, ends in September 2011, and Sempra Generation will sell its El Dorado natural gas generation plant to SDG&E on October 1, 2011. Based on current market prices for electricity, contracts it enters into to replace the DWR contract, if obtained, or merchant (daily) sales will provide substantially lower earnings. Sempra Generation is also undertaking and investing in several projects for the construction of renewable generation facilities, with planned in-service dates ranging from mid-2011 to 2013.

On April 6, 2011, Sempra Pipelines & Storage increased its investment in two utilities in South America. We expect the acquisition to be accretive to our earnings per share. We discuss the acquisition in Note 12 of the Notes to Condensed Consolidated Financial Statements herein. Sempra Pipelines & Storage is also expected to provide earnings from construction projects when completed and other investments, but will require substantial funding for these investments.

At Sempra LNG, until there are firm LNG supply or capacity services contracts from third parties that would subscribe to 100 percent of the capacity of Sempra LNG's Cameron receipt terminal, Sempra LNG will seek to purchase short-term LNG supplies and sell short-term capacity, which may result in greater variability in revenues and earnings.

The Sempra Utilities' performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature to address the state budget crisis and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss in various sections of this report. In the third quarter of 2009, SDG&E's liability insurance premiums increased significantly, by approximately $40 million (pretax) annually, due to the increased costs of wildfire liability coverage as compared to the previous policy year. In the third quarter of 2010, SDG&E secured additional insurance coverage of approximately $560 million, providing SDG&E with maximum loss recovery due to a wildfire incident from insurance carriers of approximately $960 million, with the remainder of Sempra Energy's business units' maximum coverage for a wildfire incident remaining at $400 million, the same as in the previous policy year. As a result of the increase in SDG&E's wildfire liability insurance coverage in the third quarter of 2010, SDG&E's insurance premiums increased by approximately $30 million (pretax) annually for the increased coverage.

In regard to the 2007 wildfire litigation, SDG&E's settlement of claims and the estimate of outstanding claims and legal fees is approximately $1.9 billion, which is in excess of the $1.1 billion of liability insurance coverage and the $444 million of proceeds received as a result of the settlement with Cox Communications. However, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from other potentially responsible parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. However, SDG&E’s cash flow may be adversely affected by timing differences between the resolution of claims and recoveries from other potentially responsible parties and utility customers, which may extend over a number of years. In addition, recovery from customers will require future regulatory actions, and a failure to obtain recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy's and SDG&E's cash flows and results of operations.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries from other potentially responsible parties and utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory asset as additional information becomes available. We provide additional information concerning these matters in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14, 15 and 16 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Southern California Edison (SCE) and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC). SCE is currently addressing a number of regulatory and performance issues at SONGS, and the NRC has required SCE to take actions to provide greater assurance of compliance by SONGS personnel. SCE continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, the likelihood of further required action by SCE persists, which may result in increased SONGS operating costs and/or adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E’s Operation and Maintenance Expense, with any increase being fully offset in Operating Revenues – Electric or, if electric generation is adversely impacted, require SDG&E to procure additional electricity supply from other sources.

In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the recent earthquake and tsunami, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The lessons learned from the events in Japan and the results of the NRC reviews may impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS. We provide more information about SONGS in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 6, 14 and 16 of the Notes to Consolidated Financial Statements in the Annual Report.

Pending the outcome of the various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the Sempra Utilities, may incur incremental expense and capital investment associated with its natural gas pipeline operations and investments. If incremental expense and capital investment is required by either SDG&E or SoCalGas, we would expect to file a request with the CPUC to recover any incremental expenses incurred from our customers in rates and to request any capital investment required above what is approved and authorized in our 2012 GRC application as incremental rate base. We provide more information in “Natural Gas Pipeline Operations Safety Assessments” in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

Both SDG&E and SoCalGas have filed their 2012 GRC applications with the CPUC to establish their authorized revenue requirements for the 2012 Test Year and the ratemaking mechanisms to update the authorized revenue on an annual basis over the subsequent three-year (2013-2015) period. Since these applications were filed, Congress passed the 2010 Tax Act which, among other things, included provisions for companies to elect bonus depreciation on certain investments made after September 8, 2010 through December 31, 2012 for federal income tax purposes. The use of bonus depreciation, while reducing cash tax obligations in the near term, results in incremental deferred tax liabilities which reduce both SDG&E's and SoCalGas' rate base upon which authorized revenue requirements are determined. In March 2011, the Internal Revenue Service issued technical guidance on the application of the bonus depreciation provisions of the 2010 Tax Act. SDG&E and SoCalGas are currently analyzing how this guidance will impact the federal income tax depreciation deductions the companies expect to claim for 2011, as well as quantifying the incremental deferred federal income tax liabilities generated. After applying the incremental deferred tax liabilities to each company’s rate base, assuming all other factors in the 2012 GRC application remain the same, it will result in revenue requirements that are less than what the companies have requested in their 2012 GRC applications.

The scoping memo issued by the CPUC in March 2011 set a final decision on the GRC to be issued around the month of March 2012, with retroactive application to allow recovery of SDG&E's and SoCalGas' authorized 2012 revenue requirements to January 1, 2012. If the CPUC's final decision grants a significantly lower authorized revenue requirement, it could result in an adverse effect to the Sempra Utilities' cash flows and results of operations starting in 2012. We provide more information about the GRC in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E's next CPUC cost of capital proceeding is scheduled to be filed in April 2012 for a 2013 test year. SoCalGas has also requested to file its next CPUC cost of capital proceeding on the same schedule as SDG&E. A cost of capital proceeding determines the authorized capital structure, authorized rate of return and authorized rate for recovery of debt service costs on SDG&E's electric distribution and generation assets and on both companies' natural gas transmission and distribution assets. SDG&E's and SoCalGas' current CPUC authorized return on equity (ROE) is 11.10 percent and 10.82 percent, respectively, with authorized common equity capital structures of 49.00 percent and 48.00 percent, respectively. If the proceedings result in either a reduction in the authorized ROE or in the authorized common equity capital structure, it would have an adverse effect on the respective company's cash flows and results of operations starting in 2013. Also, to the extent that either company's authorized rate for recovery of debt service costs is higher than their actual rate of debt service costs at the time of the cost of capital proceeding, the authorized rate for recovery of debt service costs will be reduced to the actual rate of debt service costs, which would adversely affect the respective company's cash flows and results of operations starting in 2013. We provide more information about the cost of capital proceedings in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

The current FERC formulaic rate methodology for SDG&E's electric transmission assets will be up for review in 2013, with the new rates effective in September 2013. This proceeding will assess the rate-making methodology to be employed for SDG&E's FERC-regulated operations, including a determination of SDG&E's FERC-authorized ROE and recovery of operations and maintenance expenses. If this proceeding results in a reduction from SDG&E's current authorized ROE of 11.35 percent or in an adverse determination for the recovery of operations and maintenance expenses, it would adversely affect SDG&E's cash flows and results of operations.

We discuss additional potential and expected impacts of the 2010 Tax Act on our income tax expense, earnings and cash flows in "Results of Operations  – Changes in Revenues, Costs and Earnings  – Income Taxes" above.

In three separate transactions in 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our commodities-marketing partnership. We expect our share of the remaining proceeds from the sales of all of the joint venture's businesses and related cash distributions to approximate $779 million, of which $329 million was received in April 2011. We provide additional information in Notes 4 and 6 of the Notes to Condensed Consolidated Financial Statements herein.

We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar has fluctuated significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. North American natural gas prices, which affect profitability at Sempra Generation and Sempra LNG, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability.

We discuss additional matters that could affect our future performance in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14, 15 and 16 of the Notes to Consolidated Financial Statements in the Annual Report.

FINANCIAL DERIVATIVES REFORMS

In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

SEMPRA UTILITIES – INDUSTRY DEVELOPMENTS AND CAPITAL PROJECTS

We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect our business in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA GLOBAL INVESTMENTS

As we discuss in "Cash Flows From Investing Activities," our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in "Capital Resources and Liquidity" herein and “Capital Resources and Liquidity” and “Factors Influencing Future Performance” in the Annual Report.

Sempra Generation

Mesquite Solar

Mesquite Solar is a photovoltaic generation facility under development by Sempra Generation in Maricopa County, Arizona. When fully developed, the project will be capable of producing approximately 400 MW to 700 MW of solar power. Mesquite Solar will connect to the 500-kilovolt Hassayampa switchyard via our existing Mesquite Power natural gas generation plant.

Construction of the first phase (Mesquite Solar 1) of 150 MW is expected to begin in June 2011 and be completed in early 2013. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years, which contract was approved by the CPUC in April 2011.

Auwahi Wind

In April 2011, Sempra Generation entered into a 20-year contract with Maui Electric Company to provide 21 MW of wind energy from the Auwahi Wind project in the southeastern region of Maui. The contract is subject to approval by the Hawaii Public Utilities Commission. We expect construction on the project to begin in early 2012, and the project to be fully operational in late 2012.

Energía Sierra Juárez

In April 2011, San Diego Gas & Electric entered into a 20-year contract for renewable power supplied from the 156-MW first phase of Sempra Generation’s Energía Sierra Juárez wind project in Baja California, Mexico. The contract is subject to approval by the CPUC and FERC. We expect construction on the project to begin in 2012, and the project to be fully operational in 2013.

Sempra Generation intends to develop the project within the framework of a joint venture, and is working on a joint development agreement for the sale of a 50-percent partnership interest in the current phase of the project to BP Wind Energy.

Sempra Pipelines & Storage

Natural Gas Storage Projects

Currently, Sempra Pipelines & Storage has 23 billion cubic feet (Bcf) of operational working natural gas storage capacity. We plan to develop as much as 75 Bcf of total storage capacity by 2015.

Sempra Pipelines & Storage’s natural gas storage facilities and projects include

§   Bay Gas Storage Company, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Pipelines & Storage owns 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.

§   Mississippi Hub storage facility, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.

§   Liberty Gas Storage Expansion, a salt cavern development project in Cameron Parish, Louisiana. Sempra Pipelines & Storage owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.

South American Utilities

We discuss the increase in Sempra Pipelines & Storage’s investments in Chile and Peru in April 2011 in Note 12 of the Notes to Condensed Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.

INTEREST RATE RISK

The table below shows the nominal amount and the one-year VaR for long-term debt, excluding commercial paper classified as long-term debt and capital lease obligations, at March 31, 2011 and December 31, 2010:

	Sempra Energy
	Consolidated				SDG&E				PE/SoCalGas
	Nominal		One-Year		Nominal		One-Year		Nominal		One-Year
(Dollars in millions)	Debt		VaR(1)		Debt		VaR(1)		Debt		VaR(1)
At March 31, 2011:
Utility fixed-rate	$	4,017	$	478	$	2,705	$	358	$	1,312	$	120
Utility variable-rate		598		34		598		34		―		―
Non-utility, fixed-rate and variable-rate		4,255		304		―		―		―		―
At December 31, 2010:
Utility fixed-rate	$	4,117	$	787	$	2,704	$	587	$	1,413	$	200
Utility variable-rate		751		59		601		59		150		―
Non-utility, fixed-rate and variable-rate		3,459		509		―		―		―		―
(1) After the effects of interest rate swaps.

At March 31, 2011, the net notional amount of interest rate swap transactions ranged from $15 million to $305 million at Sempra Energy (ranges relate to amortizing notional amounts).  We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.

FOREIGN CURRENCY RATE RISK

We discuss our foreign currency rate risk in detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report. At March 31, 2011, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2010.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E, PE and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.

Under the supervision and with the participation of management, including the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E, PE and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2011, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E, PE and SoCalGas concluded that their respective company's disclosure controls and procedures were effective at the reasonable assurance level.

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and Notes 14, 15 and 16 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein and in the Annual Report.

ITEM 1A. RISK FACTORS

There have not been any material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

On September 21, 2010, we entered into a Collared Accelerated Share Acquisition Program with JPMorgan Chase Bank, National Association under which we prepaid $500 million to repurchase shares of our common stock, as we discuss in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

The following table sets forth information concerning purchases made by us, from the program authorized above, of our common stock during the first quarter of 2011:

						Maximum
					Total Number of	Dollar Value of
		Total			Shares Purchased as	Shares that May
		Number	Average		Part of Publicly	Yet Be Purchased
		of Shares	Price Paid		Announced Plans	Under the Plans
		Purchased (1)	Per Share (1)		or Programs (1)	or Programs
March 2011		1,496,435	$	52.22	1,496,435
		1,496,435			1,496,435	$500 million remaining (2)
(1)	Our publicly announced Collared Accelerated Share Acquisition Program, which began in September 2010, was completed in March 2011. A total of 9,574,435 shares were purchased at a weighted average price of $52.22 per share under this program, including 1,496,435 shares received in March 2011. Additional information regarding the program is provided in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
(2)	Our board of directors has authorized the repurchase of shares of our common stock provided that the amounts expended for such purposes do not exceed the greater of $2 billion or amounts expended to purchase no more than 40 million shares. We prepaid $500 million under a Collared Accelerated Share Acquisition Program with JPMorgan Chase Bank, National Association in September 2010 and expended an additional $1 billion pursuant to a share repurchase program completed in 2008. Therefore, approximately $500 million remains authorized by the board for the purchase of additional shares. We also may, from time to time, purchase shares of our common stock from restricted stock plan participants who elect to sell a sufficient number of vesting restricted shares to meet minimum statutory tax withholding requirements.

ITEM 6. EXHIBITS

The exhibits filed under Forms 8-K that are incorporated herein by reference were filed under Commission File Number 1-14201 (Sempra Energy).

The following exhibits relate to each registrant as indicated.

EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra Energy
10.1	Letter Agreement, dated as of April 15, 2011, by and among The Royal Bank of Scotland plc, Sempra Energy, Sempra Commodities, Inc. and Sempra Energy Holdings VII B.V. (Sempra Energy Form 8-K/A filed on April 15, 2011, Exhibit 10.1).
10.2	Form of Sempra Energy 2008 Long Term Incentive Plan, 2011 Performance-Based Restricted Stock Unit Award.
Sempra Energy / Pacific Enterprises
10.3	Fourth Amendment to Indemnity Agreement, dated as of April 15, 2011, by and among The Royal Bank of Scotland plc, Sempra Energy, Pacific Enterprises and Enova Corporation (Sempra Energy Form 8-K filed on April 15, 2011, Exhibit 10.2).
Sempra Energy / San Diego Gas & Electric Company
10.4	Amended and Restated Operating Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.
10.5	Amended and Restated Servicing Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.
EXHIBIT 12 – STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1	Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
San Diego Gas & Electric Company
12.2	San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Pacific Enterprises
12.3	Pacific Enterprises Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Southern California Gas Company
12.4	Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1	Statement of Sempra Energy's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2	Statement of Sempra Energy's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3	Statement of San Diego Gas & Electric Company's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4	Statement of San Diego Gas & Electric Company's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Pacific Enterprises
31.5	Statement of Pacific Enterprises’ Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.6	Statement of Pacific Enterprises’ Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.7	Statement of Southern California Gas Company's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.8	Statement of Southern California Gas Company's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1	Statement of Sempra Energy's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2	Statement of Sempra Energy's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3	Statement of San Diego Gas & Electric Company's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.4	Statement of San Diego Gas & Electric Company's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Pacific Enterprises
32.5	Statement of Pacific Enterprise's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.6	Statement of Pacific Enterprise's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.7	Statement of Southern California Gas Company's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.8	Statement of Southern California Gas Company's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES
Sempra Energy:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SEMPRA ENERGY, (Registrant)
Date: May 9, 2011	By:  /s/ Joseph A. Householder
	Joseph A. Householder Senior Vice President, Controller and Chief Accounting Officer

San Diego Gas & Electric Company:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)
Date: May 9, 2011	By:  /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Pacific Enterprises:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	PACIFIC ENTERPRISES, (Registrant)
Date: May 9, 2011	By:  /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Southern California Gas Company:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)
Date: May 9, 2011	By:  /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

EX-10

SEMPRA ENERGY

2008 LONG TERM INCENTIVE PLAN

2011 PERFORMANCE-BASED RESTRICTED STOCK UNIT AWARD

You have been granted a performance-based restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below.  The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned and will be subject to forfeiture unless and until they vest based upon the satisfaction of total shareholder return performance criteria for a performance period beginning on January 1, 2011 and ending in January 2015.   Shares of Common Stock will be distributed to you after the completion of the performance period ending in January 2015, if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year 2011 Restricted Stock Unit Award Agreement and in the prospectus for the Sempra Energy 2008 Long Term Incentive Plan, which is enclosed.  The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
		SUMMARY
Date of Award:	January 3, 2011
Name of Recipient:
Recipient’s Employee Number:
Number of Restricted Stock Units (prior to any dividend equivalents):
At Target:
At Maximum (150% of Target)
Award Date Fair Market Value per Share of Common Stock:	$52.46
Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award.  Your restricted stock units are not shares of Common Stock.  The target number of restricted stock units will vest (as described below), if the target total shareholder return (a return at the 50th percentile) is achieved.  If above target total shareholder return is achieved, you may vest in up to the maximum number of restricted stock units.
Vesting/Forfeiture of Restricted Stock Units:
Your restricted stock units will vest only upon and only to the extent that the Compensation Committee determines and certifies that Sempra Energy has met specified total shareholder return performance criteria for the performance period beginning on January 1, 2011 and ending at the close of trading on the first New York Stock Exchange trading day of 2015.  Any restricted stock units that do not vest upon the Compensation Committee's determination and certification will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Your restricted stock units also may be forfeited if your employment terminates.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units.  Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award.  Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock).  The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan.  Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest.  The shares will be distributed to you after the completion of the performance period ending in January 2015 and the Compensation Committee’s determination and certification of Sempra Energy’s total shareholder return for the performance period.  The shares of Common Stock will include the additional shares to be distributed pursuant to your dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
To accept your award you must sign the accompanying copy of this page and promptly return it to Sempra Energy.  By doing so, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year 2011 Restricted Stock Unit Award Agreement and the Sempra Energy 2008 Long Term Incentive Plan.

Recipient:	X
	(Signature)
Sempra Energy:	/s/  Donald E. Felsinger
	(Signature)
Title:	Chairman & Chief Executive Officer

SEMPRA ENERGY

2008 LONG TERM INCENTIVE PLAN

Year 2011 Restricted Stock Unit Award Agreement

Award:	You have been granted a performance-based restricted stock unit award under Sempra Energy’s 2008 Long Term Incentive Plan.  The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below).   Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award.  Your restricted stock units are not shares of Common Stock. Each restricted stock unit represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions.   Your restricted stock units (and dividend equivalents) will vest only upon and only to the extent that the Compensation Committee of Sempra Energy's Board of Directors determines and certifies that Sempra Energy has met specified total shareholder return criteria for the performance period beginning January 1, 2011 and ending in January 2015.  Any restricted stock units (and dividend equivalents) that do not vest upon the Compensation Committee's determination and certification will be forfeited. Your restricted stock units (and dividend equivalents) also may be forfeited if your employment terminates before they vest. See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Your restricted stock units (and dividend equivalents, as described below) will vest only upon and only to the extent that the Compensation Committee of Sempra Energy's Board of Directors determines and certifies that Sempra Energy has met the following total shareholder return performance criteria for the performance period beginning on January 1, 2011 and ending on the close of trading on the first New York Stock Exchange trading day of 2015: §  The percentage of your target number of restricted stock units that vest will be determined as follows, based on the percentile ranking for the performance period (as measured at the end of the performance period) of Sempra Energy’s cumulative total shareholder return (consisting of per share appreciation in Common Stock plus dividends and other distributions paid on Common Stock) among the companies (ranked by cumulative total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee. Sempra Energy Total Shareholder Percentage of Target Return Percentile Number of Restricted        Ranking Stock Units that Vest 75th 150% 70th 140% 65th 130% 60th 120% 55th 110% 50th 100% 45th 70% 40th   40% 35th 0 If the percentile ranking does not equal a ranking shown in the above table, the percentage of your target number of restricted stock units that vest will be determined by a linear interpolation between the next lowest percentile shown in the table and the next highest percentile shown on the table. o If the percentile ranking is at or above the 75th percentile, 150% of your target number of restricted stock units will vest. o If the percentile ranking is at or below the 35th percentile, none of your restricted stock units will vest. · The Compensation Committee also will determine and certify the percentile ranking of Sempra Energy’s cumulative total shareholder return  for the performance period (as measured at the end of the performance period) among the companies (ranking by cumulative total shareholder returns) in the S&P 500 Composite Index.  If the Compensation Committee determines and certifies that Sempra Energy’s cumulative total shareholder return is at or above the 50th percentile among the companies in the S&P 500 Composite Index, the percentage of your target number of restricted stock units that vest will be not less than 100%. · As soon as reasonably practicable following the end of the performance period, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the performance criteria and the extent, if any, as to which your restricted stock units have then vested.  You will receive the number of shares of Common Stock equal to the number of your vested restricted stock units after the Compensation Committee’s determination and certification.  Also, you will receive the number of shares of Common Stock equal to your dividend equivalents after the Compensation Committee’s determination and certification.  Certificates for the shares will be issued to you or transferred to an account that you designate.  When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate.    · Examples illustrating the application of the vesting provisions are shown in Exhibit A to this Award Agreement.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units.  Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award.  Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock).  The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan.   Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units.  They will vest when your restricted stock units vest. Also, your restricted stock units (and dividend equivalents) will be adjusted to reflect stock dividends on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2008 Long Term Incentive Plan.   Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units.
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock.  You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2008 Long Term Incentive Plan.
Distribution of Shares:	As described in “Vesting/Forfeiture” above, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the performance criteria and the extent, if any, as to which your restricted stock units have then vested. You will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested.  However, in no event will you receive under this award, and other awards granted to you under the 2008 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2008 Long Term Incentive Plan.  Also, you will receive the number of shares of Common Stock equal to your dividend equivalents after the Compensation Committee’s determination and certification. You will receive the shares as soon as practicable following the Compensation Committee’s determination and certification (and in no event later than March 15, 2015).  Once you receive the shares of Common Stock, your vested and unvested restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
§ Termination:	If your employment with Sempra Energy and its subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) (other than under the circumstances set forth in the next paragraph), all of your restricted stock units (and dividend equivalents) will be forfeited.  The vesting of your restricted stock units does not occur until the date of the Compensation Committee’s determination and certification described above. If your employment terminates, other than by Termination for Cause, and you had both completed five years of continuous service with Sempra Energy and its subsidiaries AND met any of the following conditions: 1.) your employment terminates after December 31, 2011 and at the date of termination you had  attained age 55; or 2.) your employment terminates after November 30, 2011 and at the date of termination you had attained age 62; or 3.) at the date of termination you had attained age 65 and you were an officer subject to the company’s mandatory retirement policy; your restricted stock units (and dividend equivalents) will not be forfeited but will continue to be subject to the transfer restrictions and vesting conditions and other terms and conditions of this Agreement
§ Termination for Cause:	If your employment with Sempra Energy and its subsidiaries terminates for cause, or your employment would have been subject to termination for cause, prior to the vesting of your restricted stock units (and dividend equivalents), all of your restricted stock units (and dividend equivalents) will be cancelled. A termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness, (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty.  For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.”
§ Leaves of Absence:	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing.  But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract.  And your employment terminates in any event when the approved leave ends, unless you immediately return to active work.  Your employer determines which leaves count for this purpose.
Taxes:	The following is a general summary of the federal income tax consequences of your Restricted Stock Unit Award.  The summary may not cover your particular circumstances because it does not consider foreign, state, local or other tax laws and does not describe future changes in tax rules.  You are urged to consult your tax advisor regarding the specific tax consequences applicable to you rather than relying on this general summary.
§ Generally:	You will not be subject to federal income taxes on your award until you receive shares of Common Stock following the vesting of your restricted stock units.   When you receive your shares, you will realize taxable income based on the fair market value of the shares at the time you receive the shares. When you sell your shares you may also realize taxable gain (or loss) based upon the difference between the sales price and the amount that you have previously recognized as income.
§ Withholding Taxes:	When you become subject to income taxes upon your receipt of the shares of Common Stock, Sempra Energy or its subsidiary is required to withhold taxes.  Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of the shares (valued at the distribution date fair market value) to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares.
Recoupment  (“Clawback”) Policy:	The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed.  The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause.  The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its subsidiaries.
Change in Control:	Subject to certain limitations set forth in the 2008 Long Term Incentive Plan, in the event of a Change in Control (as defined in the plan) of Sempra Energy during the portion of the performance period beginning on January 1, 2011 and ending on December 31, 2012, unless your restricted stock units have been forfeited prior to the Change in Control, 100% of your target number of restricted stock units will vest in the event of a Change in Control.  In the event of a Change in Control of Sempra Energy during the portion of the performance period beginning on January 1, 2013 and ending on the first New York Stock Exchange trading day of 2015, unless your restricted stock units have been forfeited prior to the Change in Control, your restricted stock units will vest or be forfeited on the basis of the total shareholder return performance criteria set forth above under “Vesting/Forfeiture” as if the performance period had ended on the date immediately preceeding the date of the Change in Control. You will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested.  Also, you will receive the number of shares of Common Stock equal to your dividend equivalents.  You will receive the shares of Common Stock immediately prior to the date of the Change in Control. Immediately following the Change in Control, your vested and unvested restricted stock units (and dividend equivalents) will terminate.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the attached Arbitration Agreement. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Other Agreements:	In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail.

By signing the Cover Sheet/Summary of this Agreement, you agree

to all of the terms and conditions described above and in the 2008 Long Term Incentive Plan

Exhibit A

Examples Illustrating the Determination
of the Vested Percentage of the

Target Number of Restricted Stock Units

The following examples illustrate how the percentage of the target number of restricted stock units is to be determined.  The examples assume that Sempra Energy achieves certain total cumulative shareholder returns for the performance period.  The vested percentage of your target number of restricted stock units will be determined based on Sempra Energy’s actual cumulative total shareholder return for the performance period as measured at the end of the performance period.  No assurance is given that Sempra Energy will achieve the cumulative total shareholder returns shown in the examples.

Example 1

Sempra Energy’s total cumulative shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 80^th percentile.

Because Sempra Energy’s cumulative total cumulative shareholder return is above the 75^th percentile, 150% of the target number of restricted stock units vest.  This is the maximum number of restricted stock units under the award.

Example 2

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 67^th percentile.

The percentage of the target number of restricted stock units that vest is determined by a linear interpolation between the percentage based on the achievement of the 65^th percentile (130%) and the percentage based on the achievement of the 70^th percentile (140%).

The percentage is determined as follows:  

(a)

130% (the percentage based on the achievement of the 65^th percentile), plus

(b)

10% (the percentage based on the achievement of the 75^th percentile, less the percentage based on the achievement of the 65^th percentile), multiplied by an interpolation factor.   

The interpolation factor equals (67^th percentile, less 65^th percentile), divided by (70^th percentile, less 65^th percentile), or two fifths (2/5).  

The percentage based on the achievement of the 67^th percentile equals:  (a) 130%, plus (b) 10%, multiplied by 2/5, or 134%.   Based on Sempra Energy’s cumulative total shareholder return, 134% of the target number of restricted stock units vest.

Example 3

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 45th percentile.

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Composite Index, as determined and certified by the Compensation, is at or above the 50^th percentile.

Because Sempra Energy’s cumulative total shareholder return is at the 45^th percentile when ranked among the companies in the S&P 500 Utility Index, 70% of the target number of restricted stock units would vest (before taking into account Sempra Energy’s performance among the companies in the S&P 500 Composite Index).  

However, because Sempra Energy’s cumulative total shareholder return is at or above the 50^th percentile when ranked among the companies in the S&P 500 Composite Index, 100% of the target number of restricted stock units vest.

Example 4

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation  Committee, is at the 30th percentile.

Also, Sempra Energy’s total shareholder return for the performance period among the companies (ranked by cumulative total shareholder returns) in the S&P 500 Composite Index, as determined and certified by the Compensation Committee, is below the 50th percentile.

Because Sempra Energy’s total shareholder return for the performance period among companies in the S&P 500 Utility Index is below the 35^th percentile, none of the target number of restricted stock units vest.

EX-10

8/23/2010

2010 OPERATING ORDER

CONCERNING

STATE OF CALIFORNIA
DEPARTMENT OF WATER RESOURCES

And

SAN DIEGO GAS & ELECTRIC COMPANY

THIS ORDER HAS BEEN FILED WITH AND APPROVED BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION (“COMMISSION”) FOR USE BETWEEN THE STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES (“DWR”) AND SAN DIEGO GAS & ELECTRIC COMPANY (“UTILITY”).  

Date of Commission Approval:  March 10, 2011

Effective Date:  March 10, 2011

2010 OPERATING ORDER

This 2010 OPERATING ORDER (this “Order” or “2010 Operating Order”) concerns the State of California Department of Water Resources (“DWR”), acting solely under the authority and powers granted by AB1X, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with respect to the State Water Resources Development System, and San Diego Gas & Electric Company, a California corporation (“Utility”).  This 2010 Operating Order amends and restates that certain 2004 Operating Agreement filed with the Commission on November 12, 2004 as directed in Decision 04-10-020, clarifying and revising that certain original Operating Agreement filed with the Commission on April 17, 2003, consistent with Decision 03-04-029, which replaced that certain Operating Order adopted pursuant to Decision 02-12-069, as amended and supplemented from time to time (collectively, the “Existing Operating Arrangement”).  DWR and Utility are sometimes collectively referred to herein as the “Parties” and individually referred to as a “Party.”  Unless otherwise noted, all capitalized terms shall have the meanings set forth in Article I of this Order.

R E C I T A L S

WHEREAS, under the Act, DWR has entered into a number of long-term power purchase agreements for the purpose of providing the net short requirements to the retail ratepayers of the State’s electrical corporations, including Utility; and  

WHEREAS, the Contract Allocation Order of the Commission provides that such long-term power purchase agreements are to be operationally allocated among the State’s electrical corporations, including Utility, solely for the purpose of causing the State’s electrical corporations to perform certain specified functions on behalf of DWR, as DWR’s limited agent, including dispatching, scheduling, billing and settlements functions, and, prior to the MRTU Effective Date, to sell surplus energy, all as such functions relate to those certain power purchase agreements that are operationally allocated to each electrical corporation under the Contract Allocation Order; and

WHEREAS, DWR wishes to provide for the performance of such functions under the Allocated Contracts by Utility on behalf of DWR in accordance with such long-term power purchase agreements as provided in this Order; and

WHEREAS, consistent with the Contract Allocation Order and prior to the date that any Contract is novated to Utility, DWR will retain legal and financial obligations, together with ongoing responsibility for any other functions not explicitly provided in this Order to be performed by Utility, with respect to each of the Allocated Contracts and it is the intent of DWR and the Utility that the provisions of this Order will not constitute an “assignment” of the Allocated Contracts to Utility; and

WHEREAS, to reflect the changes resulting from the ISO implementation of Market Redesign and Technology Upgrade, DWR desires to amend the Existing Operating Arrangement and the Servicing Arrangement, consistent with the principles memorialized in that certain Memorandum of Understanding, dated as of February 4, 2009, which has been approved by the Commission on March 13, 2009.

NOW, THEREFORE, DWR agrees and Utility is ordered to do as follows:

ARTICLE I
DEFINITIONS

Section 1.1.

Definitions.  The following terms shall have the respective meanings in this Order:  

The following terms, when used herein (and in the attachments hereto) with initial capitalization, shall have the meaning specified in this Section 1.01.  Certain additional terms are defined in the attachments hereto.  The singular shall include the plural and the masculine shall include the feminine and neuter, and vice versa.  “Includes” or “including” shall mean “including without limitation.”  References to a section or attachment shall mean a section or attachment of this Order, as the case may be, unless the context requires otherwise, and reference to a given agreement or instrument shall be a reference to that agreement or instrument as modified, amended, supplemented or restated through the date as of which such reference is made (except as otherwise specifically provided herein).  Unless the context otherwise requires, references to Applicable Laws or Applicable Tariffs shall be deemed references to such laws or tariffs as they may be amended, replaced or restated from time to time.  References to the time of day shall be deemed references to such time as measured by prevailing Pacific Time.

“Act” means Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of California, as amended.

“Allocated Contracts” mean the long-term power purchase agreements (as such agreements may be amended, supplemented, modified or clarified from time to time) operationally allocated to Utility under the Contract Allocation Order, without legal and financial assignment of such agreements to Utility, as provided in Schedule 1 attached hereto.

“Allocated Power” means all power and energy, including the use of such power or energy as ancillary services, delivered or to be delivered under the Contracts.  

“Applicable Commission Orders” mean such rules, regulations, decisions, opinions or orders as the Commission may lawfully issue or promulgate from time to time, which further define the rights and obligations of the Parties under this Order.

“Applicable Law” means the Act, Applicable Commission Orders and any other applicable statute, constitutional provision, rule, regulation, ordinance, order, decision or code of a Governmental Authority.

“Applicable Tariffs” mean Utility’s tariffs, including all rules, rates, schedules and preliminary statements, governing electric energy service to Utility’s customers in its service territory, as filed with and approved by the Commission and, if applicable, the Federal Energy Regulatory Commission.

“Assign(s)” shall have the meaning set forth in Section 14.01.

“Bonds” shall have the meaning set forth in the Rate Agreement.

“Bond Charges” shall have the meaning set forth in the Rate Agreement.

“Business Day” means the regular Monday through Friday weekdays that are customary working days, excluding holidays, as established by Applicable Tariffs.

“Commission” means the California Public Utilities Commission.

“Confidential Information” shall have the meaning set forth in Section 11.01(c).

“Contracts” mean the Allocated Contracts.

“Contract Allocation Order” means Decision 02-09-053 of the Commission, issued on September 19, 2002, as such Decision may be modified, revised, amended, supplemented or superseded from time to time by the Commission.

“DWR Power” shall have the same meaning set forth in the Servicing Arrangement with such amendments to incorporate the Settlement Principles for Remittances and Surplus Revenues, as provided in Exhibit C of this Order.

“DWR Revenues” mean those amounts required to be remitted to DWR by Utility in accordance with this Order and as further provided in the Servicing Arrangement.

“Effective Date” means the effective date of this Order in accordance with Section 14.13, as such date is set forth on the cover page hereof.

“Fund” means the Department of Water Resources Electric Power Fund established by Section 80200 of the California Water Code.

“Good Utility Practice” means any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition.  Good Utility Practice does not require the optimum practice, method, or act to the exclusion of all others, but rather is intended to include acceptable practices, methods, or acts generally accepted in the Western Electric Coordinating Council region.

“Governmental Authority” means any nation or government, any state or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the Commission.

“Governmental Program” means any program or directive established by Applicable Law which directly or indirectly affects the rights or obligations of the Parties under this Order and which obligates or authorizes DWR to make payments or give credits to customers or other third parties under such programs or directives.

“ISO” means the California Independent System Operator Corporation.

“MRTU” means the ISO’s Market Redesign and Technology Upgrade.

“MRTU Effective Date” means the first trade date upon MRTU implementation by the ISO.

“Operating Order” or “Order” means this 2010 Operating Order, which amends and restates that certain 2004 Operating Agreement filed with the Commission on November 12, 2004 as directed in Decision 04-10-020, clarifying and revising that certain original Operating Agreement filed with the Commission on April 17, 2003, consistent with Decision 03-04-029, which replaced that certain Operating Order adopted pursuant to Decision 02-12-069, as amended and supplemented from time to time.

“Power Charges” shall have the meaning set forth in the Rate Agreement.

“Priority Long Term Power Contract” shall have the meaning set forth in the Rate Agreement.

“Rate Agreement” means the Rate Agreement between DWR and the Commission adopted by the Commission on February 21, 2002 in Decision 02-02-051.

“Remittance” means a payment by Utility to DWR or its Assign(s) in accordance with the Servicing Arrangement.

“Servicing Arrangement” means the Servicing Order as specified in Commission Decision 02-12-070, dated December 19, 2002, as further amended and restated by Decision 07-03-025 and certain further amended and restated 2010 Servicing Order submitted and pending the Commission approval.

“Supplier” means those certain third parties who are supplying power pursuant to the Contracts.

“Term” means term provided in Section 2.05 hereof.

“URG” means utility-retained generation, including without limitation Utility’s portfolio of generation resources and power purchase agreements prior to or after the Effective Date by Utility.

Section 1.2.

Undefined Terms.  Capitalized terms not otherwise defined in Section 1.01 herein shall have the meanings set forth in the Act or the Servicing Arrangement.

ARTICLE II
OPERATIONAL ALLOCATION OF POWER PURCHASE AGREEMENTS; MANAGEMENT OF THE CONTRACTS; ALLOCATED POWER; TERM

Section 2.1.

Operational Allocation and Management of Power Purchase Agreements. On behalf of DWR, as its limited agent, Utility will perform certain day-to-day scheduling and dispatch functions, billing and settlements and surplus energy sales (prior to the MRTU Effective Date) and certain other tasks with respect to the Allocated Contracts, as more fully set forth in this Order.  

As further provided in Contract Administration and Performance Test Monitoring Protocols set forth in Exhibit E, except as otherwise transferred to the Utility as referenced in Exhibit E, DWR will continue to monitor and audit the Supplier performance under the Contracts.  Upon development of a mutually agreeable plan, Utility will monitor the performance of Suppliers, as further provided in Exhibit E, subject, however, to DWR’s right but not the obligation to audit and monitor all functions contemplated to be performed by Utility, all as further provided in this Order.

Section 2.2.

Standard of Contract Management.

(a)

Prior to the date that any Contract is novated to Utility, Utility agrees to perform the functions specified in this Order relating to the Allocated Contracts, in a commercially reasonable manner, exercising Good Utility Practice, and in a fashion reasonably designed to serve the overall best interests of retail electric customers.  Utility shall provide to DWR such information specifically provided in Exhibit F hereto to facilitate DWR’s verification of Utility’s compliance with this Section 2.02.

(b)

To the extent requested by Utility, DWR shall provide evidence in Commission proceedings describing Utility’s and DWR’s performance, rights and obligations under this Order.

(c)

DWR acknowledges the Commission’s exclusive authority over whether the Utility has managed Allocated Power available under the Contracts in a just and reasonable manner and DWR and Utility agree that none of the provisions of this Order shall be interpreted to reduce, diminish, or otherwise limit the scope of any Commission authority or to give DWR any authority over such matters.  In addition, the Parties acknowledge that DWR is not subject to the Commission’s jurisdiction, and the Parties agree that none of the provisions of this Order, including Section 13.04 herein, shall be interpreted to subject DWR to the Commission’s jurisdiction or authority.

(d)

The Utility acknowledges DWR’s separate and independent right to evaluate and enforce Utility’s commercial performance under this Order.

(e)

Utility agrees to provide any information not otherwise required herein that is reasonably necessary to allow DWR to exercise its rights in subsection (d) above, provided that all such information shall be used solely for the purposes of exercising such rights.

Section 2.3.

Good Faith.  Each Party hereby covenants that it shall perform its actions, obligations and duties in connection with this Order in good faith.

Section 2.4.

DWR Power.  During the term of this Order, the electric power and energy, including but not limited to capacity, and output, or any of them from the Contracts delivered to retail end-use customers in Utility’s service area shall constitute DWR Power for all purposes of the Servicing Arrangement.  Prior to the MRTU Effective Date, Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective, all as further provided in Exhibit A.  

Section 2.5.

  Term.

(a)

The Term of this Order shall commence on the Effective Date and shall terminate on the earlier of (a) the termination of the Servicing Arrangement, or (b) the termination of this Order by DWR upon ninety days’ written notice to Utility and the Commission, or (c) upon consultation with the Commission, the termination of the Order by DWR upon reasonable written notice to Utility no shorter than 30 days, or (d) pursuant to Article VII hereof, the termination of this Order by a non-defaulting Party after an Event of Default.  

In addition, this Order will terminate as to each Contract that terminates in accordance with its terms, has been terminated by a party to that Contract, or has been novated.  Provided, however, whether a Contract is terminated or novated, the rights and obligations of the Parties that arise or relate to Utility’s performance of its duties under this Order in respect of any terminated or novated Contract shall survive until the expiration of any such right or obligation.  

(b)

If an event occurs which has the effect of materially altering and materially adversely impacting the economic position of the Parties or either of them under this Order, then the affected Party may, by written notice, request that the Commission approve amendments to this Order or other arrangements incidental to this Order as necessary to preserve or restore the economic position under this Order held by the affected Party immediately prior to such event.  Such notice shall describe the event and shall include reasonable particulars as to the manner and extent to which the economic position of the Party giving notice has been adversely affected.

ARTICLE III
LIMITED AGENCY / NO ASSIGNMENT

Section 3.1.

Limited Agency.  Utility is hereby appointed as DWR’s agent for the limited purposes set forth in this Order.  Utility shall not be deemed to be acting, and shall not hold itself out, as agent for DWR for any purpose other than those described in this Order.  Utility’s duties and obligations shall be limited to those duties and obligations that are specified in this Order.

Section 3.2.

No Assignment.  Prior to the date that any Contract is novated to Utility, DWR shall remain legally and financially responsible for performance under each of the Contracts and shall retain liability to the counterparty for any failure of Utility to perform the functions referred to in this Order on behalf of DWR as its limited agent, under such Contracts in accordance with the terms thereof.  It is the intent of DWR and Utility that the provisions of this Order shall not constitute or result in an “assignment” of the Allocated Contracts in any respect.

ARTICLE IV
LIMITED DUTIES OF UTILITY

Section 4.1.

Limited Duties of Utility as to the Contracts.  During the Term of this Order, Utility shall:

(a)

Prior to the MRTU Effective Date, on behalf of DWR, as its limited agent, perform the day-to-day scheduling and dispatch functions, including day-ahead, hour-ahead and real time trading, scheduling transactions with all involved parties,  under the Allocated Contracts, perform billing and settlements functions and obtain relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 hereto, all as more specifically provided in the Operating Protocols attached hereto as Exhibit A;

On and after the MRTU Effective Date, on behalf of DWR, as its limited agent, perform the day-to-day tasks, including the submission or the coordination of Bids and/or Inter-SC Trades, in the ISO’s Day-Ahead Market, Hour-Ahead Scheduling Process and/or Real-Time Market (as such terms are defined under ISO’s MRTU tariff), related to, and consistent with the terms of, the Allocated Contracts, perform billing and settlements functions and obtain relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 hereto, all as more specifically provided in the Operating Protocols attached hereto as Exhibit A;

(b)

On behalf of DWR, as its limited agent, enter into transactions for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and perform the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

(c)

On behalf of DWR, as its limited agent, perform all necessary settlement functions under the Allocated Contracts in accordance with the terms of the applicable Allocated Contracts, consistent with the provisions of Exhibit C of this Order.  In addition, perform all necessary billing and settlement functions related to DWR Revenues and remit DWR Revenues to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the Servicing Arrangement;

(d)

Assume financial responsibility for the ISO charges listed on Exhibit D attached hereto;

(e)

On behalf of DWR, as its limited agent, upon development of a mutually agreeable plan, monitor the performance of Suppliers under the Allocated Contracts and undertake the administration of the Allocated Contracts, as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E;

(f)

Provide to DWR the necessary information required by DWR as more specifically provided in the DWR Data Requirements From Utility attached hereto as Exhibit F to allow DWR to perform such internal procedures that are reasonable and determined appropriate by DWR to allow DWR to continue performance of financial obligations related to Allocated Contracts and to prepare and support reporting requirements set forth in Applicable Laws or agreements;

(g)

At all times in performing its obligations under this Order (i) comply with the provisions of each of the Allocated Contracts, (ii) follow Good Utility Practice, and (iii) comply with all Applicable Laws and Applicable Commission Orders;

(h)

Appoint a primary and secondary contact person, as set forth in Schedule 2 hereto, to coordinate the responsibilities listed in this Section 4.01;

(i)

Prior to the MRTU Effective Date, on behalf of DWR, as its limited agent, make surplus energy sales as more specifically provided in this Order; and

(j)

Upon issuance of an Applicable Commission Order approving the novation of a Contract, Utility will submit in writing to DWR as to the effective novation date of such Contract.

Provided, however, in the event that DWR fails to provide or provides inaccurate information which results in Utility’s non-compliance with its obligations under this Order, the resulting non-compliance by Utility shall not constitute an Event of Default under Section 7.01 hereof.

Section 4.2.

Dispatch or Sale of Allocated Power.  Subject to any existing or new ISO tariff provisions that may affect the dispatch of such Contracts, Allocated Power from all Contracts shall be dispatched or sold, as the case may be, by Utility pursuant to the Operating Protocols attached hereto as Exhibit A.  

Section 4.3.

DWR Revenues.  DWR Revenues shall be accounted and remitted to DWR consistent with the principles provided in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the provisions of the Servicing Arrangement.  Unless otherwise specifically provided in this Order, Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities under this Order.

Section 4.4.

Ownership of Allocated Power.  Notwithstanding any other provision herein, and in accordance with the Act and Section 80110 of the California Water Code, DWR shall retain title to all Allocated Power, including DWR Power.  In accordance with the Act and Section 80104 of the California Water Code, upon the delivery of Allocated Power to Utility’s customers, those customers shall be deemed to have purchased that power from DWR, and payment for such sale shall be a direct obligation of such customer to DWR.  In addition, prior to the MRTU Effective Date, DWR shall retain title to any surplus Allocated Power sold by Utility as limited agent to DWR as provided in this Order.  

ARTICLE V
DUTIES OF DWR

Section 5.1.

Duties of DWR.  Prior to the date that any Contract is novated to Utility and consistent with the Contract Allocation Order, during the Term of this Order, DWR shall:

(a)

Remain legally and financially responsible under each of the Contracts and cooperate with Utility in the transition from DWR to Utility the performance of the functions provided in this Order;

(b)

Assume legal and financial responsibilities and enter into or facilitate Utility’s entering into transactions as DWR’s limited agent, for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and timely consent to or approve the Utility’s performance of the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

(c)

Pay invoices to the Suppliers and perform such internal procedures that are reasonable and determined appropriate by DWR, which may include validation, analysis and audit of the settlement functions to be performed on DWR’s behalf, as its limited agent, by Utility relating to the Contracts.  In addition, perform such internal procedures that are reasonable and determined appropriate by DWR, which may include validation, analysis and audit of the billing and settlement functions to be performed on DWR’s behalf, as its limited agent, by Utility related to DWR Revenues, consistent with the principles set forth in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C;

(d)

Until such time as a mutually agreed upon plan may be entered into with Utility and approved by the Commission, and no earlier than January 1, 2004, continue to monitor the performance of Suppliers and conduct certain contract administration duties under the Allocated Contracts, all as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E.  In addition, continue to perform all other administrative functions related to Contracts not explicitly provided in this Order to be performed by Utility on behalf of DWR, as its limited agent;

(e)

Upon the termination of any Contract (other than a Contract that is novated to Utility or terminated on the Contract stated termination date shown on Schedule 1 attached to this Order), DWR will submit in writing to Utility a revised Schedule 1 to reflect the termination of any Contract.  In the event that a Contract terminates on the Contract stated termination date shown on Schedule 1, then no further notice will be provided by DWR; and

(f)

Appoint a primary and secondary contact person, as set forth in Schedule 3 hereto, to coordinate the responsibilities listed in this Section 5.01.

ARTICLE VI
[RESERVED]

Section 6.1.

[Intentionally left blank.]

ARTICLE VII
EVENTS OF DEFAULT

Section 7.1.

Events of Default. The following events shall constitute “Events of Default” under this Order:

(a)

any material failure by a Party to pay any amount due and payable under this Order that continues unremedied for five (5) Business Days after the earlier of the day the defaulting Party receives written notice thereof from the non-defaulting Party; or

(b)

any material failure by Utility to schedule and dispatch Contracts, consistent with the principles set forth in Exhibit A; or

(c)

any failure (except as provided in (a) or (b)) by a Party to duly observe or perform in any material respect any other term or condition of such Party set forth in this Order, which failure continues unremedied for a period of 15 calendar days after written notice of such failure has been given to such Party by the non-defaulting Party; or

(d)

any material representation or warranty made by a Party shall prove to be false, misleading or incorrect in any material respect as of the date made; or

(e)

an Event of Default (as defined under the Servicing Arrangement) shall have occurred and is continuing under the Servicing Arrangement.

Section 7.2.

Consequences of Utility Event of Default.  Upon any Event of Default by Utility, DWR may, in addition to exercising any other remedies available under this Order or under Applicable Law, (i) apply to the Commission for appropriate relief, including but not limited to the termination of this Order in whole or in part; and (ii) apply to the Commission and, if necessary, any court of competent jurisdiction for sequestration and payment to DWR or its Assign(s) of DWR Revenues or for specific performance of the functions related to the Contracts to be performed by Utility on behalf of DWR, as its limited agent, as provided in this Order.  

Section 7.3.

Consequences of DWR Event of Default.  Upon an Event of Default by DWR (other than an Event of Default under 7.01(a)), Utility may request that the Commission terminate this Order in whole or in part, Section 2.05 notwithstanding.

Section 7.4.

Remedies.  Subject to Article XIII of this Order, upon any Event of Default, the non-defaulting Party may exercise any other legal or equitable right or remedy that may be available to it under applicable law or under this Order, including, but not limited to, the termination of this Order.  

Section 7.5.

Remedies Cumulative.  Except as otherwise provided in this Order, all rights of termination, cancellation, or other remedies in this Order are cumulative.  Use of any remedy shall not preclude any other remedy available under this Order.

Section 7.6.

Waivers. None of the provisions of this Order shall be considered waived by either Party unless the Party against whom such waiver is claimed gives such waiver in writing.  The failure of either Party to insist in any one or more instances upon strict performance of any of the provisions of this Order or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.  Waiver by either Party of any default by the other Party shall not be deemed a waiver of any other default.

ARTICLE VIII
PAYMENT OF FEES AND CHARGES

Section 8.1.

Utility Fees and Charges.  As noted in the Contract Allocation Order, the details of the amount and recovery of administrative costs to Utility associated with the Contracts are expected to be considered in another Commission proceeding.  As such, the Parties agree that the administrative costs to Utility will be recovered pursuant to such Commission proceeding. Utility shall enter the cost of such fees and charges in its Purchased Electric Commodity Account, or its successor or another account designated by the Commission on a current basis, for recovery in retail rates subject to subsequent Commission review.

ARTICLE IX
REPRESENTATIONS AND WARRANTIES

Section 9.01.  Representations and Warranties of DWR.  DWR represents and warrants that it will use its best efforts to obtain all necessary and appropriate notices, inducements, undertakings, approvals, and consents from each Supplier to the Contract allocated to Utility in order for Utility to undertake its duties set forth in this Order in a timely and appropriate fashion.  

ARTICLE X
LIMITATIONS ON LIABILITY

Section 10.1.

Consequential Damages. In no event will either Party be liable to the other Party for any indirect, special, exemplary, incidental, punitive, or consequential damages under any theory.  Nothing in this Section 10.01 shall limit either Party’s rights as provided in Article VII above.

Section 10.2.

Limited Obligations of DWR. Any amounts payable by DWR under this Order shall be payable solely from moneys on deposit in the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code (the “Fund”).  

Section 10.3.

Sources of Payment; No Debt of State.  DWR’s obligation to make payments hereunder shall be limited solely to the Fund and shall be payable as an operating expense of the Fund solely from Power Charges subject and subordinate to each Priority Long Term Power Contract in accordance with the priorities and limitations established with respect to the Fund’s operating expenses in any indenture providing for the issuance of Bonds and in the Rate Agreement and in the Priority Long Term Power Contracts.  Any liability of DWR arising in connection with this Order or any claim based thereon or with respect thereto, including, but not limited to, any payment arising as the result of any breach or Event of Default under this Order, and any other payment obligation or liability of or judgment against DWR hereunder, shall be satisfied solely from the Fund.  NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE OF CALIFORNIA ARE OR MAY BE PLEDGED FOR ANY PAYMENT UNDER THIS ORDER. Revenues and assets of the State Water Resources Development System, and Bond Charges under the Rate Agreement, shall not be liable for or available to make any payments or satisfy any obligation arising under this Order.  If moneys on deposit in the Fund are insufficient to pay all amounts payable by DWR under this Order, or if DWR has reason to believe such funds may become insufficient to pay all amounts payable by DWR under this Order, DWR shall diligently pursue an increase to its revenue requirements as permitted under the Act from the appropriate Governmental Authority as soon as practicable.  To the extent DWR’s obligations are “administrative costs,” they will require annual appropriation by the legislature.

Section 10.4.

Cap on Liability.  In no event will Utility be liable to DWR for damages under this Order, including indemnification obligations, whether in contract, warranty, tort (including negligence), strict liability or otherwise (referred to as “Damages” for purposes of this Section), in an amount in excess of: 1) on an annual calendar year basis, $5 million plus ten percent of Damages in excess of $5 million and 2) for the entire term of this Order, $50 million in total payments of Damages to DWR.  For example, if Damages for an event are $100 million, Utility’s total liability for this event would be $14.5 million ($5 million plus 10% of $95 million) and that would be the full extent of Utility’s liability for such Damages.  All Damages associated with an event will apply only to the annual limit in the first year in which Damages for that event were assessed.  For example, if Damages for an event were paid as follows: $15 million in year 1 and $10 million in year 2, the Utility would pay DWR $7 million ($5 million plus 10% of $10 million for year 1 and 10% of $10 million for year 2).  In this example, the $1 million paid to DWR in year 2 (10% of $10 million) does not count against the year 2 $5 million calendar year threshold.  DWR hereby releases Utility from any liability for Damages in excess of the limitations on liability set forth in this Section 10.04, provided however, that this limitation on Utility liability shall not apply to the extent the liability is a result of Utility’s gross negligence or willful misconduct.  

ARTICLE XI
CONFIDENTIALITY

Section 11.1.

Proprietary Information.

(a)

Nothing in this Order shall affect Utility’s obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its customers.

(b)

Nothing in this Order, and in particular nothing in Sections 11.01(e)(x) through 11.01(e)(z) of this Order, shall affect the rights of the Commission to obtain from Utility, pursuant to Applicable Law, information requested by the Commission, including Confidential Information provided by DWR to Utility. Applicable Law, and not this Order, will govern what information the Commission may disclose to third parties, subject to any confidentiality agreement between DWR and the Commission.

(c)

The Parties acknowledge that each Party may acquire information and material that is the other Party’s confidential, proprietary or trade secret information.  As used herein, “Confidential Information” means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party’s inspection of the other Party’s records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs, records, data, models, inventions, know-how, processes, apparati, equipment, algorithms, software programs, software source documents, object code, source code, and information related to the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties’ respective information concerning research, experimental work, development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing plans and information.  In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such third party’s business or relationship with such Party.  Utility’s Confidential Information also includes any and all lists of customers, and any and all information about customers, both individually and aggregated, including but not limited to customers’ names, street addresses of customer residences and/or facilities, email addresses, identification numbers, Utility account numbers and passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among customer residences and/or facilities, and usage of DWR Power.  All Confidential Information disclosed by the disclosing Party (“Discloser”) will be considered Confidential Information by the receiving Party (“Recipient”) if identified as confidential and received from Discloser.

(d)

Each Party agrees to take all steps reasonably necessary to hold in trust and confidence the other Party’s Confidential Information.  Without limiting the generality of the immediately preceding sentence, each Party agrees (i) to hold the other Party’s Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or otherwise, other than as permitted under this Order; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality.  DWR shall not disclose Confidential Information to employees, agents or subcontractors that are in any respect responsible for power marketing or trading activities associated with the State Water Resources Development System.

(e)

The foregoing two paragraphs will not apply to any item of Confidential Information if:  (i) it has been published or is otherwise readily available to the public other than by a breach of this Order; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the provision of services under this Order; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; (iv) it was known to Recipient prior to its first receipt from Discloser, or (v) it has been summarized, processed and incorporated for incorporation into reports, discussions, statements or any other further work product.  In addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidential Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment.  Discloser shall pay Recipient its reasonable costs of cooperating.

Section 11.2.

No License.  Nothing contained in this Order shall be construed as granting to a Party a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned, obtained, controlled by, or which is or may be licensable by, the other Party.

Section 11.3.

Survival of Provisions.  The provisions of this Article XI shall survive the termination of this Order.

ARTICLE XII
RECORDS AND AUDIT RIGHTS

Section 12.1.

Records.  Utility shall maintain accurate records and accounts relating to the Contracts in sufficient detail to permit DWR to audit and monitor the functions to be performed by Utility on behalf of DWR, as its limited agent, under this Order.  In addition, Utility shall maintain accurate records and accounts relating to DWR Revenues to be remitted by Utility to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues set forth in Exhibit C hereto.  Utility shall provide to DWR and its Assign(s) access to such records.  Access shall be afforded without charge, upon reasonable request made pursuant to Section 12.02.  Access shall be afforded only during Business Hours and in such a manner so as not to interfere unreasonably with Utility’s normal operations.  Utility shall not treat DWR Revenues as income or assets of Utility or any affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of Utility and affiliates shall be maintained in a manner consistent with the absolute ownership of DWR Revenues by DWR and Utility’s holding of DWR Revenues in trust for DWR (whether or not held together with other monies).

Section 12.2.

Audit Rights.  

(a)

Upon 30 calendar days’ prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR’s expense), of Utility’s records and procedures, which shall be limited to records and procedures containing information bearing upon Utility’s performance of its obligations under this Order.  The audit shall be conducted during Business Hours without interference with Utility’s normal operations, and in compliance with Utility’s security procedures.

(b)

As provided in the Act, the State of California Bureau of State Audits (the “Bureau”) shall conduct a financial and performance audit of DWR’s implementation of Division 27 (commencing with Section 80000) of the California Water Code, and the Bureau shall issue a final report on or before March 31, 2003.  In addition, as provided in Section 8546.7 of the California Government Code, pursuant to this Section 12.02, DWR or the State of California Department of General Services, the Bureau, or their designated representative (“DWR’s Agent”) shall have the right to review and to copy (at DWR’s expense) any non-confidential records and supporting documentation pertaining to the performance of this Order and to conduct an on-site review of any Confidential Information pursuant to Section 12.03 hereof.  Utility agrees to maintain such records for such possible audit for three years after final Remittance to DWR.  Utility agrees to allow such auditor(s) access to such records during Business Hours and to allow interviews of any employees who might reasonably have information related to such records.  Further, Utility shall include a similar right for DWR or DWR’s Agent to audit records and interview staff in any contract between Utility and a subcontractor directly related to performance of this Order.

Section 12.3.

Confidentiality.  Materials reviewed by either Party or its agents in the course of an audit may contain Confidential Information subject to Article XI above.  The use of all materials provided to DWR or Utility or their agents, as the case may be pursuant to this Article XII, shall comply with the provisions in Article XI and shall be limited to use in conjunction with the conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law.

Section 12.4.

Annual Certifications.  At least annually, and in no event later than the 30th day after the end of the calendar year, Utility shall deliver to DWR, with a copy to the Commission, a certificate of an authorized representative certifying that to the best of such representative’s knowledge, after a review of Utility performance under this Order, Utility has fulfilled its obligations under this Order in all material respects and is in compliance herewith in all material respects.

Section 12.5.

Additional Applicable Laws.  Each Party shall make an effort to promptly notify the other Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a material adverse effect on either Party’s ability to perform its duties under this Order.  A Party’s failure to so notify the other Party pursuant to this Section 12.05 will not constitute a material breach of this Order, and will not give rise to any right to terminate this Order or cause either Party to incur any liability to the other Party or any third party.

Section 12.6.

Other Information.  Upon the reasonable request of DWR or its Assign(s), Utility shall provide to DWR or its Assign(s) any public financial information in respect of Utility applicable to services provided by Utility under this Order, to the extent such information is reasonably available to Utility, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by Utility hereunder, or (ii) otherwise relates to the exercise of DWR’s rights or the discharge of DWR’s duties under this Order or any Applicable Law.  In particular, but without limiting the foregoing, Utility shall provide to DWR any such information that is necessary or useful to calculate DWR’s revenue requirements (as described in Sections 80110 and 80134 of the California Water Code).

Section 12.7.

Data and Information Retention.  All data and information associated with the provision and receipt of services pursuant to this Order shall be maintained for the greater of (a) the retention time required by Applicable Law or Applicable Tariffs for maintaining such information, or (b) three (3) years.

ARTICLE XIII
DISPUTE RESOLUTION

Section 13.1.

Dispute Resolution.  Should any dispute arise between the Parties or should any dispute between the Parties arise from the exercise of either Party’s audit rights contained in Section 12.02 hereof, the Parties shall remit any undisputed amounts and agree to enter into good faith negotiations as soon as practicable to resolve such disputes within (10) Business Days so as to resolve such disputes, as appropriate, within the timeframes provided under this Order, or as soon as possible thereafter.  For any disputed Remittances, if such resolution cannot be made before the remittance date, Utility shall remit the undisputed portion to DWR.  In addition, the disputed portion of the Remittances shall be deposited into an escrow account held by a qualified, independent escrow holder.  Upon resolution of such disputes, the Party that escrowed the disputed amount shall reimburse the other Party from the escrow account as necessary.

Section 13.2.

ISO Settlements and Disputes.  Prior to the MRTU Effective Date, Utility shall review, validate and verify all ISO charges/credits contained on all ISO settlement statements, including any charges/credits resulting from functions related to the Contracts to be performed by Utility as provided in the Existing Operating Arrangement.  Utility shall inform DWR of any discrepancies and shall dispute any such discrepancies with the ISO in accordance with the ISO’s tariff and protocols.  Except as provided in Section 13.03, if any ISO charge type settlement amount appearing on a Preliminary or Final Settlement Statement (as defined in the ISO tariff) resulting or relating to the Utility’s performance of functions related to the Contracts under the Existing Operating Arrangement is in dispute, it shall be the responsibility of Utility, on behalf of DWR, as its limited agent, to seek resolution of said dispute through the ISO dispute resolution process as provided in the ISO’s tariff.

On and after the MRTU Effective Date, consistent with the parameters of settlements procedures as further provided in Exhibit C attached hereto, DWR agrees and Utility is ordered to perform the following as related to ISO invoices and Settlement Statements (as such term is defined in the ISO tariff then in effect) issued to Utility in its role as load serving entity.  

On and after the MRTU Effective Date, Utility shall review, validate and verify such ISO data or charges/credits contained on all ISO Settlement Statements related to Inter-SC Trades with respect to the Allocated Contracts and to provide such data or information as specified under the caption “Schedule / Bilateral Invoice” in Part II of Exhibit F attached to this Order.  As to such data or information described under the caption “Schedule / Bilateral Invoice” in Part II of Exhibit F, Utility shall inform DWR of any discrepancies and shall dispute any such discrepancies with the ISO in accordance with the ISO’s tariff and protocols.  

At all times, for disputes affecting Utility’s Remittances to DWR, including, prior to the MRTU Effective Date, disputes on ISO charges to non-DWR parties related to Surplus Revenues that would affect Remittances to DWR, Utility shall provide to DWR: a) notification of submission of the dispute through the ISO dispute resolution process, identifying, among other items, the dispute type, quantity, price and allocation; b) a copy of the submitted dispute and all supporting data; and c) a copy of all ensuing documentation resulting from the ongoing dispute resolution process.  Utility shall track and validate all disputed ISO charges involving any financial responsibility of DWR.

Section 13.3.

Supplier Invoice Disputes.  DWR shall continue to be responsible for all dispute resolution relating to Supplier invoices.  In addition, except as specifically provided in Exhibit E of this Order, all other contract administration functions shall remain DWR’s responsibility.  

Section 13.4.

Good-Faith Negotiations.  Should any dispute arise between the Parties relating to this Order, the Parties shall undertake good-faith negotiations to resolve such dispute.  If the Parties are unable to resolve such dispute through good-faith negotiations, either Party may submit a detailed written summary of the dispute to the other Party.  Upon such written presentation, each Party shall designate an executive with authority to resolve the matter in dispute.  If the Parties are unable to resolve such dispute within 30 days from the date that a detailed summary of such dispute is presented in writing to the other Party, and the dispute relates solely to Utility’s conduct, performance, acts and/or omissions (and not to DWR’s conduct performance, acts and/or omissions), then DWR may, at its sole discretion, present the dispute to the Commission for resolution, in accordance with Applicable Law.  All other disputes shall be brought in a court of competent jurisdiction or a forum mutually acceptable to the Parties in accordance with Applicable Law.  Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

Section 13.5.

Costs.  Each Party shall bear its own respective costs and attorney fees in connection with respect to any dispute resolution process undertaken by it pursuant to this Article.  Provided, however, DWR shall reimburse Utility all reasonably incurred costs, including, but not limited to, in-house and retained attorneys, consultants, witnesses, and arbitration costs, arising from or pertaining to all disputes relating to ISO charges/credits contained on all ISO settlement statements resulting from the operational, dispatch and administrative functions related to the Contracts performed by Utility on behalf of DWR, as its limited agent, pursuant to the standards set forth in Section 2.02 herein and consistent with the provisions of the ISO tariff, as may be amended from time to time, including, prior to the MRTU Effective Date, disputes on ISO charges to non-DWR parties related to Surplus Revenues that would affect Remittances to DWR.  These costs shall be recorded and invoiced in the manner set forth in Section 8.01 hereof.

ARTICLE XIV
MISCELLANEOUS

Section 14.1.

Assignment

(a)

Except as provided in paragraphs (b) (c) and (d) below, neither Party shall assign or otherwise dispose of this Order, its right, title or interest herein or any part hereof to any  entity, without the prior written consent of the Commission.  No assignment of this Order shall relieve the assigning Party of any of its obligations under this Order until such obligations have been assumed by the assignee. When duly assigned in accordance with this Section 14.01(a) and when accepted by the assignee, this Order shall be binding upon and shall inure to the benefit of the assignee.  Any assignment in violation of this Section 14.01 (a) shall be void.

(b)

DWR may assign or pledge its rights to receive performance hereunder to a trustee or another party (“Assign(s)”) in order to secure DWR’s obligations under its bonds (as that term is defined in the Act), and any such Assign shall be a third party beneficiary of this Order; provided, however, that this authority to assign or pledge rights to receive performance hereunder shall in no event extend to any person or entity that sells power or other goods or services to DWR.

(c)

Any person (i) into which Utility may be merged or consolidated, (ii) which may result from any merger or consolidation to which Utility shall be a party or (iii) which may succeed to the properties and assets of Utility substantially as a whole, which person in any of the foregoing cases executes an agreement of assumption to perform every obligation of Utility hereunder, shall be the successor to Utility under this Order without further act on the part of any of the Parties to this Order; provided, however, that Utility shall have delivered to the Commission, DWR and DWR’s Assign(s) an opinion of counsel reasonably acceptable to the Commission and DWR stating that such consolidation, merger or succession and such agreement of assumption complies with this Section 13.01(c) and that all of Utility’s obligations hereunder have been validly assumed and are binding on any such successor or assign.

(d)

Notwithstanding anything to the contrary herein, DWR’s rights and obligations hereunder shall be transferred, without any action or consent of either Party hereto, to any entity created by the State legislature which is required under Applicable Law to assume the rights and obligations of DWR under Division 27 of the California Water Code.

Section 14.2.

Force Majeure.  Neither Party shall be liable for any delay or failure in performance of any part of this Order (including the obligation to remit money at the times specified herein) from any cause beyond its reasonable control, including but not limited to, unusually severe weather, flood, fire, lightning, epidemic, quarantine restriction, war, sabotage, act of a public enemy, earthquake, insurrection, riot, civil disturbance, strike, restraint by court order or Government Authority, or any combination of these causes, which by the exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by the exercise of due diligence is unable to overcome.  

Section 14.3.

Severability.  In the event that any one or more of the provisions of this Order shall for any reason be held to be unenforceable in any respect under applicable law, such unenforceability shall not affect any other provision of this Order, but this Order shall be construed as if such unenforceable provision or provisions had never been contained herein.

Section 14.4.

Survival of Payment Obligations.  Upon termination of this Order, each Party shall remain liable to the other Party for all amounts owing under this Order.  Utility shall continue to collect and remit, pursuant to the terms of the Servicing Arrangement and the principles provided in the Settlement Principles for Remittances and Surplus Revenues provided in Exhibit C hereto and any DWR Charges billed to customers or, prior to the MRTU Effective Date, any DWR Surplus Energy Sales Revenues attributable to sales entered into before the effective date of termination of the Servicing Arrangement.  

Section 14.5.

Third-Party Beneficiaries.  The provisions of this Order are exclusively for the benefit of the Parties and any permitted assignee of either Party.

Section 14.6.

Governing Law.  This Order shall be interpreted, governed and construed under the laws of the State of California without regard to choice of law provisions.

Section 14.7.

[Reserved.]

Section 14.8.

Section Headings.  Section and paragraph headings appearing in this Order are inserted for convenience only and shall not be construed as interpretations of text.

Section 14.9.

Amendments.  No amendment, modification, or supplement to this Order shall be effective unless it is in writing and signed by the authorized representatives of both Parties and approved as required, and by reference incorporates this Order and identifies the specific portions that are amended, modified, or supplemented or indicates that the material is new.  No oral understanding or agreement not incorporated in this Order is binding on either of the Parties.

Section 14.10.

Amendment Upon Changed Circumstances.  (a)

The Parties acknowledge that compliance with any Commission decision, legislative action or other governmental action (whether issued before or after the Effective Date of this Order) affecting the operation of this Order, including but not limited to (i) dissolution of the ISO, (ii) changes in the ISO market structure, including but not limited to MRTU or a reversion related thereto, (iii) a decision regarding direct access currently pending before the Commission, (iv) the establishment of other Governmental Programs, or (v) a modification to the Contract Allocation Order may require that amendment(s) be made to this Order.  If either Party reasonably determines that such a decision or action would materially affect the services to be provided hereunder or the reasonable costs thereof, then upon the issuance of such decision or the approval of such action (unless and until it is stayed), the Parties shall negotiate the amendment(s) to this Order that is (or are) appropriate in order to effectuate the required changes in services to be provided or the reimbursement thereof.  If the Parties are unable to reach agreement on such amendments within 60 days after the issuance of such decision or approval of such action, either Party may, in the exercise of its sole discretion, submit the disagreement to the Commission for proposed resolution, in accordance with Applicable Law.  Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

(b)

The Parties shall, if the rating agencies request changes to this Order which the Parties reasonably determine are necessary and appropriate, negotiate in good faith, but will be under no obligation to reach agreement or to ask the Commission to amend this Order to accommodate the rating agency requests.  The Parties will cooperate in obtaining any required approvals of the Commission or other entities for such amendments.

(c)

Upon request of DWR, the Utility agrees to a meet and confer for any reasonable issues identified by DWR as necessary and appropriate for DWR as related to its financial reporting and fiduciary responsibilities and any rights and obligations related to this Operating Order.  In addition, upon the reasonable request of DWR, the Utility will provide to DWR any information in respect of Utility that is applicable to the rights and obligations of the Parties under this Operating Order or any material information that is reasonably necessary for DWR to monitor and manage their risks and perform their fiduciary responsibilities.  Likewise, upon the reasonable request of Utility, DWR will provide to Utility any information in respect of DWR that is applicable to the rights and obligations of the Parties under this Operating Order or any material information that is reasonably necessary for Utility to operationally administer the Allocated Contracts.  If the joint analysis of this information and the “meet and confer” process indicate DWR should, in its judgment, revise its revenue requirement determination for submittal to the Commission, the Utility agrees to support an appropriate revised determination by DWR.

DWR and the Utility agree that as MRTU moves forward either DWR or Utility may identify further changes required to properly administer the Allocated Contracts under MRTU.  DWR and the Utility shall meet and confer on mutual solutions to such changes, implement such solutions, and include them in modifications to the Servicing Arrangement and/or this Operating Order.  

Section 14.11.

Indemnification.

(a)

Indemnification of DWR.  Utility (the “Indemnitor”) shall at all times protect, indemnify, defend and hold harmless DWR, and its elected officials, appointed officers, employees, representatives, agents and contractors (each, an “Indemnified Party” or an “Indemnitee”) from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys’ fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from in connection with):  (1) any failure by Utility to perform its material obligations under this Order; (2) any material representation or warranty made by Utility shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of Utility or any of its officers, directors, employees, agents, representatives, subcontractors or assignees in connection with this Order; and (4) any violation of or failure by Utility or Indemnitor to comply with any Applicable Commission Orders or Applicable Law; provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from gross negligence or willful misconduct of any Indemnified Party.

(b)

Obligation of Utility. Consistent with the Contract Allocation Order, Utility shall not, in acting as limited agent of DWR hereunder be required to perform any obligations of any Supplier or on behalf of any Supplier under any Allocated Contract or to make any payments on behalf of such Supplier or as the result of the failure of such Supplier to perform under any Allocated Contract, except as otherwise explicitly noted in the Operating Protocols attached as Exhibit A and as further provided in Section B of Part III of Exhibit C attached hereto.

(c)

Indemnification of Utility. To the extent permitted by law, DWR (“Indemnitor”) shall at all times protect, indemnify, defend and hold harmless Utility, and its officers, employees, representatives, agents and contractors (each, an “Indemnified Party” or “Indemnitee”), from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys’ fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from on in connection with):  (1)  any failure by DWR to perform its material obligations under this Order or any Allocated Contract; (2) any material representation or warranty made by DWR shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of the DWR or any of its officers, directors or employees, agents, representatives, subcontractors or assignees in connection with this Order; (4) any action claiming Utility failed to perform any Supplier’s obligations under a Contract; and (5) any violation of or failure by DWR or Indemnitor to comply with any Applicable Law; and provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from the gross negligence or willful misconduct of any Indemnified Party.

(d)

Indemnification Procedures.  Indemnitee shall promptly give notice to Indemnitor of any claim or action to which it seeks indemnification from Indemnitor.  Indemnitor shall defend any such claim or action brought against it, and may also defend such claim or action on behalf of the Indemnitee (with counsel reasonably satisfactory to Indemnitor) unless there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action.  If there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action, Indemnitee shall have the opportunity to assume (at Indemnitor’s expense) defense of any claim or action brought against Indemnitee by a third party; however, failure by Indemnitee to request defense of such claim or action by the Indemnitor shall not affect Indemnitee’s right to indemnity under this Section 14.11.  In any action or claim involving Indemnitee, Indemnitor shall not settle or compromise any claim without the prior written consent of Indemnitee.

Section 14.12.

Notices and Demands.  (a) Except as otherwise provided under this Order, all notices, demands, or requests pertaining to this Order shall be in writing and shall be deemed to have been given (i) on the date delivered in person, (ii) on the date when sent by facsimile (with receipt confirmed by telephone by the intended recipient or his or her authorized representative) or electronic transmission (with receipt confirmed telephonically or electronically by the intended recipient or his or her authorized representative) or by special messenger, or (iii) 72 hours following delivery to a United States post office when sent by certified or registered United States mail postage prepaid, and addressed as set forth below:

Utility:

San Diego Gas & Electric Company
Electric and Fuel Procurement
8315 Century Park Court
San Diego, California 92123

Attn:

Michael Strong
Manager - Settlements & Systems
Telephone: (858) 650-6154
Facsimile: (858) 650-6190
Email: mgstrong@semprautilities.com

DWR:

State of California
The Resources Agency
Department of Water Resources
California Energy Resources Scheduling Division
2033 Howe Avenue, Suite 220
Sacramento, California  95825

Attn:

John Pacheco
Acting Deputy Director
Telephone:  (916) 574-0311
Facsimile:  (916) 574-2512
Email:  jpacheco@water.ca.gov

(a)

DWR agrees and with respect to the Utility it is ordered that each Party shall be entitled to specify as its proper address any other address in the United States, or specify any change to the above information, upon written notice to the other Party complying with this Section 14.12.

(b)

DWR agrees and with respect to the Utility it is ordered that each Party shall designate on Attachment A the person(s) to be contacted with respect to specific operational matters.  Each Party shall be entitled to specify any change to such person(s) upon written notice to the other Party complying with this Section 14.12.

Section 14.13.

Effective Date.  This Order shall be effective on the effective date set forth in the decision in which the Commission adopts this Order.  Except as expressly provided otherwise herein, neither Party may commence performance hereunder until such date.  Any delay in the commencement of performance hereunder as a consequence of waiting for such adoption(s) shall not be a breach or default under this Order.

Section 14.14.

Government Code and Public Contract Code Inapplicable.  DWR has determined, pursuant to Section 80014(b) of the California Water Code, that application of certain provisions of the Government Code and Public Contract Code applicable to State contracts, including but not limited to advertising and competitive bidding requirements and prompt payment requirements, would be detrimental to accomplishing the purposes of Division 27 (commencing with Section 80000) of the California Water Code and that such provisions and requirements are therefore not applicable to or incorporated in this Order.

Section 14.15.

Annual Review. The provisions of the Exhibits are subject to annual review by DWR and Utility to ensure their relevance and usefulness.  In the event that the Parties mutually agree that certain provisions of the Exhibits should be amended or supplemented, an amendment to the Exhibit should be executed and Utility shall submit to the Commission for approval.

Section 14.16.

[Reserved]

Schedule 1

ALLOCATED CONTRACTS

SDG&E Contracts	Contract Name	Contract Bidding and Operations Summary	Remittance Basis	Contract Stated Termination Date
Must-Take Contract	JP Morgan B/C	IST in Day Ahead at SP15 Gen Hub	IST Quantity	12/31/2010
Large Dispatchable	Sunrise	Unit will be bid into Market	Metered Amount1	6/30/2012
Small Dispatchable (Peakers)	Calpeak - Border, El Cajon, Enterprise - SDG&E is SC*	Unit will be bid into Market	Metered Amount1	12/8/2011 - Escondido 12/12/2011 - Border 1/1/2012 - El Cajon
	Calpeak - Border, El Cajon, Enterprise -SDG&E is not SC	Bid or self-scheduled into market for all hours (with IST when self-scheduled) (in Day Ahead and/or HASP) at P-node4, 5	IST Quantities2	12/8/2011 - Escondido 12/12/2011 - Border 1/1/2012 - El Cajon
PIRP	Shell Wind - Cabazon, Whitewater Hill	IST (in Day Ahead and/or HASP) at P-node3	IST Quantities2	12/31/2013

¹ IOU-SC will retain market revenues/charges.

² IST quantities include CPT quantities, if any.  

³ IOU will schedule PIRP units according to PIRP requirements.

⁴ Market Revenues generated by Bid awards will be paid to DWR by the counterparty.

⁵ A schedule reduction in HASP can only be accomplished by DEC bids.

* Effective April 1, 2010, SDG&E became the SC for Calpeak Contracts.  

S-1-

Schedule 2

REPRESENTATIVES AND CONTACTS

San Diego Gas & Electric Company
Electric and Fuel Procurement
8315 Century Park Court
San Diego, California 92123

Michael Strong
Manager - Settlements & Systems
Telephone: (858) 650-6154
Facsimile: (858) 650-6190
Email: mgstrong@semprautilities.com

Alternate Contact:

Sue Garcia
Settlements & Administration Manager
Telephone:  (858) 650-6189
Facsimile:  (858) 650-6190
Email:  sgarcia@semprautilities.com

S-2-

8/23/2010

DWR/SDG&E EXHIBIT A

OPERATING PROTOCOLS

EXHIBIT A

OPERATING PROTOCOLS

Pursuant to Section 4.01 of the Operating Order, on behalf of DWR as its limited agent, Utility shall perform the day-to-day scheduling and dispatch functions, including day-ahead, hour-ahead and real-time trading, scheduling of transactions with all involved parties, making surplus energy sales (prior to the MRTU Effective Date) and obtaining relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 to the Operating Order, all as more specifically provided below and in compliance with the provisions of each of the Contracts:

I.

Resource Commitment and Dispatch.  Utility agrees to use good faith efforts to dispatch Allocated Contracts, based on the principle of “least cost dispatch” to retail customers, consistent with the Contract Allocation Order and other Applicable Commission Orders. Utility shall undertake these least cost dispatch functions both of the Contracts and its URG so as to minimize the cost of service to retail customers based on circumstances known or that reasonably could have been known by Utility at the time dispatch decisions are made.  DWR shall have no role in enforcement or review of Utility least cost dispatch under the Operating Order and all issues of Utility compliance with least cost dispatch shall be within the sole review of the Commission.

A.

Annual, Quarterly and Weekly Load and Resource Assessment Studies.  Utility shall provide to DWR copies of its annual and quarterly load and resource assessment studies.  Provided that Utility submits substantially the same information to the Commission, copies of the Commission submission will be simultaneously sent to DWR to satisfy requirements of this section.  In addition, Utility will provide a weekly commitment and dispatch plan for informational purposes to DWR in the same form that such plan is used internally.

B.

Scheduling Protocols.

1.

DWR is responsible for notifying the counter-party to each of the Allocated Contracts that scheduling under the Allocated Contracts will be performed by Utility before the first day that schedules are due to be submitted by Utility.  DWR is responsible for notifying Utility of any changes to the Allocated Contracts that it has negotiated, including changes to the scheduling terms.  DWR agrees to provide such notice as soon as possible following the negotiation of any changed provisions and in any case prior to the time that any changed provisions become effective.

2.

Utility agrees to schedule Contracts in accordance with their terms and in accordance with the requirements of the Control Area operator or operators with whom the Contract must be scheduled to provide for power delivery.

II.

ISO Ancillary Service (AS) Market.  Among the Contracts are resources that are or may be qualified to be bid into the ISO’s Ancillary Services (“AS”) market or that Utility may use in its self-provision of AS.  Utility is authorized to develop protocols and procedures for the use of DWR resources for AS.  Utility shall, upon DWR’s request, provide to DWR such information concerning Utility’s intended use of DWR resources for AS as DWR may reasonably request for planning and revenue requirement purposes.

III.

Surplus Energy Sales and Energy Exchanges - Prior to MRTU Effective Date.  The provisions set forth under this Section III shall be applicable prior to the MRTU Effective Date.  

A.

Over-generation.  If the ISO announces an  over-generation situation Utility will  back down resources in accordance with the ISO tariff and  Good Utility Practice. In order to reduce the need for physical curtailment in over-generation situations, DWR and Utility shall develop pay for curtailment protocols and procedures that will enable Utility to instruct a must-take resource not to deliver energy under specified conditions. The costs and charges associated with mitigation of an over-generation situation shall be allocated among the Parties on a pro-rata basis consistent with the surplus sales allocation principles set forth in Exhibit C.

B.

Energy Exchange Arrangements.  Existing non-DWR/CERS exchanges and those that might be transacted post-2002, will be considered URG exchanges. The accounting of energy necessary to support energy exchanges is addressed in Exhibit C.

C.

Surplus Energy Sales Arrangement.  Utility shall on a monthly basis prepare a sales plan addressing all surplus sales, including without limitation sales to manage over-generation, contemplated by the Utility for review by DWR.  Such plan shall address sales of power from the combined portfolio of URG resources and Contracts, which will be administered by Utility on its own behalf and acting as DWR’s limited agent. As specified in Section 2.02 of the Operating Order, Utility shall pursue surplus sales in a fashion reasonably designed to serve the overall best interests of retail electric customers based on information known or could have been known by Utility at the time.  Utility agrees to include sufficient details in the sales plans to allow DWR to satisfy its financial management and reporting requirements. To the extent there is surplus power uncommitted to a forward energy surplus sales transaction, Utility shall be required to bid such surplus energy in the day-ahead, hour-ahead or real-time market.  Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective.  The costs of transmission service, ISO charges and the costs of firm transmission rights associated with such surplus energy sales transactions shall be treated in accordance with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C.  

IV.

Outage Coordination and Determination of Resource Availability of Contracts.  Utility shall communicate with the Scheduling Coordinator of each Contract to coordinate, approve, document and report planned Contract outages.  For those Contracts where resource availability affects capacity payments, Utility will use good faith efforts to verify Supplier’s actual resource availability, and keep records of resource availability as reported by Supplier.  In addition, Utility shall document all outages (forced and planned) and notices of outages of DWR contract resources and provide such documents to DWR within five (5) business days after the end of each calendar month.  

A-

DWR/SDG&E EXHIBIT B

FUEL MANAGEMENT PROTOCOLS

EXHIBIT B

FUEL MANAGEMENT PROTOCOLS

Certain of the Contracts listed on Schedule 1 of the Operating Order provide DWR the option of either (i) letting the Supplier provide the necessary natural gas for its generating units at an index-based price or agreed upon fixed price or (ii) DWR procuring the gas supply and causing such supply to be delivered to the Supplier under a tolling arrangement (“Fuel Option”).  Certain of the Contracts with Fuel Option provide that DWR can decide on a monthly basis whether to procure the gas and others provide that the decision be made annually or semi-annually when DWR reviews the Supplier’s proposed fuel plan.

The purpose of this Exhibit B is to describe the relationship which will exist between DWR and Utility and the specific responsibilities of each as they all relate to managing the natural gas provisions of the Contracts which include Fuel Options.  Specifically, this Exhibit B will address responsibilities for the following activities: (i) determining types and lengths of gas contracts, (ii) nominating deliveries, (iii) contracting for gas transportation and storage, (iv) managing imbalances, (v) reviewing, authorizing and making payment of gas invoices and (vi) determining and implementing hedge strategies, as appropriate.  

I.

Operating Relationship Between DWR and Utility

While DWR will retain legal and financial responsibility for gas and related services, Utility shall, as a limited agent acting for DWR, perform the administrative and operational activities, as further specified below, required to ensure adequate gas is supplied to Suppliers’ generating units, consistent with the tolling provisions included in the Contracts.  The intent of this relationship is to provide Utility sufficient flexibility and authority to execute normal day-to-day activities associated with managing the fuel provisions of tolling Contracts and procurement of natural gas and related services, as a limited agent acting on behalf of DWR without direct involvement by DWR but in a manner consistent with Utility Gas Supply Plans which have been reviewed and approved by DWR and the Commission.  

II.

Fuel Activities

Consistent with the terms of the Contracts with Fuel Options, Utility shall have administrative and operational authority to act, as a limited agent, for fuel supply related activities, consistent with the following goals and guidelines whenever Utility has recommended, and DWR has reviewed and approved such recommendation that gas for a Contract with Fuel Option be caused to be supplied by Utility from a list of approved providers.

1.

Utility shall use reasonable commercial efforts to secure delivery of gas in a reliable manner and consistent with gas requirements for producing scheduled energy.

2.

Utility shall develop a portfolio of gas supply for the Contracts that contain Fuel Options and where Utility is to supply gas, acting as limited agent on behalf of DWR, consistent with the approved Utility Gas Supply Plans.  Such portfolio should be diversified in terms of price mechanism, period of performance, and gas suppliers.

3.

Utility shall develop a portfolio of supply which is reasonably priced relative to the market and in accordance with an approved Utility Gas Supply Plan.

III.

Review of Supplier Fuel Plans

In accordance with the terms of each of the Contracts with Fuel Options, Utility, acting as a limited agent on behalf of DWR, shall review each fuel plan prepared and submitted by the Supplier, and forwarded to the Utility by DWR, and determine whether to recommend (i) approval of the Supplier Fuel Plan and authorization for the Supplier to provide gas to its generating unit(s), or (ii) procurement and management of gas supplies to the generating unit(s) by Utility.  Utility, acting as a limited agent on behalf of DWR, shall advise DWR and the Commission on a timely basis of its recommendation regarding responsibility for supplying natural gas.  DWR shall, on a timely basis, review Utility’s recommendation and either approve or identify requested changes.  Once approved, Utility shall advise the Supplier in accordance with the time requirements included in the appropriate Contract with Fuel Option.  In addition, for any Supplier Fuel Plans which have been implemented and are operative as of the Effective Date, and where DWR has previously elected to be responsible for gas supply, Utility may advise DWR that it would rather have Supplier provide the gas as of the Effective Date.  DWR shall coordinate with Utility and Supplier to revise such Supplier Fuel Plans, to the extent possible, prior to the Effective Date.   

IV.

Fuel Procurement Strategies

Under the Contracts with Fuel Option, upon Utility’s recommendation, and DWR’s review and approval of such recommendation, Utility will be responsible for procuring the natural gas fuel from a list of approved gas providers. Utility shall, acting as the limited agent of DWR, have administrative and operational responsibility for determining its gas procurement strategies, including but not limited to (i) types of contracts, (ii) length of contracts, (iii) pricing terms, (iv) use of storage, (v) types of gas transportation, (vi) delivery point(s), (vii) whether and how to obtain gas price forecasts, (viii) if and what risk management tools are to be used, and (ix) how to maintain current market intelligence.  

Utility shall consolidate these strategies and submit them to DWR and the Commission as a “Utility Gas Supply Plan” by April 17, 2003 and, thereafter on a semi-annual basis initially but was subsequently revised to be submitted on an annual basis during the Term.  Utility may also provide a copy of such Gas Supply Plan to DWR in advance of the filing with the Commission so as to be able to indicate DWR’s approval of such plan.  Utility shall indicate in its Advice Letter filing to the Commission whether DWR has approved such plan as appropriate.  DWR shall also formally notify the Commission when it has approved such plan.

DWR and the Commission will review and approve the Utility Gas Supply Plans.  In the event of conflicting guidance between the Commission and DWR regarding various aspects of the Gas Supply Plan they respectively approve or reject, where DWR only approves a subset of what the Commission approves, then Utility shall operate within the sphere of DWR’s approval.  If, however, the Commission explicitly rejects portions of the Gas Supply Plan that DWR would authorize, then Utility must operate within the limitations of the Commission’s decision.  After a reasonable period of time operating within the framework of the Gas Supply Plans and the Commission’s and DWR’s respective approval and/or rejection of various pieces of the Gas Supply Plan, the Parties agree to meet and confer to determine whether the approval process may need to be revised in some manner, and Utility shall submit to Commission any such proposed revisions. Once approved, Utility may act within such Utility Gas Supply Plan without further DWR involvement, except as provided below.

V.

Gas Purchasing

Utility and DWR shall jointly determine a list of approved gas providers who can be used to supply gas under the Contracts with Fuel Options.  Master agreements intended to cover normal day-to-day volumes will then be executed with such approved providers.  While DWR will be the executing party under all DWR gas contracts, such agreements shall specifically authorize Utility to act for and on behalf of DWR, as a limited agent, in negotiating specific prices, quantities and delivery periods for specific purchases under such master agreements; provided however, on the earliest practicable date after the issuance date of the Operating Order, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.  If Utility determines it would be beneficial to enter into any DWR gas contract which exceeds 3 months or have a total value exceeding $10 million, it shall negotiate such agreement(s) and submit them to DWR for advance approval and execution.   

VI.

Gas Transportation

Utility shall have responsibility for recommending to DWR which pipelines should transport gas if Utility, acting as limited agent on behalf of DWR is to supply gas under a Contract with Fuel Option.  Following approval of or revision of Utility Gas Supply Plan, Utility shall negotiate firm and/or interruptible agreements with such pipelines, consistent with the Utility Gas Supply Plan and submit them to DWR for execution.  While DWR will be the executing party, such agreements with pipelines shall specifically authorize Utility to act for and on behalf of DWR in nominating gas deliveries, making imbalance trades and managing gas volumes transported under such agreements  provided, however, on the earliest practicable date after the issuance date of the Operating Order, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.

VII.

Gas Scheduling

If permitted under the Contracts, the Utility shall have full administrative and operational responsibility for scheduling gas deliveries, whether to a specific generating plant or to storage for all gas contracts entered into by DWR or by Utility on DWR’s behalf pursuant to this Exhibit B.  This function includes use of interstate and intrastate gas pipeline provider websites, confirming via telephone, and all other activities required to move gas from the designated delivery point, as determined by the Utility, to its destination, as determined by the Utility.

VIII.

Storage Capacity, Injections and Withdrawals

Utility shall have responsibility for devising plans for gas storage, if Utility, acting as limited agent on behalf of DWR, is to supply gas under Contracts with Fuel Option from a list of approved providers.   Following approval of the Utility Gas Supply Plans, Utility shall negotiate firm and/or interruptible agreements with such storage service providers and submit them to DWR for execution.  While DWR will be the executing party with DWR remaining the principal under such contracts, such agreements with storage service providers shall specifically authorize Utility to act for and on behalf of DWR in nominating gas injections and withdrawals under such agreements; provided, however, on the earliest practicable date after the issuance date of the Operating Order, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.   

IX.

Managing Gas Delivery/Usage Imbalances

For gas that it purchases and transports on behalf of DWR, Utility shall have full administrative and operational responsibility for monitoring and managing the daily status of gas usage vs. gas deliveries (i.e. gas imbalances).  In addition, to the extent that gas transportation providers issue operational flow orders or require adjustments in scheduled gas deliveries due to system constraints, Utility, acting as limited agent on behalf of DWR, shall be responsible for compliance with such orders.  Utility shall also be responsible for any penalties imposed by gas transportation providers for imbalances caused by Utility, due to its failure to exercise prudent gas management practices.

X.

Invoice Review, Approval and Payment

For natural gas, pipeline transportation and storage services it purchases in accordance with this Exhibit B, Utility, acting as limited agent on behalf of DWR, shall have responsibility for receiving invoices from gas, transportation and storage suppliers, reviewing them for accuracy, approving/rejecting invoices for payment and forwarding to DWR for payment; provided, however, on the earliest practicable date after the issuance date of the Operating Order, DWR agrees to cause Utility to be authorized to receive such information from Suppliers.  Utility shall provide DWR sufficient documentation to verify payment of the invoices.

XI.

Forecasting

Utility shall be responsible for all gas price, demand and supply forecasts which Utility believes are consistent with any accepted gas supply responsibilities.  

XII.

Risk Management

Utility shall develop and include in its Gas Supply Plans, plans for the hedging of DWR Fuel Supply costs.  Final decisions relating to the use or non-use of financial tools such as futures, options and swaps to hedge future gas price exposure on any gas volumes not hedged by Utility under the Utility Gas Supply Plans shall be made and implemented by DWR.  Any such contracts executed by DWR on a “portfolio basis” should be utility-specific.

XIII.

Market Intelligence

Any and all efforts to obtain, analyze and utilize market intelligence for decision-making purposes shall be the responsibility of Utility.  

XIV.

Payment of Gas Costs

For natural gas, pipeline transportation, financial hedges and storage services that are purchased and provided by a Supplier under an approved Fuel Supply Plan, DWR shall pay such gas related costs as part of the invoice for commodity, product, or services submitted by the Supplier.  For natural gas, pipeline transportation and storage services provided under DWR contracts and administered by Utility on behalf of DWR, DWR shall pay invoices after they have been reviewed and approved for payment by Utility.

XV.

Allocation of Existing DWR Gas Contracts

From time to time, DWR enters into fuel supply, transportation and storage contract, consistent with the Gas Supply Plans submitted to the Commission by the Utility.  DWR will continue to enter into such contracts in connection with the administration of DWR Contracts.  In addition, consistent with Decision 03-10-016 dated October 2, 2003, issued by the Commission, the Utility will continue to administer the allocated portion of the Williams Energy Marketing and Trading Company’s gas supply contract (“Williams Gas Contract”), allocated as set forth in Attachment 1 to this Exhibit B.  The Utility will administer such fuel supply, transportation and storage contracts, including the Williams Gas Contract, and perform such functions including but not limited to (i) scheduling gas transportation, (ii) confirming gas deliveries, (iii) nominating gas withdrawals from and injections into storage, if applicable, and (iv) reviewing and approving invoices for payment.  When approved, invoices shall be transmitted to DWR for payment within 10 days of receipt of invoice from the gas supplier, gas storage or gas transportation provider.

XVI.

Pre-existing Financial Hedge Instruments

If DWR has entered into any financial hedge transactions that will remain operable after the Effective Date of the Existing Operating Arrangement or this 2010 Operating Order, DWR shall retain full administrative and operational control over such transactions.

B-

Attachment 1

to Exhibit B

Williams Gas Contract Allocation Table

B-

DWR/SDG&E EXHIBIT C

SETTLEMENT PRINCIPLES
FOR REMITTANCES AND
SURPLUS REVENUES

EXHIBIT C

SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES

This Exhibit C outlines the principles by which Utility will calculate revenues associated with surplus energy sales prior to the MRTU Effective Date, and DWR energy delivered to retail customers.  This Exhibit C also addresses the information that Utility will provide to DWR to support DWR payment of Contract invoices, and invoices from natural gas supplier(s) for fuel provided to service DWR Contracts where tolling options have been implemented.  

This Exhibit C works in conjunction with the applicable Servicing Arrangement with Utility for purposes of determining the remittance amounts by Utility, which serves as DWR’s billing and collection agent.

Prior to the MRTU Effective Date, in accordance with the Contract Allocation Order¹, Part I of this Exhibit C provides that:

·

Revenues will be allocated for both surplus sales and retail customer deliveries

·

Revenues will be allocated pro rata, based on dispatched quantities of energy

·

The principle of balancing least cost economic dispatch while maintaining reliability is reinforced through these revenue allocation protocols.

·

Surplus sales quantities will be calculated as the difference between Utility’s Energy Delivery Obligations (EDO) and the combination of energy from URG and energy dispatched from the Contracts.

Where Utility’s Energy Delivery Obligations is defined as: (1) Utility’s retail load which includes distribution losses, (2) all pump-back loads, (3) energy exchange transactions between Utility and counter parties, (4) wholesale obligations, existing as of January 1, 2003, and (5) transmission losses.

On and after the MRTU Effective Date, as further provided in that certain Memorandum of Understanding, dated as of February 4, 2009, which was approved by the Commission on March 13, 2009 (“MOU”), Remittances to DWR will be allocated as further provided in Part II hereof.

The principles herein, together with the applicable methods and calculations contained in the Servicing Arrangement, form a substantive component of the accounting protocols required to implement the Contract Allocation Order, as certain of the principles are modified on and after the MRTU Effective Date as provided in this 2010 Operating Order and the Servicing Arrangement.  This Exhibit should also be read in conjunction with Exhibit F (“Data Requirements”).

Exhibit F may periodically be modified to include all data that DWR will require to verify Remittances to DWR or to implement protocol changes.  Utility and DWR agree to modify Exhibit F to include or exclude information reasonably determined by DWR to allow DWR to verify Net DWR Retail Supply and, prior to the MRTU Effective Date, the surplus remittances.  On and after the MRTU Effective Date, Utility and DWR further agree to review and modify Exhibit F, from time to time, to include or exclude such information so as to allow DWR to perform such internal procedures that are reasonable and determined appropriate by DWR, and such validation, analysis and audit of the settlement functions to be performed by Utility, as DWR’s limited agent, consistent with the principles and parameters set forth in Part III of this Exhibit C.

I.

Utility Remittance to DWR - Prior to the MRTU Effective Date

The provisions under this Part I shall be effective to but not including the MRTU Effective Date.  On and after the MRTU Effective Date, the provisions under Part II shall control.  

Utility shall remit to DWR an Energy Payment for the delivery of Contract energy to Utility retail customers and a separate payment for DWR’s share of Surplus Energy Sales Revenues.  The principles for the remittances to DWR of Surplus Energy Sales Revenue and Energy Payment are contained in Sections A and B, respectively, of this Part I of this Exhibit C.  The details for determination of the remittances to DWR by Utility are contained in the Servicing Arrangement.

A.

Utility Remittance to DWR of Revenue from Surplus Energy Sales

Surplus Energy and Revenues

Surplus energy exists when dispatched supply from Utility portfolio and DWR Contracts exceeds Utility’s Energy Delivery Obligations.  When such a condition exists, the revenues from the sale of surplus energy shall be shared between Utility and DWR.  Surplus sale revenues can occur either through a forward market sale or a delivery of the excess energy into the ISO real time market.  In addition to the sharing of surplus energy revenues, the quantity of any surplus energy shall likewise be shared between Utility and DWR, and used in the determination of the Hourly Percentage Factor described in Section B of this Part I.

Surplus energy sales revenues shall be placed by Utility into a separate account (Surplus Sales Fund) to be held in trust and shall be disbursed by Utility to DWR in accordance with the pro-rata allocation principles in this Exhibit C and consistent with the provisions of Service Attachment 2 of the Servicing Arrangement.  For surplus energy sales to third parties, Utility shall apply reasonable credit risk management criteria that is consistent with industry accepted credit standards.

Surplus Energy Quantity

The Surplus Energy quantity shall be determined by subtracting Utility’s Energy Delivery Obligations from the sum of dispatched URG energy and dispatched DWR Supply.  URG energy shall include dispatched energy from URG, new Utility contracts and Utility market purchases plus adjustments for Ancillary Services and ISO Instructed Energy as described under “Definitions and Adjustments.”  DWR Supply shall include dispatched energy from DWR must take and dispatchable contracts plus adjustments described below.   

DWR Surplus Energy quantity shall be the product of Surplus Energy quantity multiplied by the DWR Surplus Energy Percentage.  Utility Surplus Energy quantity shall be the remaining portion of Surplus Energy.  Both Utility and DWR Surplus Energy quantities shall be applied to the respective Party’s energy supply quantities for determination of the Hourly Percentage Factor described in Section B of this Part I.

Surplus Energy Sales Revenues

Surplus Energy Sales Revenues shall be shared between Utility and DWR in the same manner as Surplus Energy.   

Forward Market Sale

DWR share of revenues from a forward market sale of surplus energy shall be the product of the net revenue multiplied by the DWR Surplus Energy Percentage.  Utility share of these revenues shall be net revenue less DWR share of net revenues.  Revenues from a forward market sale shall not be distributed to the Parties until after Utility receives the revenues from the sales and pays sale-related charges.  Shared revenues from forward market sales shall be net of transmission costs and broker fees.

ISO Real Time Market Sales

Revenues from delivery of surplus energy to the ISO real time market shall be determined from the product of positive load or supply deviation multiplied by the ISO real time market price.  These revenues will be netted against any ISO charges related to the load deviation, including a negative ISO price.  Load deviation is determined by subtracting the Utility metered load from the Final Hour Ahead Load Schedule, however only positive quantities, where schedule exceeds meter, reflect surplus conditions for revenue sharing. Supply deviation is determined by subtracting the Final Hour Ahead Supply Schedule (adjusted by real time instructions) from metered supply, however, only positive quantities, where meter exceeds the adjusted schedule, reflect surplus conditions for revenue sharing.

DWR share of revenues from delivery of surplus energy to ISO real time market shall be the product of the net revenues multiplied by the DWR Surplus Energy Percentage.  Utility share of these net revenues shall be the net revenue less DWR share of net revenues.  Revenues from delivery of surplus energy to the ISO real-time market shall not be distributed to the Parties until after the Utility received payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

Over-generation Periods

During periods of over-generation condition as announced by the ISO, surplus sales may be made at very low, zero or even negative prices.  In such conditions, the surplus sale revenue calculations as described above still hold.  However it is recognized that the sales may result in little or no revenue.  Sales could even be done at a cost to the seller.  That seller could be Utility or the ISO selling in an “out-of-market” condition.  During these conditions, ISO-related charges assigned to Utility for such sales (e.g. – ISO selling out-of-market) are included in the surplus sales revenue as a cost.  During over-generation conditions there may be no market in which to sell surplus energy.  In that event, or in expectation of that event, Utility shall declare that no valid market exists for surplus energy and shall begin curtailing must-take resources in accordance with Utility’s procedures for mitigating over-generation conditions.  Such mitigation measures shall be consistent with good utility practice, specifically hydroelectric facilities at spill or near-spill conditions and nuclear facilities scheduled by Utility are the last resources to be reduced in power output.

Over-generation for purposes of this Exhibit C is defined as the condition in which total supply exceeds total loads in the ISO control area.

Revenues or costs from delivery of surplus energy to the ISO real time market under an over-generation condition shall not be distributed to the Parties until after Utility receives payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

Calculation of Surplus Energy Percentage

DWR Surplus Energy Percentage shall be equal to the pro rata share of DWR Supply to the sum of Utility Supply and DWR Supply, expressed as follows:

DWR Surplus Energy Percentage = DWR Supply / (Utility Supply + DWR Supply)  

Where:

DWR Supply is total energy dispatched from DWR Contracts with adjustments for transmission losses, Ancillary Services and ISO Instructed Energy transactions described below.

Utility Supply is total energy dispatched from URG, new Utility contracts and Utility market purchases with adjustments for transmission losses, existing wholesale obligations, Ancillary Services and ISO Instructed Energy, exchange transactions, all pumping loads, and ISO Uninstructed Energy as described below.

B.

Definitions and Adjustments

Certain energy and capacity transactions, which may be conducted by Utility in its normal course of business, may affect the Utility and DWR Supply quantities used in pro rata calculations.

Exchanges are transactions where energy is delivered to a third party in one period and a similar, but not necessarily equal, amount of energy is returned by third party in a different period.  For the purposes of pro rata share calculation, exchanges use and supplement energy from the Utility Supply.

Forward Sales are transactions where energy is sold in a forward market to balance supply with demand.  In general, for the purposes of remittance determination, forward sales are made using energy from the joint Utility/DWR portfolio.

Ancillary Services are transactions where capacity from certain qualifying resources is sold to ISO for ancillary services rather than being used as energy to serve retail load.   Resources from both Utility portfolio and DWR Contracts may qualify for use as ancillary services.  Since the capacity used for ancillary services does not serve retail energy load, ancillary service capacity is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination.  If Utility or DWR Contract resource capacity is used for ancillary services, the capacity quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the ancillary services as well as all associated transaction costs and ISO charges.  

ISO Instructed Energy is a transaction where certain qualifying resources are able to sell energy from unused capacity to the ISO in the real time market.  The energy delivered from these resources is directed by the ISO in real time to balance supply and load imbalances on the grid.  Either Utility portfolio or DWR Contracts may contain resources that have ability to provide instructed energy to ISO.  Since instructed energy is resource specific and does not directly serve the retail load of any utility, instructed energy is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination.  If Utility or DWR Contract resources are dispatched as instructed energy, the energy quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the instructed energy as well as all associated transaction costs and ISO charges.    

ISO Uninstructed Energy is a transaction where energy is delivered or received from the ISO grid in the real time based on the actual consumption of retail load and actual deliveries of supply resources.   

Uninstructed Retail Load Deviations

Uninstructed Load Deviations are the difference between scheduled load and metered load.  If retail load deviations are positive (schedule exceeds meter), it is considered that any excess supply (less any positive uninstructed supply deviation) was dispatched from the joint Utility/DWR portfolio in excess of quantity needed to serve retail load, and that the ISO credit for the excess supply should be shared pro rata as described above.  If retail load deviations are negative (meter exceed schedule), to the extent deviations are not compensated by a positive uninstructed supply deviation, it is considered that Utility had to procure additional supply from ISO real time market.  The negative load deviation quantity procured from ISO real time market is considered a Utility market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes.

Uninstructed Supply Deviations

Uninstructed Supply Deviations are the difference between scheduled supply and metered supply plus an ISO allocation for transmission losses.  If Utility’s net supply deviations¹ are positive (meter exceeds schedule), to the extent not needed to compensate a negative uninstructed retail load deviation, it is considered that excess supply was a Utility market sale and will not be included in Utility Supply for pro rate calculation purposes.  If Utility’s net supply deviations are negative (schedule exceeds meter), to the extent not balanced by a positive uninstructed retail load deviation, it is considered that Utility had to procure additional supply from the ISO real time market.  The negative supply deviation quantity procured from the ISO real time market is considered a Utility market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes.

Transmission Losses

Transmission loss is defined as Energy that is lost due to the process of transmitting energy from supply source to load.  Therefore, supply resources from DWR Contracts and Utility Supply have distinct and identifiable quantity of transmission losses.  Utility and DWR Supply should be net of transmission losses because of energy that is delivered to retail customers (i.e. load) equals quantity of supply less losses.

C.

Utility Remittance to DWR for Sales of DWR Energy to Utility Retail Customers –Energy Payment

Utility shall remit to DWR its Energy Payments according to the terms of each Utility’s respective Servicing Arrangement.

The DWR Energy Payment is billed by each utility to customers in accordance with the terms of each applicable Utility Servicing Arrangement.  The DWR Energy Payment is billed kWhs served by Net DWR Supply at the applicable CPUC approved DWR rate.  Net DWR Supply is total DWR Supply less DWR share of surplus energy.  The DWR Energy Payment is allocated based on the percentage of energy supplied by DWR to Utility, which is the “Hourly Percentage Factor” multiplied by the retail load of each customer.  The Hourly Percentage Factor is determined by calculating the percentage of net energy supplied by DWR to Utility to serve retail load, as expressed below:

Hourly Percentage Factor = Net DWR Supply / (Net Utility Supply + Net DWR Supply)

Where:

Net DWR Supply is DWR Supply quantity used for the determination of DWR Surplus Energy Percentage less DWR share of surplus energy quantity, which is determined by the product of surplus energy multiplied by DWR Surplus Energy Percentage.

Net Utility Supply is Utility Supply quantity used for the determination of DWR Surplus Energy Percentage less Utility share of surplus energy quantity, which is total surplus energy less the DWR share of surplus energy quantity.

In the Event of any conflict between the formulas and procedures in this Exhibit C and the formulas and procedures in Utility’s Servicing Arrangement, those contained in Utility’s Servicing Arrangement shall govern.

D.

Other

In the Event of any conflict between the formulas and procedures in this Part I of Exhibit C and the formulas and procedures in Utility’s Servicing Arrangement, those contained in Utility’s Servicing Arrangement shall govern.

II.

Utility Remittance to DWR - On and After the MRTU Effective Date

On and after the MRTU Effective Date, Utility shall make Remittances to DWR for the delivery of Contract energy to Utility retail customers, all as set forth under this Part II of Exhibit C.  The details for determination of the Remittances to DWR by Utility are contained in the Servicing Arrangement.  

A.

DWR Remittances

For billing purposes, Bundled Customers’ energy usage for DWR Bundled Customer Power Charge shall be based on “DWR Percentage Calculation” and shall be billed by each Utility to Customers in accordance with the terms of each applicable Servicing Arrangement.  DWR Percentage Calculation determines the percentage of DWR Contract power relative to the total “Estimated Bundled Customer Load” as expressed below:

DWR Percentage Calculation = Summation of Hourly DWR Remittance Basis Power (MWh), divided by Summation of Hourly Estimated Bundled Customer Load (MWh)

The term “DWR Remittance Basis” refers to the aggregated quantity and amount of energy (MWh) set forth in the table in Schedule 1 of this 2010 Operating Order in the column noted as “Remittance Basis” and as may be further modified under Section B entitled “Real Time Energy Dispatch Charges & Credits” below.

The term “Estimated Bundled Customer Load” is an estimate of Power purchased on behalf of the Utility’s Bundled Customers within the Utility’s Service Area.  The Estimated Bundled Customer Load is calculated hourly using the actual Service Area MW load from the Utility’s Energy Management System (EMS).   Estimated Bundled Customer Load is derived from in-area generation and net power flows at the Utility’s boundary and adjusted by removing actual pumping load (from EMS), estimate of Transmission Losses, and estimate of “Non-Bundled Customer Load”, consisting of Direct Access Customers, Customer Generation Departing Load Customers, Municipal Departing Load Customers and Community Choice Aggregation Customers, as such Customer Types are specifically defined in the 2007 Servicing Orders and may exist from time to time with respect to each Utility, and excluding other specified categories as further provided in the 2010 Servicing Order.  

The term “Hourly Estimated Bundled Customer Load” refers to:

Hourly Estimated Bundled Customer Load (MW) = EMS Service Area Load (MW) – Actual IOU pumping load - Transmission Losses (MW) - DA Customers (MW) - CGDL Customers (MW) - MDL Customers - CCA Customers (MW )

Further details of the Estimated Bundled Customer Load are provided for the Utility in Appendix A-2 of Attachment B of the Utility’s Servicing Arrangement.  

The Utility represents that the Hourly Estimated Bundled Customer Load as presented to DWR for each hour of each trade date, commencing on April 1, 2009, has been determined consistent with that general description set forth in Exhibit C, Part II(A) of the Operating Order.  The Utility further represents that commencing April 1, 2009 it has submitted the same Hourly Estimated Bundled Customer Load to the ISO for Operational Meter Analysis and Reporting (“OMAR”) requirements related to Bundled Customer load for credit statement and payment acceleration purposes.  

In the event that the Utility expects to terminate the submission of that Hourly Estimated Bundled Customer Load for OMAR requirements, the Utility agrees to provide reasonable written notice to DWR so that a mutually agreeable arrangement related to the submission of Hourly Estimated Bundled Customer Load can be discussed.  In addition, in the event that a “meet and confer” shall occur as described under the heading “Meet and Confer Obligation for Significant Load Deviations” in Exhibit C, Part II(A) of the Operating Order, the scope of such meet and confer shall include DWR’s ability to review and audit of the hourly assumptions used by the Utility to determine Hourly Estimated Bundled Customer Load provided to DWR.  The Parties agree that such review or audit of the hourly assumptions shall occur at the Utility offices.

Billed Amount

The Billed Amount for DWR Bundled Customer Power Charge will be the product of the DWR Percentage Factor, the Bundled Customer’s electric consumption and the Bundled Customer Power Charge rate in dollars per kilowatt-hours.

Billed Amount for DWR Bundled Customers Power Charge = DWR Percentage Factor x Bundled Customer’s electric consumption (kWh) x Bundled Customer Power Charge rate ($/kWh)

Remittances for DWR Bundled Customer Power Charge  

The Daily Remittance of DWR Bundled Customer Power Charge shall be determined based upon the Billed Amount for DWR Bundled Customers by each Utility by either applying a collection curve factor to the Billed Amount for DWR Bundled Customers, or by remitting the actual amounts collected from Bundled Customers, all as more specifically set forth in the appropriate 2007 Servicing Order.

Meet and Confer Obligation for Significant Load Deviations

The Utility will provide a monthly report of the load information, as more fully described in Appendix A-2 of Attachment B and Attachment C of the Servicing Arrangement.  The Utility will provide such monthly reports to the DWR by the fifth Business Day following the publication of the ISO’s Recalculation Settlement Statement for the last trade date of a calendar month ..

Individual Utility Deviation.  If, for a period of two consecutive months, the monthly simple average of the Utility ’s ISO metered load (submitted to the ISO at 43 calendar days currently and such other interval as may be required after the ISO implementation of “Payment Acceleration” procedures) deviates by at least three percent (3%) from the Estimated Bundled Customer Load value for the Utility (as such term is described under this Section A), DWR and the Utility shall meet and confer to discuss the cause of the deviation, upon written request by either Party.

Average Deviation Amount for All Utilities.  If, for any one month, the monthly simple averages of each of the three (3) Utilities’ ISO metered load, individually, deviates by at least three percent (3%) from the Estimated Bundled Customer Load values for the respective Utilities (as such term is described in this Section A), DWR and each Utility shall meet and confer to discuss the cause of the deviations, upon written request by any of the Parties.

Scope of Meet and Confer.  For the purposes of this section, the “meet and confer” shall mean the affected Utility or Utilities, as the case may be, will engage in a conference call with DWR to discuss: (i) the Utility’s or Utilities’ efforts to determine the root cause of the variance between Estimated Bundled Customer Load values and ISO metered load, and (ii) corrective action , if any, planned by the Utility or Utilities to address the variance.  In addition, in the event the variance between Estimated Bundled Customer L oad values and ISO metered load requires DWR to revise its revenue requirement determination for the year in which the variance occurs, the Utilities agree to support an appropriate revised determination by DWR.

B.

Real Time Energy Dispatch Charges & Credits

The provisions under this Section B apply to Dispatchable Units - and as to Instructed and Uninstructed Real Time Energy, distinguished by whether the Utility is to act as the Scheduling Coordinator (“SC”) under the Contract or not.  

1.

When Utility is SC for the contracts identified in Section B of Part III of this Exhibit C:  

Utility will pay retail Remittances on the metered amount and Utility will retain ISO market revenues / charges, consistent with the terms of the applicable Contract.  

2.

If the Utility is not the SC for the Dispatchable Unit:

DWR or the counterparty, as provided by the Contract, will receive market revenues for the real time energy via the SC and DWR will not be paid retail Remittances from the Utility for the real time dispatch.

C.

Transmission Losses

Under MRTU, transmission losses are converted from physical adjustments to financial adjustments.  To simplify the process and maintain equity across parties, the Parties agree to the following principles:

o

DWR revenue requirement, which previously reduced the quantity of energy based upon transmission losses, will not reduce the quantity of energy to adjust for transmission losses.

o

This change should be clearly identified or footnoted within future DWR Revenue Requirement documents.

D.

Other

In the Event of any conflict between the formulas and procedures in this Part II of this Exhibit C and the formulas and procedures in Utility’s Servicing Arrangement, those contained in Utility’s Servicing Arrangement shall govern.

III.

Bilateral Settlement

Under the Contract Allocation Order but prior to the date that any Contract is novated to Utility, DWR remains financially obligated for the Contracts.  DWR will continue to pay Suppliers and this requires DWR to apply appropriate procedures and controls to ensure that payments are made accurately and in a timely manner.  Information supporting Contract settlements will be provided by Utility, and additional information may also be required to address contract performance issues (such as availability and other items as discussed in Exhibit E) and to allow DWR to settle disputes in an appropriate manner, as set forth in Section 13.03 of the body of this Operating Order.

DWR requires sufficient information to support payment requests so that it can meet the accountability requirements of the State Controller’s Office and the State Auditor, and simultaneously comply with the applicable statutes concerning disbursement of public monies.  The Utility shall reconcile schedules with Suppliers invoice.  DWR shall make the associated payments to Suppliers after performing its verification prior to the MRTU Effective Date, and, on and after the MRTU Effective Date, such internal procedures that are reasonable and determined appropriate by DWR, and such validation, analysis and audit of the settlement function performed by Utility, as DWR’s limited agent, consistent with the principles and parameters set forth in this Part III of this Exhibit C.  In addition, the Utility will also provide the data as required in Exhibit F to allow DWR to perform its duties in a timely manner as set forth herein.

Prior to the MRTU Effective Date, DWR shall continue to perform validation of settlement data and invoices and pay Contract costs directly to the Suppliers upon validation of invoices.

On and after the MRTU Effective Date, the Parties have agreed to the specific provisions related to Real Time Energy Dispatch Charges and Credits as set forth in Section B of Part II of this Exhibit C.  In addition, the Parties agree to the following principles related to Contract settlements:

A.

Ancillary Services

·

If the Utility is not the SC under the Contract:   Revenues from ancillary services are passed through from the counterparty to DWR (to the extent so provided by the Contract) and, in turn, to the Utility, via the Utility Specific Balancing Accounts

·

When the Utility is SC for the Contracts as identified in Section B of Part III of this Exhibit C, then :  Revenues for ancillary services (to the extent so provided by the Contract) will be allocated to the Utility to the extent that DWR is entitled to such revenues

B.

Responsibility for ISO Charges and Credits - Generation Invoices

As to the Contracts specifically identified in Attachment A of the MOU, to the extent PG&E, SCE, or SDG&E becomes the SC for certain Contracts, the Utility that becomes the SC will take responsibility for the payment/receipt of ISO invoice charges and credits that are allocated to DWR under and consistent with the terms of the applicable Contract.  The Utilities have agreed to such responsibilities, to the extent they become the SC for the Contracts referenced in Attachment A of the MOU, but more recently updated as: (1) Sunrise, (2) JP Morgan D AL 1, AL5, (3) JP Morgan D HB1 and (4) JP Morgan D RB6.

In the event that a Utility or another entity identified by DWR becomes the SC for Contracts (other than those Contracts identified in the immediately preceding paragraph above), responsibility for ISO invoice charges and credits allocable to DWR shall be explicitly addressed at the time and in the document appointing such new SC.  

1.

Applicable to: SDG&E and SCE (when the Utility is SC for the contracts identified in the first paragraph under this Section B )

·

As SC, the Utility will be responsible for paying all ISO invoices in a timely manner.

·

Utility will be responsible for ISO charges and credits, as allocated between DWR and the counterparty pursuant to the Contract

·

With respect to ISO charges allocated to the counterparty pursuant to the Contract, in the event the counterparty does not pay such charges to the Utility, then the Utility and DWR shall refer to the procedure described in Section D below that reimburses the Utility and to provide DWR with sufficient information to collect those charges from the counterparty.

2.

Applicable to all 3 Utilities and when the Utility is the SC, for any Contracts other than those identified in the first paragraph of this Section B:

·

DWR and the appropriate Utility will agree upon the Remittance Basis and the treatment of market revenues for energy and Ancillary Services

·

DWR and the appropriate Utility will agree upon the responsibility for ISO charges and rights to ISO credits

C.

Bilateral Settlement Parameters On and After the MRTU Effective Date

1.

General.  On behalf of DWR, as its limited agent, Utility will perform all necessary settlement functions related to and in accordance with the terms of the applicable Allocated Contracts, and provide recommendations to allow DWR to make payments accurately and in a timely manner.  Utility shall perform such settlement functions consistent with Good Utility Practice.  

Settlement functions shall include but  are not limited to verification or appropriate review, as the case may be, of energy and related fuel charges, capacity, transmission charges, ISO charges and credits (as further described below), and contract performance related costs and credits, as further set forth in this Section C.  

2.

ISO Market Activity Related Settlements Parameters.  Settlement functions in the cases where Utility is the Suppliers’ Scheduling Coordinator, shall also include verification of ISO market activity in accordance with the terms of the Contracts.  

In addition, verification activities shall be performed as to each Contract’s ISO market activity where the Utility is not the Supplier’s Scheduling Coordinator, and where the Contract provides for the necessary information and appropriate timing to perform such activities. These activities shall be limited to ISO charges or credits where DWR is financially responsible or has the right to receive under the Contract.  Settlement processing of the ISO market activity of the Contracts may include but is not limited to the review, validation or verification, as appropriate, of charges or credits to confirm reasonableness and consistency with the operating history and record maintained by the Utility.  In addition, the Utility shall review such types of charges or revenues for consistency under provisions of the Contracts.  The types of charges or revenues may include but is not limited to:  

1)

Volume and prices of uninstructed imbalance energy charged or credited as invoiced;

2)

Volume and prices of instructed imbalance energy charged or credited as invoiced;

3)

Volume and prices of Ancillary Services charged or credited as invoiced;

4)

Compensation for start up cost and minimum load cost compensation as invoiced;

5)

Compensation for exceptional dispatch uplift compensation as invoiced;

6)

Verification of volume and prices of load uplift obligation trade offset and bid cost recovery charged or credited as invoiced; and

7)

Resource performance penalties such as uninstructed deviation penalties and ancillary service no pay penalties.

3.

Insufficient ISO Data for Settlement Verification.  In the event that the Utility determines that some of the data is not available for the Utility to verify certain ISO charges and credits, the Utility shall notify DWR and provide sufficient description of the ISO data reasonably necessary to complete the verification activities above.  DWR will request and facilitate Utility’s receipt of such ISO data from the counterparty. In the event that DWR subsequently is successful in obtaining such Utility notified necessary ISO data, upon receipt of such ISO data, the Utility shall commence its settlements verification of such ISO market activity prospectively.

4.

Recommendations on Invoice Payment.  The Utility shall provide recommendations to DWR on payment of bilateral invoices, including ISO charges and credits consistent with Section C of Part III of this Exhibit C, no later than five calendar days before the required contract payment date, or such other timeline that is mutually agreeable to both parties.  In the event the Utility recommendation for payment is different than the Supplier invoice, Utility shall provide a detailed explanation with support information to CDWR sufficiently in advance to allow DWR to settle disputes with the Contract counterparty in an appropriate manner.

D.

Additional Provisions Related to ISO Settlement Statements

1.

ISO Settlement Statements issued to Utility as Scheduling Coordinator of Specified Allocated Contracts.  As to the Allocated Contracts specifically identified in Annex 1 attached hereto, as such Annex 1 may be amended from time to time, to the extent that Utility becomes the Scheduling Coordinator as contemplated in Section II(G) of that certain Memorandum of Understanding, dated as of February 4, 2009, Utility will take responsibility for the timely payment, if any, to the ISO, taking into account such ISO charges and credits that are allocated to DWR and (i) any net payments owed to the Utility by the Supplier or (ii) any net credit owed to the Supplier by the Utility (collectively, “Supplier Portion of ISO Charges”).  

a.

Within five (5) Business Days of the Utility’s receipt of an ISO Invoice, the Utility shall determine the Supplier Portion of ISO Charges and (i) invoice DWR for such amount or (ii) advise DWR as to the net credit to be paid to DWR.  In each case, the Utility shall also provide the Supplier and DWR of such agreed-upon data.  

b.

In the case of any net payment owed to the Utility, within ten (10) Business Days of DWR receipt of an invoice from the Utility , DWR will pay the Utility the entire Supplier Portion of ISO Charges.  

c.

In the case of a net credit owed to the Supplier, within ten (10) Business Days of DWR receipt of such credit advice, the Utility will submit net credit payment.

d.

In either instance as described in (b) or (c) above, the same amount of the Supplier Portion of ISO Charges will be accounted and either credited to DWR (in the case of net payment owed by the Supplier as described in (b) above) or debited to DWR (in the case of net credit owed to the Supplier as described in (c) above) in DWR’s succeeding month’s Supplier’s invoice, consistent with the procedures agreed to between DWR and the Supplier.  

e.

In the event that the Supplier shall dispute the Utility determined Supplier Portion of ISO Charges, in the case net payment owed by the Supplier as described in (b) above, DWR agrees to pay the entire Utility determined Supplier Portion of ISO Charges to the Utility initially and pursue dispute resolution with the Utility.  In the case of dispute as to the net credit owed to the Supplier as described in (c) above, Utility will pay the Utility determined amount.  

As to the disputed portion, DWR agrees to enter into dispute resolution process with the Supplier, with such back-up data and information from the Utility, to resolve such dispute of the Supplier.  Upon resolution of such dispute by DWR, the disputed portion shall be communicated to the Supplier and the Utility.  

f.

Utility agrees to reconcile and account for such disputed portion in the succeeding month’s determination of the Supplier Portion of ISO Charges to address the adjusted amount, either positive or negative.  Such adjustment will be specifically noted in the notice to DWR and the Supplier described in (a) of this Section D and reflected in the immediately succeeding month’s invoice to DWR.  

Appropriate adjustments to the Supplier’s invoice will also be reflected, consistent with the agreement between DWR and Supplier.

2.

ISO Settlement Statement issued to Suppliers’ Non-Utility Scheduling Coordinators.  So long as appropriate settlement statements and necessary supporting details to validate and verify ISO Settlement Statements issued with respect to the Contracts to the Suppliers’ Scheduling Coordinators are available to Utility, Utility shall review, validate and verify all ISO charges/credits contained on all ISO Settlement Statements related to the Allocated Contracts.  

In the event that the settlement statements or supporting details available to the Utility with respect to the Supplier’s ISO Settlement Statements issued with respect to a Supplier are not determined to be sufficient as mutually determined by DWR and Utility, the Utility shall review the available data for reasonableness which review shall be commensurate with the quality and the quantity of the data available to the Utility.  

The obligations described in this Section D(2) of Part III of this Exhibit C shall be performed consistent with the Bilateral Settlement Parameters provided in Section C of Part III of this Exhibit C, which protocols may be modified, clarified or amended from time to time as determined appropriate by the Parties.

IV.

Fuel Cost Verification and Settlement

Exhibit B provides a detailed discussion concerning Utility’s responsibility for fuel management.  Prior to the date that any Contract is novated to Utility, DWR will continue to pay fuel suppliers and others involved in providing fuel management services for the delivery of fuel for those DWR Contracts where the Fuel Option has been elected.  Consistent with the above, Utility will perform settlements activities to reconcile quantities and associated charges, and DWR will perform verification, audit and monitoring to support its disbursement of funds prior to the MRTU Effective Date.  On and after the MRTU Effective Date, DWR will perform such internal procedures that are reasonable and determined appropriate by DWR, and such validation, analysis and audit of the settlement functions to be performed by Utility, as DWR’s limited agent, to support DWR disbursement of funds.  Utility will comply with the requirements contained in Exhibit F to provide DWR with the necessary information to apply appropriate procedures and controls to ensure that fuel payments and payments for fuel management services are made accurately and in a timely manner and to allow DWR to settle disputes in an appropriate manner.

C-

ANNEX 1 TO EXHIBIT C

Contracts Subject to Part III, Section D(1)
as of the Effective Date of the 2010 Operating Order

San Diego Gas & Electric Company^*:

None

^*SDG&E acting as Scheduling Coordinator for the Sunrise Contract will not be subject to the specified SC procedure provisions. Upon appointment of SDG&E as Scheduling Coordinator for the Calpeak Contracts allocated to SDG&E, SDG&E will not be subject to the specified SC procedure provisions set forth in this Exhibit C.

C-

DWR/SDG&E EXHIBIT D

ISO SCHEDULING COORDINATOR CHARGES

EXHIBIT D

ISO SCHEDULING COORDINATOR CHARGES

The financial obligation for ISO charges incurred as of January 1, 2003 has been allocated to the Utility.  Unless specifically provided in Exhibit C hereto, all ISO charges incurred after January 1, 2003 attributable to load and resources shall be the responsibility of Utility.   

Utility agrees that any refunds, reruns or credits through the ISO attributable to costs incurred by DWR for trade dates beginning February 7, 2001 up to January 1, 2003, under that certain Restated Letter Agreement, dated April 5, 2001, shall belong to DWR and Utility shall take all necessary action to remit such refunds or credits to DWR within reasonable time.  In addition, DWR shall be responsible for any ISO charges incurred during this period pursuant to the existing letter agreement between the Parties.  Utility shall invoice DWR for such ISO charges within a reasonable period of time and DWR shall pay Utility for such ISO charges within 10 days of receipt of such invoice.  Without making any assurances as to Commission action, DWR agrees to take appropriate action to ensure that such refunds or credits are applied consistent with DWR’s Revenue Requirement cost allocation method for the same trade dates.

On and after the MRTU Effective Date, all ISO charges attributable to Load (as defined under the ISO MRTU tariff) will be paid by the Utility.  Revenues associated with Inter-SC Trades related to Energy, Ancillary Services or IFM Load Uplift Obligation (as defined under the ISO MRTU tariff) from DWR Contract will be applied by Utility to offset ISO charges allocated to Load.

D-

DWR/SDG&E EXHIBIT E

CONTRACT MANAGEMENT AND
ADMINISTRATION PROTOCOLS

EXHIBIT E

CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS

Except as specifically noted below, DWR will retain all contract management, administration and monitoring responsibilities for the Contracts, including due diligence, performance testing, contract performance assessment, formal correspondence and notifications with Suppliers, exercise of contract options, contract interpretation and dispute resolution, and financial reporting.  In the event Utility and DWR agree in the future to transition the Due Diligence and Performance Test Monitoring functions set forth in this Exhibit E from DWR to the Utility, the Parties will first develop a mutually acceptable plan of performance, a transition schedule, and a transition plan for transfer of such functions from DWR to the Utility for review and approval by the Commission.  Upon agreement of the Parties to an acceptable plan and completion of the transition period, the agreed upon functions will transfer from DWR to the Utility (the “Transition Date”).  

Pursuant to Advice Letter 2048-E dated December 12, 2008 as related to SDG&E, responsibilities set forth in Paragraph II.A of this Exhibit E have been transferred from DWR to the Utility.  

I.

Due-Diligence

The Due Diligence function assesses the progress of permitting, construction and performance capability of new generating facilities under to the Contracts.  Due Diligence includes (i) monitoring activities associated with the development, construction, and performance of new generating facilities; (ii) identification and tracking of key projects milestones including permitting, equipment procurement, construction, commissioning, and performance testing; (iii) coordination with permitting agencies and the Suppliers, review of project documents, physical inspections, and witnessing of acceptance tests, (iv) verification that the new facilities can perform in a manner that is consistent with the obligations under the appropriate Contract and (v) review and approval of commercial operation dates and documentation.

II.

Performance Test Monitoring

A.

Annual Performance Tests

Annual Performance Tests verify ongoing compliance with the Contracts and establish plants capacities and efficiencies that are used to calculate contract payments, either for capacity or energy.  Annual Performance Test responsibilities generally consist of (i) verification of testing procedures, (ii) witness of performance tests, (iii) review of test results and test reports for compliance with Contract terms and conditions, and (iv) identification of contract non-compliance for dispute resolution with the Supplier.  Prior to the Transition Date, the Utility will cooperate and assist DWR with scheduling of upcoming Annual Performance Tests, and the Utility may have its staff witness such testing.  

B.

Scheduled Performance Tests

Prior to the Transition Date, on occasion, DWR may request that Utility schedule a peaking or dispatchable generating facility for testing (to assure that such generation facility is available according to the terms of the contract between such generation facility and DWR). The Utility will cooperate and shall coordinate with the DWR on a mutually acceptable date for performance of the test.  On the date agreed upon, the Utility shall schedule the specified facility or unit for operation to test the availability, reliability, and performance of the scheduled unit.  

C.

Test Procedures and Protocols

Prior to January 1, 2003, Utility shall meet with DWR staff to review, discuss, and verify test procedures and protocols developed by DWR.  

III.

Contract Performance Assessments

DWR shall continue to perform an after-the-fact review (“Performance Assessment”) of each Contract on a periodic basis.  The purpose of the Performance Assessment is to assess, analyze, and document the overall performance of each contract Supplier, assure that the Supplier is satisfying the terms and conditions of their respective Contract(s), and identify potential issues, disputes, and other matters that may require corrective action by either Utility or DWR as part of contract administration.  

IV.

Other Administrative Matters

A.

Correspondence with Suppliers

Utility and DWR agree to copy each other on all written correspondence and written notifications sent to or received from a Supplier of an Allocated Contract related to the activities described in this Exhibit E. The Parties agree to provide additional information as requested related to verification and support of the activities described in this Exhibit E.

B.

Reports

Results of the activities described in this Exhibit E will be documented by DWR in written reports (“Reports”) and shall be discussed periodically between DWR and the Utility.  Such Reports may include, but are not limited to, summary of test results, status of projects, recommendations for operational changes, procedural changes, dispute resolution, and results of Performance Assessments.  

Such Reports, documentation, or other material developed by either Party shall be shared and reviewed with the other Party on a timely basis.

E-

DWR/SDG&E EXHIBIT F

DWR DATA REQUIREMENTS FROM UTILITY

F-

EXHIBIT F

DWR DATA REQUIREMENTS FROM UTILITY

To effectively fulfill its legal and financial responsibilities, DWR requires access to standard and reliable information on a timely basis. Post transition, DWR remains statutorily and contractually obligated to collect, account for, and remit funds for the power it provides to the Utility’s retail customers.  More specifically, post transition, DWR must have readily available access to information that is currently available in-house due to DWR’s operational responsibilities.  The primary source of this information post transition will be the three utilities.

I.

Prior to the MRTU Effective Date

Prior to the MRTU Effective Date, the information being requested is required to:

·

Verify, audit, monitor and authorize payment for bilateral invoices for allocated DWR contracts;

·

Manage disputes between DWR and the bilateral counterparties;

·

Verify, audit, monitor and authorize payment for fuel procured by the utilities relating to DWR allocated contracts;

·

Verify, audit, monitor, collect and Utility remittances relating to repayment of Energy Supplied and Bond Funds;

·

Forecast, manage and monitor DWR monetary requirements and associated accounts;

·

Ongoing reporting responsibilities under AB1X, the rate agreement and bond indenture;

·

Audit and monitor long-term contract performance and associated risks prior to contract assignment or novation.

The table below contains a brief description of the information to be provided by Utility, the frequency for which Utility shall provide such information to DWR, and the effective date for when Utility shall provide such information to DWR.

F-

The following table outlines DWR data requirements relating to general contract/trade information:

Contract/Trade
Requirement	Description	Freq	Effective	Delivery Method
Surplus Energy Sales Plan	Monthly utility’s surplus energy sales plan updated weekly.  Sales plan will outline all surplus sales contemplated by the utility, including but not limited to balance of month, weekly balance of week and other short-term sales.	Monthly plan, updated weekly	1/1/2003	Email/Fax - Standard Form TBD
Surplus Energy Sales	Contract/Deal information relating to the forward sale of DWR surplus energy.  This would include but is not limited to Counterparty, Term (Start/End Date), Hourly Contract Volumes, Hourly Price, Location, any fee information, etc.	When executed	All surplus forward sales  entered into after 1/1/2003	Email/Fax - Standard Form TBD

The following table outlines DWR data requirements relating to long-term contract schedule information and associated bilateral invoices:

Schedule/Bilateral Invoice
Requirement	Description	Freq	Effective	Delivery Method
Final Schedule Volumes, Long Term Contracts	For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hourly final schedule volumes and pricing information by contract by counterparty, by day. Final schedule volumes are defined as the final volume for the hour at the completion of the real-time market.  These volumes represent the hour ahead scheduled volumes adjusted to include any real-time market adjustments by the ISO.  Absent any real time adjustments, this data will be the same as Final Hour Ahead Schedule. File should include, but is not limited to; Utility identifier, file type identifier (i.e. final, HA), SC identifier, counterparty identifier, contract identifier, schedule type identifier (i.e. sale), delivery location, date, volume scheduled by hour, price per hour.	T+1 (Daily)	1/2/2003	Secure Electronic – Format TBD
Hour Ahead  Schedule Volumes, Long Term Contracts	For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hour ahead final schedule volumes and pricing information by contract, by counterparty, by day. Format and data elements of the file provided should be identical to what was specified above in Final Schedule volumes. (Note: This cannot be the ISO Hour Ahead Final Schedule template as this file does not provide transactional level details but consolidates/collapses information based on certain ISO rules.)	T+1 (Daily)	1/2/2003	Secure Electronic – Format TBD
Reconciled Monthly bilateral invoices	Monthly invoice and supporting documentation for bilateral contracts relating to DWR long-term contracts, reviewed and approved by utility for payment by DWR to the counterparty.	Monthly – 5 business days prior to payment due date	Feb 03	TBD

In the event of a bilateral invoice dispute with the counterparty, DWR may also request from the utility the additional schedule information.  This information would be in the same format as outlined in the table above.  As mentioned above, DWR is requesting transactional level information and not the associated ISO template files due to the consolidation/collapsing of schedules with the template files.  Schedule information required would include :

·

Hour Ahead Preferred Schedule Volumes

·

Day Ahead Final Schedule Volumes

·

Day Ahead Adjusted Schedule Volumes

·

Day Ahead Revised Preferred Schedule Volumes

·

Day Ahead Preferred Schedule Volumes

F-

The following table outlines DWR data requirements relating to the verification of fuel costs.  It assumes DWR will retain legal and financial responsibility for gas and related services while the utility will perform administrative and operational responsibilities as outlined in Exhibit B.

Fuel Costs
Requirement	Description	Freq	Effective	Delivery Method
Generator fuel plan proposal	Proposal and supporting analysis on whether or not to accept or reject of generator fuel plan.	Based on individual contracts	Jan-03	TBD
Utility Fuel Procurement Plan	Utility will provide a bi-annual fuel procurement plan for utility supplied fuel.	Bi-Annual	Jan-03	TBD
Tolling agreement Settlement Report	Monthly report on each DWR tolling agreement that includes but is not limited to: tolling contract identifier, who provided the gas (generator/utility) and daily quantity of gas supplied.	Monthly	Feb-03	Electronic Format TBD
Reconciled Monthly Gas Invoice	Suppliers monthly invoice and supporting documentation for fuel procurement relating to DWR tolling agreements, reviewed and approved by Utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic – Format TBD
Gas Transportation Contract Information	Details relating to the Utility negotiated firm and/or interruptible transportation agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/2003	E-mail/Fax Standard Form TBD
Gas Storage Contract Information	Details relating to the Utility/negotiated firm and/or interruptible storage agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/03	E-mail/Fax Standard Form TBD
Reconciled Monthly gas transportation invoices	Suppliers monthly invoice and supporting documentation for natural gas transportation costs relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic – Format TBD
Reconciled  Monthly gas storage invoices	Supplier’s monthly invoice and supporting documentation for storage relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic – Format TBD

The following table outlines additional DWR data relating to utility revenue remittance:

Utility Revenue Remittance
Requirement	Description	Freq	Effective	Delivery Method
Utility ISO Preliminary Settlement Statement and Supporting Files	The complete Utility preliminary settlement statement and supporting files in original ISO template format.	T + 38 business days	Ongoing	Secure Electronic-ISO Template Direct from ISO
Utility Final ISO Settlement Statement and Supporting Files	The complete Utility final ISO settlement statement and supporting files in ISO original template format.  This information also required for remittance calculation purposes.	T + 45 business days	Ongoing	Secure Electronic-ISO Template Direct from ISO
Scheduled Retail Load by hour	Utilities estimated retail load information by hour, by day used for the preliminary remittance.	T + 1	1/1/2003	TBD
Hourly aggregate final schedule of Utility’s resource portfolio	Utilities total hourly scheduled volumes for the entire Utilities portfolio.  This is an aggregate total for the day, by hour and represents the total volume supplied by the utility.	T+1 (Daily)	1/2/2003	TBD
Hourly Distribution Loss Factor	Utility DLF % by hour	When changes required	1/1/2003	TBD
Estimated DWR remittance %	Utility estimated remittance percentage.	When changes required	1/1/2003	TBD
Energy Sales billed (kWh)*	Daily kWh billed by Utility to end users	Daily	Ongoing	Standard DWR Form/File (TBD)
DWR Power Charge volumes*	Daily DWR kWh billed by Utility to end users	Daily	Ongoing	Standard DWR Form/File (TBD)
DWR Power Charge billed to Customer*	Daily dollar amount of DWR Power Charge being billed to customer including identification of dates billed.	Daily	Ongoing	Standard DWR Form/File (TBD)
DWR Power Charge Remitted to DWR*	Daily dollar amount being remitted by Utility to DWR for the DWR Power Charge collected from customers including identification of dates billed.	Daily	Ongoing	Standard DWR Form/File (TBD)

*This information is already provided pursuant to the Servicing Arrangement, and supports the daily remittance calculation for each month and subsequent true-ups.  The Servicing Arrangement will be modified as necessary to conform to the Operating Order.

As various Commission proceedings are finalized DWR will also require specific data related to Bond Charge remittances and to Direct Access exit fees.  The specific nature and format of this data will be agreed with between the utilities and DWR.

The following table outlines DWR data requirements relating to resource information:

Resource Information
Requirement	Description	Freq	Effective	Delivery Method
Load and Resource Assessment Studies	Copies of Utilities annual and quarter load and resource assessment studies as provided to the PUC.	Annually and quarterly	Jan-03	TBD
Update Description of Resources	Updated description of resources as set out in Exhibit A.  Utilities will also provide timely updates on significant resource changes as outlined in Exhibit A.	Annually or when significant changes	Jan 1, 04	TBD
Unit Commitment Studies	As provided to the PUC.	Weekly	Jan-03	TBD
DWR Non-Dispatched Resources Report	Report of Resources that were economic to run, but were not dispatched.	Weekly	1/1/03	TBD
DWR Resource Unavailability Form	Utility notification to DWR for resources within an allocated contracts becoming unavailable, or scheduled to become unavailable. Note: This information could be provided directly from the generator to DWR and would therefore not be required from Utility.	As outlined in operating agreement	1/1/2003	Standard DWR Form – Email/Fax

II.

On and After the MRTU Effective Date

This Part II contains a brief description of the information to be provided by Utility, as well as the frequency, name of the report or source and the delivery method with respect to such information to be provided to DWR.  

The following table outlines DWR data requirements relating to long-term contract schedule information and associated bilateral invoices after MRTU go-live (4/1/2009):  

Schedule/Bilateral Invoice
Requirement	Description	Frequency	Report Name/Source	Delivery Method
Utility is the Generator Scheduling Coordinator
Day Ahead IFM Award  Volumes, Long Term Contracts	For all long-term contracts allocated to the utilities where the Utility is the SC, the detailed Day Ahead IFM Award Volumes and pricing information pursuant to a bid. Final IFM award volumes are defined as the award volume that clears the ISO IFM.   File should include, but is not limited to; Utility identifier, file type identifier (i.e. final, DA), SC identifier, counterparty identifier, contract identifier, schedule type identifier (i.e. sale), delivery location, date, volume scheduled by hour, price per hour.	M+10 Calendar Days	CMRI Report	Excel Format per Existing Protocol
ISO Expected Energy File	For Contracts allocated to SDG&E where the Utility is the SC, the ISO Expected Energy File.	Ad Hoc, upon request of DWR	CMRI Report	Excel format by email

Utility is Not the Generator SC
Requirement	Description	Frequency	Report Name/Source	Delivery Method
Requested and Final Day Ahead Inter-SC Trade Volumes	For all long-term contracts allocated to the utilities, all the IST information downloaded from SIBR. File should include, but is not limited to; Market, Date, Hour, Product Type, Selling SC, Buying SC, Trading Location, Submitted Qty., Adjusted Qty., Counter Qty., Trade Name, Trade Type, Depend on Trade, Submit SC, Trade Status, Submitted, Market Status, Physical/APN ISTs, CPTs, IST Quantities not considered for Remittance, and IST Quantities for Remittance Basis	M+10 Calendar Days	IST Report	Excel Format per existing Protocol
Requested and Final HASP Inter-SC Trade Volumes	For all long-term contracts allocated to the utilities, all the IST information downloaded from SIBR. File should include, but is not limited to; Market, Date, Hour, Product Type, Selling SC, Buying SC, Trading Location, Submitted Qty., Adjusted Qty., Counter Qty., Trade Name, Trade Type, Depend on Trade, Submit SC, Trade Status, Submitted, Market Status, Physical/APN ISTs, CPTs, IST Quantities not considered for Remittance, and IST Quantities for Remittance Basis	M+10 Calendar Days	IST Report	Excel Format per existing Protocol –
Reconciled Monthly bilateral invoices	Monthly invoice and supporting documentation for bilateral contracts relating to DWR long-term contracts, reviewed and approved by utility for payment by DWR to the counterparty.	Monthly  5 Calendar days prior to payment due date		Format per existing Protocol

The following table outlines the data to be transferred to the Utility upon receipt by DWR from certain of the Suppliers :

Requirement	Description	Frequency	Report Name/Source	Delivery Method
Data to be Provided by DWR to Utility when the Utility is Not the Generator SC Relating to Small  Dispatchable Contracts
ISO Expected Energy File	For Contracts Allocated to Utility where the Utility is not the SC and market bids are directed to be submitted by Utility	M + 10 Calendar Days	CMRI Report	Excel format by email or Secure Electronic ISO Template Directly from ISO

In the event of a bilateral invoice dispute with the counterparty, DWR may also request from the utility the additional schedule information.  This information would be in the same format as outlined in the table above.  In the cases the Utility is the generator SC, CDWR may request additional ISO data for dispute resolution.  

F-

The following table outlines DWR data requirements relating to the verification of fuel costs.  It assumes DWR will retain legal and financial responsibility for gas and related services while the utility will perform administrative and operational responsibilities as outlined in Exhibit B.

Fuel Costs
Requirement	Description	Freq	Effective	Delivery Method
Generator fuel plan proposal	Proposal and supporting analysis on whether or not to accept or reject of generator fuel plan.	Based on individual contracts	Jan-03	E-mail or overnight mail
Utility Fuel Procurement Plan	Utility will provide a bi-annual fuel procurement plan for utility supplied fuel.	Bi-Annual	Jan-03	E-mail
Tolling agreement Settlement Report	Monthly report on each DWR tolling agreement that includes but is not limited to: tolling contract identifier, who provided the gas (generator/utility) and daily quantity of gas supplied.	Monthly	Feb-03	Electronic Transmission
Reconciled Monthly Gas Invoice	Suppliers monthly invoice and supporting documentation for fuel procurement relating to DWR tolling agreements, reviewed and approved by Utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic Transmission
Gas Transportation Contract Information	Details relating to the Utility negotiated firm and/or interruptible transportation agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/2003	E-mail / Fax / Overnight Mail
Gas Storage Contract Information	Details relating to the Utility/negotiated firm and/or interruptible storage agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/03	E-mail/Fax
Reconciled Monthly gas transportation invoices	Suppliers monthly invoice and supporting documentation for natural gas transportation costs relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic Transmission or overnight mail
Reconciled  Monthly gas storage invoices	Supplier’s monthly invoice and supporting documentation for storage relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5-business days prior to payment due date	Feb-03	Electronic Transmission or overnight mail

F-

The following table outlines additional DWR data relating to utility revenue remittance:

Utility Revenue Remittance
Requirement	Description	Freq	Report Name/Source	Delivery Method
Utility Preliminary ISO Settlement Statement and Supporting Files	Related to Prior Day Adjustments (or similar adjustments) for trade hours between January 17, 2001 through December 31, 2002	Continuous	ISO	Secure Electronic - ISO Template Direct from ISO or other secure method
Utility Final ISO Settlement Statement and Supporting Files	Related to Prior Day Adjustments (or similar adjustments) for trade hours between January 17, 2001 through December 31, 2002	Continuous	ISO	Secure Electronic - ISO Template Direct from ISO or other secure method
ISO Digital Certificate for OMAR	ISO electronic certificate to access ISO OMAR system to retrieve the Utility’s load meter information.	Continuous	ISO	Secure Electronic-ISO Template Direct from ISO
ISO SIBR - IST	Access ISO SIBR data to access Utility’s transaction information for DWR Contracts.	Ad Hoc	ISO	On-site Audit by DWR
DWR Remittance Basis	Agreed upon method for determining volume of energy from DWR Contracts.  This is an aggregate total for the day, by hour and represents the total volume of energy supplied to the utility from DWR Contracts.	Monthly	DWR Remittance Basis Report and Monthly Intertie and IST Reports	Standard DWR Form/File
Estimated Bundled Customer Load	Utility estimated retail load information by hour, by day used for the DWR Percentage Calculation, including other detailed components as provided in DWR Remittance Basis Report.	Monthly	DWR Remittance Basis Report	Standard DWR Form/File
Estimated Bundled Customer Load Deviation	Utility calculated deviation of Estimated Bundled Customer Load to Actual reported load for the same period.	Monthly	EBCL Deviation Report	Standard DWR Form/File
Hourly Distribution Loss Factor	Utility DLF % by hour	When changes required	IOU	Standard IOU Form/File
DWR Percentage Factor	Utility calculated DWR Percentage Factor (or DWR Percentage Calculation) and applied to customers’ bills to determine DWR Remittances.	Monthly	DWR Percentage Calculation Report	Standard DWR Form/File
Energy Sales billed (kWh)	Monthly kWh billed by Utility to end users	Monthly	Monthly Billing Report	Standard DWR Form/File
DWR Power Charge volumes	Monthly kWh billed by Utility to end users	Monthly	Monthly Billing Report	Standard DWR Form/File
DWR Power Charge billed to Customer	Monthly dollar amount of DWR Power Charge being billed to customer including identification of dates billed.	Monthly	Monthly Billing Report	Standard DWR Form/File
DWR Power Charge Remitted to DWR	Daily dollar amount being remitted by Utility to DWR for the DWR Power Charge collected from customers including identification of dates billed.	Daily	Daily Remittance Report	Standard DWR Form/File

Some of this information is provided pursuant to the Servicing Arrangement, and supports the daily remittance calculation for each month and subsequent true-ups.  The Servicing Arrangement will be modified as necessary to conform to this Operating Agreement.

As various Commission proceedings are finalized DWR will also require specific data related to Power and Bond Charge remittances and to Direct Access Departing Load exit fees.  The specific nature and format of this data will be agreed with between the utilities and DWR.

The following table outlines DWR data requirements relating to resource information:

Resource Information
Requirement	Description	Freq	Effective	Delivery Method
Load and Resource Assessment Studies	Copies of Utilities annual and quarter load and resource assessment studies as provided to the PUC.	Annually and quarterly	Jan-03	E-mail or other transmission
Update Description of Resources	Updated description of URG resources.	Annually or when significant changes	Jan 1, 04	E-mail or other transmission
Unit Commitment Studies	As provided to the PUC.	Weekly	Jan-03	E-mail or other transmission
DWR Non-Dispatched Resources Report	Report of Resources that were economic to run, but were not dispatched.  Applicable as to PG&E and SDG&E only.	Ad hoc	1/1/03	E-mail or other transmission
DWR Resource Unavailability Form	Utility notification to DWR for resources within an allocated contracts becoming unavailable, or scheduled to become unavailable. Note: This information could be provided directly from the generator to DWR and would therefore not be required from Utility.	As outlined in operating agreement	1/1/2003	Standard DWR Form – Email/Fax

III.

Additional Provisions

Upon the reasonable request of DWR, Utility will provide to DWR any information in respect of Utility that is applicable to the rights and obligations of the Parties under the Operating Order or any material information that is reasonably necessary for DWR to monitor and manage their risks and perform their fiduciary responsibilities.  Upon the reasonable request of Utility, DWR will provide to Utility any information in respect of DWR that is applicable to the rights and obligations of the Parties under the Operating Order or any material information that is reasonably necessary for Utility to operationally administer Contracts under the Operating Order.

For the information identified above, or any additional information identified through the Term of the Operating Order, standard submission formats will be used or be developed by DWR for use by each of the investor-owned utilities, including Utility.  In the cases where the information requirements result in a large volume of data (e.g., schedule information), DWR will use or develop standard detailed file definitions for use by all of the investor-owned utilities, including Utility.  At all times, data will be submitted to DWR by Utility through a secure electronic communication medium, unless other medium is reasonably requested by DWR.

As a result of the relative short implementation timeframes at the time of implementing the requirements under the Existing Operating Arrangement, interim delivery protocols (e.g., comma delimited file via email, compact diskettes) were utilized until the final data transmission media were in place.  DWR worked jointly with Utility to ensure the required data was available by January 1, 2003.

On and after the MRTU Effective Date, interim delivery protocols and templates were utilized.  On and after the Effective Date of this 2010 Operating Order, the Utility and DWR will work to ensure that the required data described in Part II of this Exhibit F will be available to DWR.  

In the event that DWR incurs additional costs, including but not limited to penalties, interest or other such costs, due to Utility’s failure to timely provide the data set forth in this Exhibit F, any such direct cost increase invoiced or assessed to DWR shall be borne by Utility.

The provisions of this Exhibit are subject to annual review by DWR and Utility to ensure that data reporting remains relevant and useful.

F-

Footnotes

¹

Contract Allocation Order is CPUC Decision (D.) 02-09-053.

²

Net positive and negative deviations of all supply resources.

EX-10

8/23/2010

2010 SERVICING ORDER

CONCERNING

STATE OF CALIFORNIA
DEPARTMENT OF WATER RESOURCES

And

SAN DIEGO GAS & ELECTRIC COMPANY

THIS ORDER HAS BEEN ISSUED BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION (“COMMISSION”) FOR USE BETWEEN THE STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES (“DWR”) AND SAN DIEGO GAS & ELECTRIC COMPANY (“UTILITY”).

Date of Commission Approval: March 10, 2011

Effective Date:  March 10, 2011

2010 SERVICING ORDER
TABLE OF CONTENTS

Section Numbers Title Page

Section 1.

Definitions.

Section 2.

Energy Delivery, Surplus Energy Sales and Ownership.

Section 3.

Billing Services.

Section 4.

DWR Revenues; Remittance of DWR Revenues.

Section 5.

Term and Termination; Events of Default.

Section 6.

Confidentiality.

Section 7.

Payment of Fees and Charges.

Section 8.

Records; Audit Rights; Annual Certification.

Section 9.

Reserved.

Section 10.

Amendment Upon Changed Circumstances.

Section 11.

Data Retention.

Section 12.

Indemnity.

Section 13.

Limitations on Liability.

Section 14.

Miscellaneous.

Attachments, Appendices and Annexes

Service Attachment 1 - Utility Billing Services

SA1-1

Service Attachment 2 - DWR Surplus Energy Sales Revenues Remittance

SA2-1

Attachment A

-

Representatives and Contacts

A-1

Attachment B

-

Remittances of DWR Charges

B-1

Appendix A-1:

Bill Determination - Bundled Customers Bond Charge

A-1-1

Appendix A-2:

Bill Determination - Bundled Customers Power Charge

A-2-1

Appendix B-1:

Bill Determination - Direct Access Customers Bond Charge

B-1-1

Appendix B-2:

Bill Determination - Direct Access Customers Power Charge

B-2-1

Appendix C-1:

Bill Determination - Customer Generation Departing Load
Bond Charge

C-1-1

Appendix C-2:

Bill Determination - Customer Generation Departing Load
Power Charge

C-2-1

Appendix D-1:

Bill Determination - Municipal Departing Load Bond Charge

D-1-1

Appendix D-2:

Bill Determination - Municipal Departing Load Power Charge

D-2-1

Appendix E-1:

Bill Determination - Community Choice Aggregation Bond
Charge

E-1-1

Appendix E-2:

Bill Determination - Community Choice Aggregation Power
Charge

E-2-1

Attachment C

-

Sample Daily and Monthly Reports

C-1

Attachment D

-

[Reserved]

D-1

Attachment E

-

Additional Provisions

E-1

Attachment F

-

Calculation Methodology for Reduced Remittances Pursuant to 20/20 Program  F-1

Attachment G

-

SDG&E Fee Schedule

G-1

Attachment H

-

[Not Applicable]

H-1

()

2010 SERVICING ORDER

THIS 2010 SERVICING ORDER (this “Servicing Order” or the “2010 Servicing Order”) concerns the State of California Department of Water Resources (“DWR”), separate and apart from its powers and responsibilities with respect to the State Water Resources Development System, and San Diego Gas & Electric Company, a California corporation (“Utility” or “SDG&E”).  This Servicing Order amends and restates that certain 2007 Servicing Order adopted pursuant to D.07-03-025 (the “2007 Servicing Order”) to amend and restate that certain 2003 Servicing Order adopted pursuant to D.02-12-070 on December 19, 2002 (the “2003 Servicing Order”), further amending and restating that certain First Amended and Restated Servicing Agreement, between DWR and Utility, approved by the Commission on April 22, 2002 pursuant to D.02-04-048, as amended by the Amendment No. 1 thereto, approved by the Commission on July 17, 2002. DWR and Utility are sometimes collectively referred to as the “Parties” and individually referred to as a “Party.”

BACKGROUND

A.

Under the Act, DWR is authorized to sell electric power and energy to Customers.  Amounts payable by DWR under this Servicing Order are payable solely from the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code or other appropriated amounts legally available therefor.

B.

Utility is engaged in, among other things, the transmission and distribution of electrical services to certain of the Customers in its service territory, the billing and collection for electrical services and other charges, and the ownership, installation and reading of electrical meters for certain of such Customers.

C.

Under the Act, DWR is authorized to enter into contracts with the Utility to provide transmission and distribution of all power sold or made available for sale by DWR to certain of the Customers, and, upon request of DWR, the Commission has ordered Utility to provide such transmission and distribution services, including the provision of billing, collection and related services, as agent for DWR, on terms and conditions that reasonably compensate Utility for its services.

D.

On June 23, 2001, the Parties entered into a Servicing Agreement, as amended and approved by the Commission pursuant to D.01-09-013, to set forth the terms under which Utility will provide for the transmission and distribution of DWR Power as well as billing and related services.

E.

On February 21, 2002, the Commission adopted D.02-02-051, approving and adopting a Rate Agreement between the Commission and DWR.

F.

On April 22, 2002, the Commission approved the First Amended and Restated Servicing Agreement, pursuant to D.02-04-048, to comply with D.01-09-013 to implement certain provisions of the Rate Agreement.  Said First Amended and Restated Servicing Agreement was further amended by Amendment No. 1 approved by the Commission on July 17, 2002, pursuant to D.02-07-038 to provide for a separate line item on the Utility Bills for Bond Charges and to implement the 2002 20/20 Program as ordered by the Commission pursuant to Resolution E-3770.   

G.

On September 19, 2002, the Commission adopted D.02-09-053 relating to the allocation of DWR’s power contracts, ordering the Parties to modify the previously approved servicing agreement to reflect the new operational arrangements under said contract allocation decision issued by the Commission.

H.

On December 19, 2002, pursuant to D.02-12-069, the Commission adopted an Operating Order which established the respective rights and responsibilities with respect to the Utility’s administration of the Allocated Contracts and, on that same date, the Commission further adopted D.02-12-070, imposing the 2003 Servicing Order on the Utility.

I.

Through other proceedings, the Commission also determined the cost responsibility of certain Customers, other than Bundled Customers, for Bond Charge and the ongoing DWR power charge component.

J.

Section 10(a) of the 2003 Servicing Order provided that Parties are to negotiate appropriate amendments to effectuate the required changes upon certain events, including the implementation of Bond Charges and the imposition of a DWR Charge upon customers of ESPs or other third-parties.

K.

In Appendices D-1, D-2, E-1 and E-2 to Attachment B and in reporting templates contained in Attachment C of the 2007 Servicing Order, DWR has identified and included certain Customer Types who do not currently remit DWR Charges.  Unless specifically provided elsewhere in this Servicing Order, the Utility and DWR acknowledge that the collection and remittance of DWR Charges from such Customer Types will not begin until Applicable Commission Orders that require the Utility to perform such services are final and effective.

L.

DWR and Utility amended the 2003 Servicing Order to reflect the remittance methodologies and obligations applicable to DWR Revenues, consisting of DWR Charges collected from Customers and DWR Surplus Energy Sales Revenues, all as previously provided in Applicable Commission Orders and State law, and such amendments were adopted in the 2007 Servicing Order adopted pursuant to D.07-03-025.   

M.

To reflect the changes resulting from the ISO implementation of Market Redesign and Technology Upgrade, DWR desires to amend the 2007 Servicing Order and the Operating Order, consistent with the principles memorialized in that certain Memorandum of Understanding, dated as of February 4, 2009, which has been approved by the Commission on March 13, 2009.

NOW, THEREFORE, DWR agrees, and Utility is ordered to do as follows:

Section 1.

Definitions.

The following terms, when used herein (and in the attachments hereto) with initial capitalization, shall have the meaning specified in this Section 1.  Certain additional terms are defined in the attachments hereto.  The singular shall include the plural and the masculine shall include the feminine and neuter, and vice versa.  “Includes” or “including” shall mean “including without limitation.”  References to a section or attachment shall mean a section or attachment of this 2010 Servicing Order, as the case may be, unless the context requires otherwise, and reference to a given agreement or instrument shall be a reference to that agreement or instrument as modified, amended, supplemented or restated through the date as of which such reference is made (except as otherwise specifically provided herein). Unless the context otherwise requires, references to Applicable Laws or Applicable Tariffs shall be deemed references to such laws or tariffs as they may be amended, replaced or restated from time to time.  References to the time of day shall be deemed references to such time as measured by prevailing Pacific Time.

ACH - Automated Clearing House, a nationwide payment and collection system which provides for the electronic distribution and settlement of funds.

Act - Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of California, as amended from time to time.

Additional Charges - Additional Charges shall have the meaning set forth in Section 7.2 below.

Aggregate Power - DWR Power, Utility-Provided Electric Power, and, subject to Section 4.3 of the Rate Agreement, ESP Power or other third-party provided Power for customers located within that Utility’s service territory, to the extent DWR Charges are authorized to be imposed on any such Power by Applicable Commission Orders or State or federal law.

Allocated Contracts - The long-term power purchase agreements, listed on Schedule 1 of the Operating Order, allocated to Utility under the Contract Allocation Order.

Applicable Commission Orders - Such rules, regulations, decisions, resolutions, opinions or orders as the Commission may lawfully issue or promulgate from time to time, which further define the rights and obligations of the Parties under or in connection with the Servicing Order, including any advice letters in furtherance thereof that are approved by the Commission.

Applicable Law - The Act, Applicable Commission Orders and any other applicable statute, constitutional provision, rule, regulation, ordinance, order, decision or code of a Governmental Authority.

Applicable Tariffs - Utility’s tariffs, including all rules, rate schedules, contracts, and preliminary statements, governing electric energy service to Customers in Utility’s service territory, as filed with and approved by the Commission and, if applicable, the Federal Energy Regulatory Commission.

Assign(s) - Assign(s) shall have the meaning set forth in Section 14.3(c).

Billing Services - mean Utility Billing Services.

Bond Charges - Bond Charges shall have the meaning set forth in the Rate Agreement and shall include Bond Charges to be remitted by Customers, including Bundled Customers, Direct Access Customers, Customer Generation Departing Load Customers, Municipal Departing Load Customers and Community Choice Aggregation Customers who are required to remit Bond Charges under Applicable Law.

Bundled Customers - Customers who purchase Power from Utility.

Bureau - Bureau shall have the meaning set forth in Section 8.2(b).

Business Days - Regular Monday through Friday weekdays which are customary working days, excluding State government holidays and holidays established by Applicable Tariffs; provided, however, the terms “DWR Business Days” or “Utility Business Days” shall refer to Business Days that are customary working days as related to DWR or Utility, as appropriate.

Business Hours - The period on a Business Day from 9:00 a.m. until 5:00 p.m.

CERS - California Energy Resources Scheduling, a division of DWR.

Charges - DWR Charges and Utility Charges.

Claims - Claims shall have the meaning set forth in Section 12.

Commission - The California Public Utilities Commission.

Community Choice Aggregation Customers or CCA Customers - Customers whose energy requirements are served by governmental entities formed by cities and counties pursuant to Assembly Bill 117 (2002 Stats., ch. 838), all as further provided in D.04-12-046 adopted on December 16, 2004, and D.05-12-041, adopted on December 15, 2005, as such decisions may be amended or supplemented from time to time.

Confidential Information - Confidential Information shall have the meaning set forth in Section 6.1(c).

Contract Allocation Order - D.02-09-053 of the Commission, adopted on September 19, 2002, as such decision may be amended or supplemented from time to time by the Commission.

Contracts - The Allocated Contracts.

Cost Responsibility Surcharges or CRS - For purposes of this Servicing Order, “Cost Responsibility Surcharges” or “CRS” refers to DWR Charges imposed under and pursuant to Applicable Law on Customers for the recovery of costs other than as related to the contemporaneous provisions of electrical products or services, including but not limited to (i) Bond Charge authorized or required to be imposed and (ii) any cost determined to be the ongoing DWR power charge component to be paid by such Customer or any other such similar charge. The Parties agree that under Applicable Commission Orders relating to Cost Responsibility Surcharges, the Commission has dealt with several other components to be collected by Utility, including such components which are the property of the Utility, and further agree that the use of the term Cost Responsibility Surcharges or CRS in this Servicing Order is only intended to include the components of CRS that are the property of DWR.

Customer - A retail end-use customer that purchases (or is deemed to purchase) Aggregate Power, as established by Applicable Law.

Customer Generation Departing Load Customers or CGDL Customers - Customers who (a) discontinue or reduce their purchases of Utility or Direct Access services; (b) purchase or consume electricity supplied and delivered by “Customer Generation” to replace the Utility or Direct Access purchases; and (c) remain physically located at the same location or elsewhere within the Utility’s service territory, all as further provided in D.03-04-030 adopted on April 3, 2003, as such decision may be amended or supplemented from time to time.

Customer Type - Refers to Customers who may be Bundled Customers, Direct Access Customers, Customer Generation Departing Load Customers, Municipal Departing Load Customers or Community Choice Aggregation Customers.  

Daily Remittance - Daily Remittance shall have the meaning set forth in Attachment B hereto.

Daily Remittance Report - Daily Remittance Report shall have the meaning set forth in Attachment B hereto and shall be in the form set forth in Attachment C hereto.

Day-Ahead Market - The daily ISO forward market for which energy and ancillary services are scheduled for delivery on the following calendar day, as such market operated prior to the MRTU Effective Date.

Delinquent Payment - Delinquent Payment shall mean the payment of any amount due under this Servicing Order after the time when payment is required to be made hereunder, as further described and/or limited hereunder.

Direct Access Customers or DA Customers - Customers who subscribe to direct access service from Electric Service Providers, all as further provided in D.02-03-055 adopted on March 21, 2002, as such decision may be amended or supplemented from time to time.

Discloser - Discloser shall have the meaning set forth in Section 6.1(c).

DWR Charges - Bond Charges, Power Charges and any other amounts authorized to be collected from Customers pursuant to the Rate Agreement, Applicable Commission Orders and Applicable Law in order to meet DWR’s revenue requirements under the Act.

DWR Power - The electric power and energy, including but not limited to capacity and output, supplied by DWR to Bundled Customers pursuant to the Act, Applicable Commission Orders and State and federal law.

DWR Revenues - Those DWR Charges collected from Customers required to be remitted to DWR through Utility Bills or Non-Utility Bills, as the case may be, and, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues.

DWR Surplus Energy Sales Revenues or Surplus Revenues - Revenues received by Utility for the sale of surplus Power to third parties that Utility is required to remit to DWR, consistent with the Contract Allocation Order and Exhibit C of the Operating Order, prior to the MRTU Effective Date.

DWR’s Agent - DWR’s Agent shall have the meaning set forth in Section 8.2(b).

Effective Date - The date this Servicing Order is effective in accordance with Section 14.16, as such date is set forth on the cover page hereof.

Electrical Corporation - Electrical Corporation shall have the meaning ascribed thereto in Section 218 of the Public Utilities Code, including any successor and assign thereof.

Electric Service Provider or ESP - Electric Service Provider means an entity that provides electrical service to one or more retail customers located within the Service Areas of Pacific Gas and Electric Company, Southern California Edison Company, or San Diego Gas & Electric Company or any of their respective successors, except that Electric Service Provider excludes: DWR, any other public agency to the extent that it offers electrical service to customers within its jurisdiction or within the service territory of a local publicly owned electric utility, and Electrical Corporations.  Electric Service Provider includes the unregulated affiliates and subsidiaries of an Electrical Corporation.   

ESP Customers - Customers served by ESP Power.

ESP Power - Power provided by an Electric Service Provider to Customers.

Event of Default - Event of Default shall have the meaning set forth in Section 5.2.

Final Hour-Ahead Schedule - The final schedule of DWR Power submitted by DWR and Utility and published by the ISO for the Hour-Ahead Market, prior to the MRTU Effective Date.

Fund - Fund shall have the meaning set forth in Section 13.2.

Fund Type - Refers to Bond Charges or Power Charges.

Governmental Authority - Any nation or government, any state or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the Commission.

Governmental Program - Any program or directive established by Applicable Law which directly or indirectly affects the rights or obligations of the Parties under this Servicing Order and which obligates or authorizes DWR to make payments or give credits to Customers or other third parties under such programs or directives.

Hour-Ahead Market - The ISO forward market for which energy and ancillary services are scheduled for subsequent hours for delivery on the current calendar day, as such market operated prior to the MRTU Effective Date.

Indemnified Party - Indemnified Party shall have the meaning set forth in Section 12.

Indemnifying Party - Indemnifying Party shall have the meaning set forth in Section 12.

Insolvency Event - With respect to Utility, (a) the filing of a decree or order for relief by a court having jurisdiction in its premises or any substantial part of its property in an involuntary case under any applicable federal or state bankruptcy, insolvency or other similar law now or hereafter in effect, or the appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official for it or for any substantial part of its property, or the ordering of the winding-up or liquidation of its affairs, and such decree or order shall remain unstayed and in effect for a period of 60 consecutive calendar days; or (b) the commencement by it of a voluntary case under any applicable federal or state bankruptcy, insolvency or other similar law now or hereafter in effect, or the consent by it to the entry of an order for relief in an involuntary case under any such law, or the consent by it to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official for it or for any substantial part of its property, or the making by it of any general assignment for the benefit of creditors, or the taking of action by it in furtherance of any of the foregoing.

ISO - The California Independent System Operator Corporation.

Late Payment Rate - The Prime Rate plus 3%.

MRTU - ISO’s Market Redesign and Technology Upgrade.

MRTU Effective Date - The first trade date upon MRTU implementation by the ISO.

Municipal Departing Load Customers or MDL Customers - Customers who departed Utility service on and after February 1, 2001 to take service from a municipal utility, all as further provided in D.03-07-028 adopted on July 10, 2003, as such decision may be amended or supplemented from time to time.

Non-Utility - Any third-party service provider under Applicable Tariff or servicing arrangement with the Utility to perform any portion of Services contemplated under this Servicing Order, including but not limited to ESPs and other third-party energy providers.

Non-Utility Bill - A bill calculated and prepared by the Utility but either (i) presented to a Non-Utility or (ii) consolidated and presented by a Non-Utility to a Customer, in either case, under and pursuant to a servicing arrangement and/or Applicable Tariff or Applicable Law which facilitates the collection of any component of DWR Charges.

Operating Order - The Operating Order adopted on December 19, 2002, pursuant to D.02-12-069, including that certain Operating Agreement executed on April 17, 2003, by and between DWR and Utility, as the same may be amended from time to time and approved by the Commission, including such amendments to be incorporated consistent with the principles memorialized in that certain Memorandum of Understanding, dated as of February 4, 2009, as further amended, supplemented and clarified as set forth in the Operating Order submitted to the Commission concurrently with this 2010 Servicing Order.

Operating Order Effective Date - The date that the Operating Order is effective in accordance with the provisions thereof.

Power - Electric power and energy, including but not limited to capacity and output.

Power Charges - Power Charges shall have the meaning set forth in the Rate Agreement, and shall include Energy Payments as referred to in Exhibit C of the Operating Order and shall further include the ongoing DWR power charge component of the CRS imposed by the Commission upon certain customers for the above-market costs of DWR Power.

Prime Rate - The rate which Morgan Guaranty Trust Company of New York, or its successor, announces from time to time in New York, New York as its prime lending rate, the Prime Rate to change when and as such prime lending rate changes.  The Prime Rate is a reference rate and does not necessarily represent the lowest or best rate actually charged to any customer.

Rate Agreement - The Rate Agreement between DWR and the Commission adopted by the Commission on February 21, 2002 pursuant to D.02-02-051, as the same may be amended and adopted by subsequent Commission proceedings.

Recipient - Recipient shall have the meaning set forth in Section 6.1(c).

Recurring Fees - Recurring Fees shall have the meaning set forth in Section 7.1.

Remittance - A payment of DWR Charges by Utility to DWR or its Assign(s) and, prior to the MRTU Effective Date, all DWR Surplus Energy Sales Revenues, in accordance with this Servicing Order.

Scheduling Coordinator-to-Scheduling Coordinator Trade - Schedules for energy transferred from one ISO scheduling coordinator to another.  Such schedules are deemed delivered by the ISO upon publication by the ISO of the Final Hour-Ahead Schedules.

Service Area - Service Area means the geographic area in which an Electrical Corporation distributes electricity.

Services - Billing Services, metering services and meter reading services which may be performed by Utility or Non-Utility, as the case may be, and related collection, remittance and other services provided by Utility for DWR pursuant to this Servicing Order.

Servicing Order or 2010 Servicing Order - This 2010 Servicing Order including all attachments hereto.

State - The State of California.

Set-Up Fee - Set-Up Fee shall have the meaning set forth in Section 7.1.

Term - The term of this Servicing Order as set forth in Section 5.1.

20/20 Program - 20/20 Program shall have the meaning set forth in Section 4.3.

Utility Bill - A bill calculated, prepared and presented by Utility to a Customer that includes both the Customer’s Utility Charges and DWR Charges; provided, however, that to the extent appropriate under Applicable Commission Orders, all Utility Bills sent to Customers shall reflect DWR Charges on a consolidated basis.

Utility Billing Service - Billing service through the use of Utility Bills or Non-Utility Bills as described in Service Attachment 1 to this Servicing Order.

Utility Charges - Charges incurred by a Customer for electricity-related services and products provided by Utility to the Customer, as approved by the Commission and, as applicable, the Federal Energy Regulatory Commission or other Governmental Authority (including, but not limited to, any Competition Transition Charges or Fixed Transition Amount Charges owing to Utility or its affiliates, as those terms are defined under the California Public Utilities Code). Utility Charges shall not include DWR Revenues or charges for retail natural gas sales.

Utility-Provided Electric Power - Utility-Provided Electric Power shall refer to electricity from Utility’s own generation, qualifying facility contracts, other power purchase agreements and bilateral contracts.  Utility-Provided Electric Power shall not include DWR Power, ESP Power or any third-party provided power for Customers.

The terms used in the attachments, but not specifically defined herein or elsewhere in this Servicing Order, should be understood by the Parties to have their ordinary meanings.

Section 2.

Energy Delivery, Surplus Energy Sales and Ownership.

2.1.

Delivery of Power.

Pursuant to the Act and Applicable Commission Orders, Utility is ordered to transmit, or provide for the transmission of, and distribute DWR Power to Bundled Customers over Utility’s transmission and distribution system in accordance with Applicable Law, Applicable Tariffs and any agreements between the Parties.

2.2.

Data and Information Communications Procedures.

(a)

Prior to the Operating Order Effective Date, Utility estimated customer usage and Utility-retained generation for a given trade day and communicated the net of such estimate to DWR by 7:00 a.m. on the preceding Utility Business Day.  In the event that DWR observed a persistent deviation between estimated customer usage and actual customer usage, or between estimated Utility-retained generation and actual Utility-retained generation, DWR requested Utility to review, and Utility promptly commenced the review of, Utility’s forecast methodology and reported the results of such review to DWR; provided, however, that Utility had no obligation to correct or minimize such deviation except as provided in Attachment H of the 2003 Servicing Order.   

(b)

Prior to the Operating Order Effective Date, DWR agreed to send to Utility in writing each day the Scheduling Coordinator-to-Scheduling Coordinator Trade between DWR and Utility. This information was delivered no later than 9:30 a.m. for trades in the Day-Ahead Market for the following day, and no later than two hours and twenty minutes prior to the start of the delivery hour for trades in the Hour-Ahead Market.  Utility was ordered, and DWR agreed to separately provide these schedules to the ISO prior to the close of the respective markets. The above deadlines for DWR were set because the ISO Day-Ahead Market closed at 10:00 a.m. on the day before delivery and the ISO Hour-Ahead Market closed two hours before the delivery hour.  If these closing times should change, the deadlines for submission of DWR data to Utility were to have changed proportionately, which revised deadlines were to be confirmed in writing by DWR and Utility. DWR agreed that, upon Utility’s request, DWR would supply information to Utility substantiating to Utility’s reasonable satisfaction (i) the total amount of energy purchased by DWR in the Day-Ahead Market and Hour-Ahead Market; and (ii) other such information that may be required for Utility to verify the DWR Charges, or any component thereof, including information regarding the allocation of such energy among Customers and other third parties to the extent so required.   

Notwithstanding the provisions of paragraphs (a) and (b) of this Section 2.2, upon the Operating Order Effective Date, Utility is to schedule and dispatch Power as provided in the Operating Order and the Utility is directed to comply with the data and information communications procedures set forth in the Operating Order.

(c)

Consistent with Applicable Commission Orders and as provided elsewhere in this Servicing Order, on and after the Effective Date of the 2007 Servicing Order, Utility was ordered to remit each component of DWR Charges from each Customer Type, all as further provided in Attachment B hereto and each of the Appendices appended thereto.  Each component of DWR Charges was ordered to be remitted at the applicable Commission-approved rate. The basis for remittance of DWR Charges shall be amounts collected from Customers, consistent with Applicable Commission Orders.  If either Party obtains actual knowledge of a material flaw in the procedures or methods set forth in this Servicing Order, and such flaw has a material adverse effect on (i) the delivery of Services (including, without limitation, the timely and accurate remittance of DWR Charges and DWR Surplus Energy Sales Revenues to DWR), or (ii) the timely and accurate payment to Utility of compensation for Services hereunder, the discovering Party shall bring such flaw to the attention of the other Party within a reasonable time.  Upon the delivery of such notice, the Parties shall conduct good faith negotiations to resolve such flaw. Without limiting any other terms, express or implied, of this Servicing Order or any other agreement between the Parties, the Parties acknowledge that the two preceding sentences do not impose an independent obligation to perform any investigation or monitoring to discover any such flaw.

(d)

Prior to the MRTU Effective Date, Utility shall perform surplus Power sales consistent with the Contract Allocation Order and the Operating Order. Utility shall also calculate and remit DWR Surplus Energy Sales Revenues consistent with the Contract Allocation Order and the Operating Order.  The basis for remittance of DWR Surplus Energy Sales Revenues shall be amounts collected by Utility from third parties for sales of surplus Power, consistent with the principles set forth in Exhibit C of the Operating Order and in accordance with the Contract Allocation Order, all as further provided in Service Attachment 2 hereto.  

(e)

On and after the MRTU Effective Date, Utility shall remit each component of DWR Charges from each Customer Type, all as further provided in this 2010 Servicing Order, consistent with the amendments set forth in the Operating Order submitted to the Commission concurrently with this 2010 Servicing Order.  These amendments are consistent with the principles set forth in that certain Memorandum of Understanding, dated as of February 4, 2009.

(f)

All data and information to be exchanged between the Parties in connection with scheduling and settlement of transactions shall be in the format agreed to by Utility and DWR and shall, except as otherwise provided by this Servicing Order or Applicable Tariffs, or as may be approved by Utility in its reasonable discretion, be submitted electronically. If a Party receives any information that is unreadable, or contains data that cannot be processed by the receiving Party’s system, or is otherwise damaged, such receiving Party shall inform the sending Party of such problem.  Until any such problem is corrected, the receiving Party shall not be responsible for processing information received in this condition. The foregoing notwithstanding, a receiving Party shall not be excused from its obligation to process information if the receiving Party cannot read or otherwise process the information sent by the sending Party as a result of defects, errors, bugs, or viruses in the receiving Party’s systems or software or due to negligence or wrongful act(s) or failure(s) to act on the part of the receiving Party’s employees, agents, independent contractors, subcontractors or assigns.

2.3.

Ownership of DWR Power, Surplus Power, Utility-Provided Electric Power and DWR Revenues.

Notwithstanding any other provision herein, and in accordance with the Act and Section 80110 of the California Water Code, DWR shall retain title to all DWR Power sold by DWR to Bundled Customers or, prior to the MRTU Effective Date, any surplus Power sold by Utility on DWR’s behalf, in accordance with the terms of the Operating Order and consistent with the Contract Allocation Order. In accordance with the terms hereof and the Operating Order, as the case may be, Utility is acting solely as the servicing agent for DWR with respect to all components of DWR Charges collected from Customers and, prior to the MRTU Effective Date, with respect to sales of surplus Power to third-party purchasers, and nothing in this Servicing Order should be construed to suggest other than that DWR shall retain title to all DWR Charges and, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues.

In accordance with the Act and Section 80104 of the California Water Code, upon the delivery of DWR Power to Bundled Customers or, prior to the MRTU Effective Date, the sale of surplus Power to third-party power purchasers made by Utility on behalf of DWR, those Bundled Customers and third-party power purchasers, shall be deemed to have purchased that power from DWR, and payment for any such sale shall be a direct obligation of such Customers or third-party purchasers, as the case may be, to DWR.  In accordance with Applicable Law, Cost Responsibility Surcharges are recovered from Direct Access Customers, Customer Generation Departing Load Customers, Municipal Departing Load Customers or Community Choice Aggregation Customers.  Utility shall collect and remit such Cost Responsibility Surcharges, all as further provided in this Servicing Order.

All DWR Revenues and DWR Charges shall constitute property of DWR.  To the extent any monies are received by the Utility during the process of collection, and pending their transfer to DWR, including any amounts collected under Non-Utility Bills and remitted to Utility by a Non-Utility, the monies shall be held by the Utility in trust for the benefit of DWR (whether or not held together with other monies).  Notwithstanding any other provision herein, Utility shall retain title to all Utility-Provided Electric Power supplied by Utility to Customers and all surplus Power provided by Utility.

2.4.

Allocation of DWR Power and DWR Surplus Energy Sales Revenues.

DWR Power will be allocated pursuant to the Act and other Applicable Law and Applicable Tariffs.  On and after the Operating Order Effective Date, DWR Power and, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues shall be allocated consistent with the Contract Allocation Order, and as provided in the Operating Order and the Servicing Order then in effect.

On and after the MRTU Effective Date, DWR Power shall be allocated consistent with the amendments to the Operating Order, implementing the principles set forth in that certain Memorandum of Understanding, dated as of February 4, 2009.

2.5.

Treatment of ISO Charges.

Prior to the Operating Order Effective Date, the allocation of cost responsibility with respect to certain ISO charges, as between the Parties, have been governed by the Restated Letter Agreement described in Attachment E.  On and after the Operating Order Effective Date, this Section shall be superseded by the provisions relating to such ISO charges provided in the Operating Order, including Exhibit D of the Operating Order.

2.6.

DWR Surplus Energy Sales Revenues.

Prior to the MRTU Effective Date, the treatment of surplus Power shall be governed by the Contract Allocation Order and the Operating Order, and as further provided in Service Attachment 2 hereto.

Section 3.

Billing Services.

3.1.

Provision of Services by Utility.

(a)

Except to the extent that such Services are provided by a third-party, Utility shall provide metering services, meter reading services and Billing Services relating to (i) the Power Charge remittances with respect to each applicable Customer Type provided in the Appendices to Attachment B hereto, and (ii) the Bond Charge remittances with respect to each applicable Customer Type provided in the Appendices to Attachment B hereto.  If Non-Utility Bills are involved in the Utility’s performance of Billing Services, Utility shall calculate the amount of any applicable DWR Charges to be collected through Non-Utility Bills, all as further provided in this Servicing Order.  Utility-provided metering services, meter reading services and Billing Services shall be provided in accordance with Applicable Law, Applicable Commission Orders, Applicable Tariffs and Service Attachment 1 hereto, as well as Attachment B and its Appendices.

(b)

In the case where Non-Utility Bills are used by the Utility in the billing and collection of any component of DWR Charges under Applicable Law, Utility shall include such necessary and appropriate provisions in the Applicable Tariffs and any applicable servicing arrangements so that any component of DWR Charges billed and collected by such Non-Utility are remitted to Utility.  Utility is directed to accept payment from such Non-Utility in respect of each applicable component of DWR Charges billed and collected through Non-Utility Bills in such forms and methods and at such times and places as the Utility and each Non-Utility shall mutually agree in accordance with Applicable Commission Orders and Applicable Tariffs. Upon remittance of any amounts by the Non-Utility to Utility for any applicable component of DWR Charges, Utility is directed to hold such charges in trust for the benefit of DWR (whether or not held together with other monies) and promptly remit and account for such amounts to DWR consistent with Applicable Law.   

(c)

Prior to the MRTU Effective Date, Utility shall sell surplus Power on behalf of DWR, and provide invoicing and collection of amounts owed by third parties for such surplus Power sales made by Utility on DWR’s behalf and the allocation of such revenues to DWR.  Surplus Power sales made by Utility on DWR’s behalf, including the invoicing and collection of amounts owed by third parties and credit risk management, shall be conducted by Utility in accordance with Applicable Commission Orders, including but not limited to, the Contract Allocation Order, Applicable Tariffs, the Operating Order and Service Attachment 2 hereto.

(d)

On behalf of DWR, Utility shall (i) follow its customary standards, policies and procedures in performing its duties hereunder and (ii) perform its duties hereunder using the same degree of care and diligence that Utility exercises for its own account.

(e)

For surplus Power sales to third parties, prior to the MRTU Effective Date, Utility shall apply prudent credit risk management criteria to ensure that such purchasers meet or exceed DWR credit criteria, or in the absence of such DWR designated criteria, and then consistent with industry accepted credit standards.  If Utility sells surplus Power to an entity that requires collateral, the cost and obligation to post such collateral shall be Utility’s responsibility.

(f)

Prior to the MRTU Effective Date, Utility shall be responsible for all transaction fees or other costs associated with the sale of surplus Power imposed by third-party purchasers or any agents of Utility or such purchaser, all as further provided in Exhibit C of the Operating Order.

3.2.

Modification of Billing and Metering Systems.

Utility shall have the right to modify and replace its billing and metering systems, subject to the requirements of Applicable Law, if any.  However, to the extent that such modifications and replacements materially interrupt Services provided by Utility to DWR, Utility shall provide to DWR, as soon as reasonably practicable, prior written notice of any such changes, including, but not limited to, such changes as are required by Applicable Law or Applicable Commission Order(s).  Moreover, to the extent any such modifications would affect the collection of DWR Charges or, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues, in a manner which is different from the collection of Utility Charges or other Utility revenues, such as revenue from the sale of Power, Utility shall obtain DWR’s prior written consent to such modifications, which consent DWR agrees shall not be unreasonably withheld or delayed.

3.3.

Customer Inquiries.

Utility shall address all Customer inquiries regarding DWR Charges.  DWR agrees to provide all necessary information to Utility in order to permit Utility to respond to all Customer inquiries on a timely basis.  In extraordinary circumstances, Utility will refer Customer inquiries to DWR in a manner to be agreed upon by the Parties.  In the event that either (i) DWR’s failure to provide all such necessary information to Utility, (ii) DWR’s provision of inaccurate information or (iii) DWR’s failure to handle Customer inquiries referred to it by Utility in extraordinary circumstances in the manner agreed upon by the Parties results in Utility’s non-compliance with its obligations under this Section 3.3, such non-compliance will not constitute a material breach of this Servicing Order and will not give DWR the right to terminate this  Servicing Order.   

3.4.

Inquiries from Third Party Power Purchasers.

So long as Utility, as agent to DWR, sells surplus Power to third-party purchasers, Utility shall address all third-party purchasers’ inquiries regarding such surplus Power sales.  If Utility and any third-party purchaser should have a dispute with respect to the sale of surplus Power, Utility shall resolve all such disputes.  Utility shall apply the same practices to the resolution of such disputes as Utility uses to resolve disputes related to any other transaction with such third-party purchaser.

Section 4.

DWR Revenues; Remittance of DWR Revenues.

4.1.

DWR Revenues.

DWR Revenues required to be remitted to DWR under this Servicing Order shall be based upon DWR Charges in effect from time to time pursuant to Applicable Law and Attachment B to this Servicing Order and the Appendices to such Attachment B.  Prior to the MRTU Effective Date, in addition to the remittance of DWR Charges, DWR Surplus Energy Sales Revenues also shall be remitted based upon the principles set forth in Exhibit C of the Operating Order and as further provided in Service Attachment 2 hereto.

4.2.

Remittance of DWR Revenues.

(a)

Utility shall determine the Daily Remittance amount for each Fund Type and for each applicable Customer Type, consistent with the provisions of the Appendices of Attachment B hereto.  As of the Effective Date of the 2007 Servicing Order, DWR Charge components relating to the following Fund Types for the Customer Types have been identified by DWR and Utility; however, the collection and remittance of DWR Charges from the Customer Types identified below will not begin until Applicable Commission Orders that require the Utility to perform such services are final and effective:

(1)

Bundled Customers - Bond Charge. Utility is directed to remit Bond Charge for Bundled Customers to DWR, all as further provided in Attachment B and as further provided in Appendix A-1 to Attachment B of this Servicing Order.

(2)

Bundled Customers - Power Charge. Prior to the Operating Order Effective Date, Utility remitted Power Charge for Bundled Customers to DWR based on the amounts collected from Bundled Customers for actual DWR Power supplied, all as further described in Attachment B of the 2003 Servicing Order. On and after the Operating Order Effective Date, Utility is directed to remit Power Charge for Bundled Customers, consistent with the principles set forth in Exhibit C of the Operating Order and as further provided in Attachment B and in Appendix A-2 to Attachment B of this Servicing Order.

(3)

Direct Access Customers - Bond Charge. Utility is directed to remit Bond Charge for Direct Access Customers to DWR, all as further provided in Attachment B and as further provided in Appendix B-1 to Attachment B of this Servicing Order.

(4)

Direct Access Customers - Power Charge. Utility is directed to remit Power Charge for Direct Access Customers to DWR, all as further provided in Attachment B and as further provided in Appendix B-2 to Attachment B of this Servicing Order.

(5)

Customer Generation Departing Load - Bond Charge. Utility is directed to remit Bond Charge for Customer Generation Departing Load to DWR, all as further provided in Attachment B and as further provided in Appendix C-1 to Attachment B of this Servicing Order.

(6)

Customer Generation Departing Load -Power Charge. Utility is directed to remit Power Charge for Customer Generation Departing Load to DWR, all as further provided in Attachment B and as further provided in Appendix C-2 to Attachment B of this Servicing Order.  

(7)

Municipal Departing Load - Bond Charge. Upon commencement of billing and collection of Bond Charge for Municipal Departing Load, to the extent that Utility is involved, the Parties intend to revise and update Appendix D-1 to Attachment B of this Servicing Order and reflect applicable remittance methods as an event contemplated under Section 10(a)(vi) of this Servicing Order.

(8)

Municipal Departing Load - Power Charge. Upon commencement of billing and collection of Power Charge for Municipal Departing Load, to the extent that Utility is involved, the Parties intend to revise and update Appendix D­2 to Attachment B of this Servicing Order and reflect applicable remittance methods as an event contemplated under Section 10(a)(vi) of this Servicing Order.

(9)

Community Choice Aggregation - Bond Charge. Upon commencement of billing and collection of Bond Charge for Community Choice Aggregation, the Parties intend to revise and update Appendix E-1 to Attachment B of this Servicing Order and reflect applicable remittance methods, as an event contemplated under Section 10(a)(vi) of this Servicing Order.

(10)

Community Choice Aggregation - Power Charge. Upon commencement of billing and collection of Power Charge for Community Choice Aggregation, the Parties intend to revise and update Appendix E-2 to Attachment B of this Servicing Order and reflect applicable remittance methods, as an event contemplated under Section 10(a)(vi) of this Servicing Order.

If the Utility determines that it has remitted amounts to DWR in error or DWR becomes aware of a material discrepancy in the remitted amounts, then DWR or the Utility, as the case may be, may provide notice of such event to the other Party (accompanied by an explanation of the facts surrounding such erroneous deposit), and the other Party will review such notice and information as soon as practicable and reach agreement as to such amount to be repaid.  Such agreement shall not be unreasonably withheld or delayed by either Party.

(b)

Each Remittance shall be accompanied by a Daily Remittance Report, substantially in the form set forth in Attachment C hereto.  Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities hereunder with respect to DWR Charges, except to the extent provided otherwise in the Attachments hereto.

(c)

Utility, from time to time, will make adjustments regarding amounts remitted as described in Attachment B and Appendices thereto.  In addition, on and after the Effective Date, Monthly Billing Reports and Monthly Late Payment Charge Reports shall be filed with DWR by Utility, all as further provided in Attachments B and C hereto.

(d)

Except as expressly provided in this Servicing Order (including Attachments hereto) or as otherwise expressly agreed to in writing by DWR, Utility shall not deduct from amounts due to DWR hereunder any amounts owing by DWR to Utility which relate to arrangements within or outside the scope of this Servicing Order, or any other amounts, and Utility expressly waives any right to do so.  The foregoing shall not limit Utility’s rights to seek any other remedies permitted under other arrangements with DWR.

(e)

Prior to the MRTU Effective Date, Utility shall calculate and remit DWR Surplus Energy Sales Revenues determined consistent with the Contract Allocation Order and Exhibit C of the Operating Order and as further provided in Service Attachment 2 hereto.  Each monthly Remittance for surplus Power sold on behalf of DWR shall be accompanied by written reports in forms set forth in Attachment C hereto.

4.3.

20/20 Program and Future Similar Programs.

To the extent that the program established in the California Governor’s Executive Order D-30-01, dated March 13, 2001, and Executive Order D-33-01, dated April 26, 2001, as the foregoing orders may be amended, supplemented, extended or otherwise modified (the “20/20 Program”), obligated DWR to make payments or extend credits to Customers or other third parties under such program, Remittances to DWR may have been reduced by such payments to the extent of DWR’s responsibility as required by Applicable Law and Applicable Tariffs.  DWR acknowledges that Utility’s reasonable initial implementation and recurring administrative costs associated with such program has been paid by DWR in the same manner and at the same times as Utility’s Set-Up Fee and Recurring Fees, respectively, as described in Sections 7.2 and 7.3 below.  Additionally, Utility has invoiced DWR for any other costs incurred by Utility under such program, and DWR has paid such invoices as Additional Charges, in the manner contemplated in Section 7 below.  The method for calculating reduced Remittances to DWR under this Section 4.3, as well as Utility’s implementation and administration costs, shall be as set forth in Attachment F hereto.

To the extent that, in the future, programs similar to the 20/20 Program are established which expressly obligate DWR under Applicable Law and Applicable Tariffs to make payments or extend credits to Customers or other third parties under such programs, DWR and Utility will implement processes similar to those used for the 20/20 Program as set forth in the immediately preceding paragraph or such other process, as may be mutually agreed upon by the Parties.

Section 5.

Term and Termination; Events of Default.

5.1.

Term.

The term of this Servicing Order (the “Term”) shall commence on the Effective Date and shall terminate on the earlier of (a) 180 calendar days after the last date DWR Charges are imposed on Customers, or (b) the earlier termination of this Servicing Order pursuant to this Section 5.  This Servicing Order will also terminate as to each Contract, solely and individually, that is novated to Utility, without further action of either Party, but subject to Section 5.1(a) above with respect to such Contract.

5.2.

Events of Default by Utility.

The following events shall constitute “Events of Default” by Utility under this Servicing Order:

(a)

any failure by Utility to remit to DWR or its Assign(s) any required Remittance in the manner and at the time specified in this Servicing Order (except to the extent otherwise allowed under Sections 4.3 and 7.2) that continues unremedied for three (3) Utility Business Days after the earlier of the day Utility receives written notice thereof from DWR or the day the responsible manager at Utility first has actual knowledge of such failure; or

(b)

any failure by Utility to duly observe or perform in any material respect any other term or condition of Utility set forth in this Servicing Order, which failure (i) materially and adversely affects the interests or rights of DWR or its Assign(s), and (ii) continues unremedied for a period of sixty (60) calendar days after written notice of such failure has been given to Utility by DWR or its Assign(s).

5.3.

Consequences of Utility Events of Default.

Upon any Event of Default by Utility, DWR may, in addition to exercising any other remedies available under this Servicing Order or under Applicable Law, (i) apply to the Commission for appropriate relief, including but not limited to the termination of this Servicing Order in whole or in part (including Service Attachments); and (ii) apply to the Commission and, if necessary, any court of competent jurisdiction for sequestration and payment to DWR or its Assign(s) of DWR Revenues.  Remittances not made to DWR by Utility on the date due (except to the extent Remittances were not made by operation of Sections 4.3, 7.2, 14.4 or Attachment B hereto) shall bear interest at the Prime Rate from the first day after the due date until the third Utility Business Day after the due date, and at the Late Payment Rate thereafter until paid.

5.4.

Defaults by DWR.

DWR agrees that it shall be in default under this Servicing Order upon:

(a)

subject to subsections (b), (c), (d) and (e) below, DWR’s failure to cure its material breach of any provision of this Servicing Order  within sixty (60) calendar days after receiving written notice thereof from Utility;

(b)

Except for amounts to which DWR has objected in writing pursuant to Section 7.2, DWR’s failure to pay to Utility the Set-Up Fee or Recurring Fees within three (3) DWR Business Days after the date they are due hereunder, as provided in Section 7;

(c)

Except for amounts to which DWR has objected in writing pursuant to Section 7.2, DWR’s failure to pay to Utility the initial implementation and recurring administrative costs associated with Utility’s implementation of the 20/20 Program, as provided in Section 4.3;

(d)

Except for amounts to which DWR has objected in writing pursuant to Section 7.2, DWR’s failure to fulfill any other monetary obligation hereunder within fifteen (15) calendar days after receiving written notice from Utility that such obligation is past due; or

(e)

DWR’s failure to comply with the terms and conditions of Section 2.2 within fifteen (15) calendar days after receiving written notice thereof from Utility.

Upon any default by DWR under this Section 5.4, Utility may exercise any remedies available under this Servicing Order or under Applicable Law, provided that Utility shall have no right to terminate this Servicing Order either in whole or in part (including Service Attachment 1) or any obligation hereunder.  DWR agrees that, except for amounts to which DWR has objected in writing pursuant to Section 7.2 and which are determined not to be owed, any Set-Up Fee or Recurring Fees, or any initial implementation and recurring administrative costs associated with Utility’s implementation of the 20/20 Program, as provided in Section 4.3, which are not paid to Utility on the date due shall bear interest at the Prime Rate from the first day after the due date until the third DWR Business Day after the date they are required to be made hereunder, and at the Late Payment Rate thereafter until paid. DWR further agrees that, except for amounts to which DWR has objected in writing pursuant to Section 7.2 and which are determined not to be owed, any other monetary obligation payable to Utility by DWR shall bear interest at the Prime Rate from the date due until 15 days after receiving written notice from Utility that such amount is overdue, and thereafter at the Late Payment Rate.  DWR further agrees that when and to the extent that any amounts to which DWR has objected in writing pursuant to Section 7.2 are determined to be owing, such amounts shall bear interest from the due date at the rates described above for the applicable category of obligation.

5.5.

Survival of Payment Obligations.

Upon termination of this Servicing Order, DWR agrees that it, and it is ordered that Utility, shall remain liable to the other Party for all amounts owing under this Servicing Order. Utility shall continue to collect or cause to be collected and, in each case, remit, pursuant to the terms of this Servicing Order, including but not limited to Attachment B and Service Attachments hereto, any DWR Charges billed to Customers before the effective date of termination, and DWR Surplus Energy Sales Revenues attributable to surplus Power sales made prior to the MRTU Effective Date, except as provided in Attachment B hereto.  

Section 6.

Confidentiality.

6.1.

Proprietary Information.

(a)

Nothing in this Servicing Order shall affect Utility’s obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its Customers.

(b)

Nothing in this Servicing Order, and in particular nothing in Sections 6.1(e)(x) through 6.1(e)(z) of this Servicing Order, shall affect the rights of the Commission to obtain from Utility, pursuant to Applicable Law, information requested by the Commission, including Confidential Information provided by DWR to Utility. Applicable Law, and not this Servicing Order, will govern what information the Commission may disclose to third parties, subject to any confidentiality agreement between DWR and the Commission.

(c)

Each Party may acquire information and material that is the other Party’s confidential, proprietary or trade secret information. As used herein, “Confidential Information” means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party’s inspection of the other Party’s records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs, records, data, models, inventions, know-how, processes, apparati, equipment, algorithms, software programs, software source documents, object code, source code, and information related to the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties’ respective information concerning research, experimental work, development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing plans and information.  In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such third party’s business or relationship with such Party. Utility’s Confidential Information also includes any and all lists of Customers, and any and all information about Customers, both individually and aggregated, including but not limited to Customers’ names, street addresses of Customer residences and/or facilities, email addresses, identification numbers, Utility account numbers and passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among Customer residences and/or facilities, and usage of DWR Power.  DWR agrees, and it is ordered with respect to Utility, that all Confidential Information disclosed by the disclosing Party (“Discloser”) will be considered Confidential Information by the receiving Party (“Recipient”) if identified as confidential and received from Discloser.

(d)

DWR agrees, and Utility is ordered to take all steps reasonably necessary to hold in trust and confidence the other Party’s Confidential Information.  Without limiting the generality of the immediately preceding sentence, DWR agrees, and Utility is ordered (i) to hold the other Party’s Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or otherwise, other than as permitted under this Servicing Order; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality.

(e)

DWR agrees, and it is ordered with respect to Utility that the foregoing two paragraphs will not apply to any item of Confidential Information if:  (i) it has been published or is otherwise readily available to the public other than by a breach of this Servicing Order ; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the provision of Services under this Servicing Order; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; or (iv) it was known to Recipient prior to its first receipt from Discloser.  DWR agrees, and it is ordered with respect to Utility that, in addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidential Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment.  DWR agrees, and it is ordered with respect to Utility that Discloser shall pay Recipient its reasonable costs of cooperating.

6.2.

No License.

DWR agrees, and it is ordered with respect to Utility that nothing contained in this Servicing Order shall be construed as granting to a Party a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned, obtained, controlled by, or which is or may be licensable by, the other Party.

6.3.

Survival of Provisions.

DWR agrees, and it is ordered with respect to Utility that the provisions of this Section 6 shall survive the termination of this Servicing Order.

Section 7.

Payment of Fees and Charges.

7.1.

Utility Fees.

DWR agrees that it will pay to Utility a fee, calculated in accordance with Attachment G hereto (the “Set-Up Fee”), in order to cover Utility’s costs of establishing the procedures, systems, and mechanisms necessary to perform Services.  In addition, DWR  also agrees to pay to Utility an annual fee, calculated in accordance with Attachment G hereto, payable monthly in arrears (unless a different payment schedule is mutually agreed upon by the Parties) as provided in Section 7.2 hereof (the “Recurring Fees”) for Services rendered pursuant to Section 3.1, Section 3.4 and Service Attachments to this Servicing Order. Additional fees to cover changes in costs or the costs of other services provided hereunder shall be as set forth in Attachment G, which from time to time may be modified by mutual agreement of the Parties or as provided in Applicable Commission Order. In the event that additional fees or costs are identified by Utility which have not been identified and included in Attachment G hereto, the Parties hereby agree to negotiate in good faith to determine the amount of such fees or costs.  Except to the extent provided otherwise in subsequent agreements between the Parties, if the Parties are unable to resolve any disputes relating to such additional fees, either Party may, upon giving seven calendar days advance written notice to the other, submit the dispute to the Commission for proposed resolution, in accordance with Applicable Law.  However, in the event such a dispute is submitted to the Commission by either Party, and prior to the Commission’s action, DWR agrees to continue to pay to Utility fees that will permit recovery of the Utility’s incremental cost of establishing procedures, systems and mechanisms necessary to perform Services as set forth in Attachment G.  The Utility shall file these fees with the Commission. Utility acknowledges that the Commission may adjust, with notice to Utility and an opportunity for Utility to be heard, Utility’s rates to avoid double recovery of any costs paid by DWR hereunder which have already been included in Utility’s rates.

7.2.

Payment of Utility Fees and Charges.

The Set-Up Fee was due and payable on the effective date of the Servicing Agreement approved by the Commission pursuant to D.01-09-013, and DWR has paid Utility the Set-Up Fee, in the manner provided in Section 7.3 below.  After receipt of Utility’s invoice thirty (30) days in advance, DWR agrees to pay to Utility its Recurring Fees in monthly installments by the 10th day of each month in the manner provided in Section 7.3 below. Additionally, with respect to all other fees and charges which are expressly identified as owing by DWR to Utility under this Servicing Order or such other amounts as mutually agreed to by the Parties (the “Additional Charges”), unless a different payment schedule is mutually agreed upon by the Parties, Utility shall (in paper format or, at DWR’s option, electronically) submit to DWR an invoice reflecting such Additional Charges for such calendar month.  Any invoiced amount for Recurring Fees or Additional Charges shall be due and payable within three (3) DWR Business Days after presentation, and any invoiced amount and the Set-Up Fee shall be considered past due thirty (30) calendar days after presentation, after which interest shall accrue as provided in Section 7.4. To the extent that any invoiced amounts described in this Section 7.2 are not fully paid within forty-five (45) days after presentation, and DWR has not objected to Utility in writing by such date, DWR agrees that Utility shall have the right to deduct from any future Remittance(s) the unpaid and overdue amount which is not the subject of any such objection by such date, until such invoice is paid in full or until the dispute over the amount due has been resolved.  In addition, upon written agreement of DWR, any amount payable under this Servicing Order may be deducted from any future Remittance(s) or be paid in such other periodic basis, all as expressly directed by DWR.

7.3.

Method of Payment.

(a)

Except as otherwise expressly provided herein or unless a different payment schedule is mutually agreed upon by the Parties, DWR agrees, and with respect to Utility it is ordered, that any payment from either Party to the other Party under this Servicing Order shall be made by ACH or, if ACH is unavailable, then by wire transfer of immediately available funds to the bank account designated by the receiving Party or, if mutually agreed, paid by means of a check or warrant sent to the recipient’s address indicated in accordance with Section 14.14 hereof.  Where the Parties have made arrangements for a bank or other third party to remit funds from one Party to the other Party, DWR agrees, and with respect to Utility it is ordered that proper identification of the bank or third party, including the account number, shall be furnished in writing. DWR agrees, and with respect to Utility it is ordered that the remitting Party shall reasonably cooperate in correcting any bank or other third-party errors and shall not be relieved of its payment responsibilities because of such errors.

(b)

Except as expressly provided otherwise herein or under any Applicable Law, Utility shall be required to pay all expenses incurred by it in connection with its activities under this Servicing Order (including any fees to and disbursements by accountants, counsel, or any other person, any taxes, fees, surcharges or levies imposed on Utility, and any expenses incurred in connection with reports to be provided hereunder) out of the compensation paid to it pursuant to this Section 7, and Utility shall not be entitled to any extra payment or reimbursement therefor.  Notwithstanding anything to the contrary above, if and to the extent any additional taxes (excluding taxes on Utility’s income), fees or charges are imposed on Utility due solely to Utility’s performance of Services hereunder with respect to DWR Charges (such as franchise fees or taxes on DWR Power, the State of California electric energy surcharge, local utility user taxes, or Commission fees), to the extent these taxes, fees, or charges are not already included in Utility’s rates and Utility has not been reimbursed therefor and is not authorized to seek reimbursement from Customers therefor, DWR agrees to reimburse Utility therefor as “Additional Charges” in accordance with Section 7.2.

7.4.

Interest.

DWR agrees, and with respect to Utility it is ordered that except as provided in Sections 5.3, 5.4 or 7.5, any Delinquent Payment under this Servicing Order (whether or not a regularly scheduled payment) shall bear interest at the Late Payment Rate.

7.5.

Reconciliation Amounts.

If a change in Applicable Law (but only if and to the extent such change is expressly intended to be retroactive in effect) or the discovery of a “Material Flaw” results in a discrepancy between any amount paid hereunder and the amount that would have been paid if the changed Applicable Law had been in effect or the Material Flaw had been corrected, such discrepancy (a “Reconciliation Amount”) shall be paid by the party that benefited from the superseded Applicable Law or Material Flaw to the other party. Reconciliation Amounts shall be paid in full within 30 days after receipt of an invoice therefore unless a different payment schedule is mutually agreed upon between the parties. Interest on any Reconciliation Amount shall accrue from the original date on which the incorrect payment or remittance produced by the Material Flaw was due until such Reconciliation Amount is paid. Interest on any Reconciliation Amount shall be calculated on the basis of a 365- or 366- day year, as applicable, for the actual days elapsed.  For a Reconciliation Amount due from Utility to DWR, interest shall accrue at the rate of interest on Commercial Paper (Financial, three-month maturity) published in the Federal Reserve Statistical Release H.15 as described in Utility’s Preliminary Statement, II. Balancing Accounts, Section L, Energy Resource Recovery Account (ERRA), Subsection 5(q), or such other superseding account then in effect.  Should the publication of the interest rate on Commercial Paper (Financial, three-month maturity) be discontinued, interest shall accrue at the rate of the most recent monthly interest rate on commercial paper that most closely approximates the rate that was discontinued, and which is published in the Federal Reserve Statistical Release H.15, or its successor publication or such other rate as may be mutually agreed by the Parties.  For a Reconciliation Amount due from DWR to Utility, interest shall accrue at the State’s Pooled Money Investment Account Rate in effect from time to time.  If an outstanding Reconciliation Amount is not paid in full as of the date agreed upon by the Parties, any overdue amounts on and after such agreed upon date shall be considered Delinquent Payments and interest shall accrue at the Late Payment Rate from the date such overdue amount was due until paid, in accordance with Section 7.4.

For purposes of this Section, a “Material Flaw” is a procedure or method set forth in this Servicing Order, or an aspect thereof, which results in the payment or remittance of amounts to either Party (or the failure so to remit or pay) in a time, manner or amount that is inconsistent with Applicable Law. It is expressly agreed and understood that the undercollection or overcollection of amounts required to be collected under Section 80134 of the California Water Code due to incorrect projections of DWR’s revenue requirements or due to incorrect projections in the setting of DWR Charges shall not constitute a Material Flaw and are intended to be trued-up in subsequent revenue requirements.

Section 8.

Records; Audit Rights; Annual Certification.  

8.1.

Records.

Utility shall maintain accurate records and accounts relating to DWR Revenues (including separate accounting of Bond Charges and Power Charges) in sufficient detail to permit recordation of Bond Charges and Power Charges billed to or caused to be billed to each Customer Type identified in the Appendices to Attachment B hereto and DWR Revenues from Bond Charges and Power Charges, respectively, remitted by Utility to DWR reflecting separate accounting with respect to each Customer Type.  Prior to the MRTU Effective Date, Utility shall maintain accurate records and accounts relating to DWR Surplus Energy Sales Revenues (including separate accounting of surplus Power sales transactions by counterparty) in sufficient detail to permit recordation of DWR Surplus Energy Sales Revenues separate from other DWR Revenues, remitted by Utility to DWR.  Utility shall provide to DWR and its Assign(s) access to such records. Access shall be afforded without charge, upon reasonable request made pursuant to Section 8.2.  DWR agrees that access shall be afforded only during Business Hours and in such a manner so as not to interfere unreasonably with Utility’s normal operations.  Utility shall not treat DWR Revenues as income or assets of the Utility or any affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of Utility and affiliates shall be maintained in a manner consistent with the absolute ownership of DWR Revenues by DWR and Utility’s holding of DWR Revenues in trust for DWR (whether or not held together with other monies).

8.2.

Audit Rights.

(a)

Upon thirty (30) calendar days’ prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR’s expense), of Utility’s records and procedures, which shall be limited to records and procedures containing information bearing upon:  (i) DWR Charges being billed or caused to be billed to each Customer Type identified in the Appendices to Attachment B hereto by Utility (and payments of DWR Charges separately accounted for each Customer Type); (ii) fees to Utility for Services provided by Utility pursuant to this Servicing Order; (iii) Utility’s performance of its obligations under this Servicing Order; (iv) amount of Aggregate Power that is the basis for DWR Charges with respect to each Customer Type pursuant hereto or Applicable Law; (v) projection or calculation of DWR’s revenue requirements as described in Sections 80110 and 80134 of the California Water Code from time to time; (vi) prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues collected from third-party purchasers and the collection and allocation of such revenues; and (vii) such other matters as may be permitted by Applicable Commission Orders, Applicable Tariffs or as DWR or its Assign(s) may reasonably request. The audit shall be conducted during Business Hours without interference with Utility’s normal operations, and in compliance with Utility’s security procedures.

(b)

As provided in the Act, the State of California Bureau of State Audits (the “Bureau”) conducted a financial and performance audit of DWR’s implementation of Division 27 (commencing with Section 80000) of the California Water Code, such audit was to be completed prior to December 31, 2001, and the Bureau issued a final report on or before March 31, 2003. In addition, as provided in Section 8546.7 of the California Government Code, pursuant to this Section 8.2, Utility is ordered to permit DWR or the State of California Department of General Services, the Bureau, or their designated representative (“DWR’s Agent”) to review and to copy (at DWR’s expense) any non-confidential records and supporting documentation pertaining to the performance of this Servicing Order  and to conduct an on site review of any Confidential Information pursuant to Sections 8.3 and 8.8 hereof.  Utility shall maintain such records for such possible audit for three (3) years after final Remittance to DWR.  Utility shall allow such auditor(s) access to such records during Business Hours and shall allow interviews of any employees who might reasonably have information related to such records.  Further, Utility shall include a similar right for DWR or DWR’s Agent to audit records and interview staff in any contract between Utility and a subcontractor related to performance of this Servicing Order.

8.3.

Confidentiality.

Materials reviewed by either Party or its agents in the course of an audit may contain Confidential Information subject to Section 6 above.  DWR agrees, and with respect to Utility it is ordered that the use of all materials provided to DWR or Utility or their agents, as the case may be pursuant to this Section 8, shall comply with the provisions in Section 6 and shall be limited to use in conjunction with the conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law.

8.4.

DWR Requested Independent Reports.

On or after the Effective Date of this Servicing Order and at the request and expense of DWR, Utility shall cause a firm of independent certified public accountants (which may provide other services to Utility) to prepare, and Utility will deliver to DWR and its Assign(s), a report addressed to Utility (which may be included as part of Utility’s customary auditing activities), for the information and use of DWR, to the effect that such firm has performed certain procedures (the scope of which shall be agreed upon with DWR) in connection with Utility’s compliance with its obligations under this Servicing Order during the preceding year, identifying the results of such procedures and including any exceptions noted.  Utility will deliver a copy of each report prepared hereunder to the Commission (at the address specified in section 14.14) at the same time it delivers each such report to DWR.  Utility shall not be obligated to complete more than one report per year under this Section.

8.5.

Annual Certifications.

On or after the Effective Date of this Servicing Order, at least annually, and in no event later than the 30^th day after the end of the calendar year, Utility shall deliver to DWR, with a copy to the Commission, a certificate of an authorized representative certifying that to the best of such representative’s knowledge, after a review of Utility’s performance under this Servicing Order, Utility has fulfilled its obligations under this Servicing Order in all material respects and is in compliance herewith in all material respects.

8.6.

Additional Applicable Laws.

DWR agrees, and Utility is ordered to make an effort to promptly notify the other Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a material adverse effect on either Party’s ability to perform its duties under this Servicing Order.  DWR agrees, and with respect to Utility it is ordered that a Party’s failure to so notify the other Party pursuant to this Section 8.6 will not constitute a material breach of this Servicing Order, and will not give rise to any right to terminate this Servicing Order or cause either Party to incur any liability to the other Party or any third party.

8.7.

Other Information.

Upon the reasonable request of DWR or its Assign(s), Utility shall provide to the Commission and to DWR or its Assign(s) any public financial information in respect of the Utility applicable to Services provided by Utility under this Servicing Order, or any material information regarding the sale of DWR Power, surplus Power (prior to the MRTU Effective Date) or the collection of DWR Charges to the extent such information is reasonably available to Utility, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by Utility hereunder, or (ii) otherwise relates to the exercise of DWR’s rights or the discharge of DWR’s duties under this Servicing Order or any Applicable Law.  In particular, but without limiting the foregoing, Utility shall provide to DWR, with a copy to the Commission, any such information that is necessary or useful to calculate DWR’s revenue requirements (as described in Sections 80110 and 80134 of the California Water Code) or DWR Charges and, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues.

8.8.

Customer Confidentiality.

Nothing in this Section 8 shall affect the obligation of Utility to observe any Applicable Law prohibiting disclosure of information regarding Customers, and the failure of Utility to provide access to such information as a result of such obligation shall not constitute a breach of this Section 8 or this Servicing Order.

Section 9.

Reserved.

Section 10.

Amendment Upon Changed Circumstances.

(a)

The Parties are informed that compliance with any Commission decision, legislative action or other governmental action (whether issued before or after the Effective Date of this Servicing Order) affecting the operation of this  Servicing Order, including but not limited to (i) dissolution of the ISO, (ii) changes in the ISO market structure, including but not limited to the Market Redesign and Technology Upgrade or a reversion related thereto, (iii) a decision regarding the “Fixed Department of Water Resources Set-Aside” as such term is defined in Section 360.5 of the California Public Utilities Code, (iv) the establishment of other Governmental Programs, (v) the establishment or implementation of Bond Charge or related charges ordered by the Commission to additional Customer Types than currently reflected in the Appendices to Attachment B and as further contemplated in Section 2.4 of Service Attachment 1 hereto, (vi) the imposition or modification of a charge or similar DWR Charge upon customers of Electric Service Providers or upon any other third party, (vii) the modification of the Operating Order, or (viii) the modification of provisions related to the sales of surplus Power made on behalf of DWR to third parties by Utility, may require that amendment(s) be made to this Servicing Order.  If either Party reasonably determines that such a decision or action would materially affect the Services to be provided hereunder or the reasonable costs thereof, then upon the issuance of such decision or the approval of such action (unless and until it is stayed), DWR agrees, and Utility is ordered to negotiate the amendment(s) to this Servicing Order that is (or are) appropriate in order to effectuate the required changes in Services to be provided or the reimbursement thereof.

Notwithstanding Section 5.4, if the Parties are unable to reach agreement on such amendments within sixty (60) days after the issuance of such decision or approval of such action, DWR may, and Utility shall, submit the disagreement to the Commission for proposed resolution, in accordance with Applicable Law.  Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

(b)

The Parties are informed that this Servicing Order has not been reviewed by the rating agencies which are rating DWR’s bonds.  If the rating agencies request changes to this Servicing Order, DWR agrees, and Utility is ordered to negotiate to amend this Servicing Order to accommodate the rating agency requests and will cooperate in obtaining approval of the Commission for such amendments.

(c)

The Parties are informed that this Servicing Order has been modified to implement the California Governor’s Executive Order D-39-01, dated June 9, 2001, concerning load curtailment programs.  Such previously negotiated amendments to this Servicing Order are incorporated in Attachment F hereto.   

(d)

DWR agrees, and Utility is ordered to bring to the other Party’s attention any errors or discrepancies that are discovered affecting the operation or implementation of this Servicing Order, and DWR agrees, and Utility is ordered to meet and confer upon such event to negotiate any amendments to this Servicing Order that are appropriate to correct such errors or discrepancies.  If the Parties are unable to reach agreement on such amendments within sixty (60) days after the discovery of such errors or discrepancies, either party may, in the exercise of its sole discretion, submit the disagreement to the Commission for proposed resolution, in accordance with Applicable Law.  Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

Section 11.

Data Retention.

DWR agrees, and with respect to Utility is ordered that all data associated with the provision and receipt of services pursuant to this Servicing Order shall be maintained for the greater of (a) the retention time required by Applicable Law or Applicable Tariffs for maintaining such information, or (b) three years.

Section 12.

Indemnity.

It is ordered that Utility and, to the extent allowed under Applicable Law, DWR agrees that it (each, the “Indemnifying Party”) shall defend, indemnify, and hold the other Party, together with its affiliates, and each of their respective officers, agents, employees, assigns and successors in interest (collectively, the “Indemnified Party”), harmless from and against all claims, losses, demands, actions and expenses, damages and liabilities of any nature whatsoever (collectively “Claims”) with respect to the acts or omissions of the Indemnifying Party, or its officers, agents, contractors and employees, with respect to Indemnifying Party’s performance of its obligations under this  Servicing Order. DWR agrees, and with respect to Utility it is ordered that notwithstanding the above, the provisions of this Section 12 shall not apply to any Claims to the extent they involve the negligence, gross negligence, recklessness, willful misconduct or breach of this Servicing Order by either Indemnified Party.  DWR agrees, and with respect to Utility it is ordered that each Indemnified Party shall bear its own attorneys’ fees and costs under this Section 12. DWR agrees, and with respect to Utility it is ordered that the Indemnifying Party’s obligations under this Section 12 shall survive termination of this Servicing Order. This Section 12 notwithstanding, DWR has made no representation that it has the express or implied legal authority to perform any obligation under this Section 12.

Section 13.

Limitations on Liability.

13.1.

Consequential Damages.

DWR agrees, and with respect to Utility it is ordered that in no event will either Party be liable to the other Party for any indirect, special, exemplary, incidental, punitive, or consequential damages under any theory.  Nothing in this Section 13.1 shall limit either Party’s rights as provided in Section 12 above.

13.2.

Limited Obligations of DWR and Utility.

DWR agrees that it will be liable for all amounts owing to Utility for the Services hereunder, irrespective of (a) any Customer’s failure to make full and timely payments owed for DWR Charges, or (b) Utility’s rights under Sections 4.3 and 7.2 to deduct certain amounts in calculating Remittances owing by Utility to DWR under Attachment B. Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities hereunder with respect to DWR Charges, except to the extent provided otherwise in Attachment B hereto.  DWR agrees that any amounts payable by DWR under this Servicing Order shall be payable solely from monies on deposit in the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code (the “Fund”). Neither the full faith and credit nor the taxing power of the State of California are or may be pledged for any payment under this Servicing Order.  Revenues and assets of the State Water Resources Development System are not available to make payments under this Servicing Order.  If monies on deposit in the Fund are insufficient to pay all amounts payable by DWR under this Servicing Order, or if DWR has reason to believe such funds may become insufficient to pay all amounts payable by DWR under this Servicing Order, DWR agrees to diligently pursue an increase to its revenue requirements as permitted under the Act from the appropriate Governmental Authority as soon as practicable.

Section 14.

Miscellaneous.

14.1.

Independent Contractor.

Utility and its agents and employees shall perform their obligations under this Servicing Order as independent contractors and not as officers or employees of the State of California.  Notwithstanding the above, Utility shall act as the agent of DWR in billing and collecting DWR Charges or, prior to the MRTU Effective Date, DWR Surplus Energy Sales Revenues hereunder, as provided in the Act and Section 80106 of the California Water Code.

14.2.

Remedies Cumulative.

DWR agrees, and with respect to Utility, it is ordered that except as otherwise provided in this Servicing Order, all rights of termination, cancellation, or other remedies in this Servicing Order are cumulative.  DWR agrees, and with respect to Utility, it is ordered that the use of any remedy shall not preclude any other remedy available under this Servicing Order.

14.3.

Assignment.

(a)

DWR agrees, and with respect to Utility, it is ordered that except as provided in paragraphs (b), (c) and (d) below, neither Party shall assign or otherwise dispose of this Servicing Order, its right, title or interest herein or any part hereof to any entity, without the prior written consent of the other Party.  DWR agrees, and with respect to Utility, it is ordered that no assignment of this Servicing Order shall relieve the assigning Party of any of its obligations under this Servicing Order until such obligations have been assumed by the assignee.  DWR agrees, and with respect to Utility, it is ordered that when duly assigned in accordance with this Section 14.3(a) and when accepted by the assignee, this Servicing Order shall be binding upon and shall inure to the benefit of the assignee. DWR agrees, and with respect to Utility, it is ordered that any assignment in violation of this Section 14.3(a) shall be void.

(b)

Notwithstanding the provisions of this Section 14.3, Utility may delegate its duties under this Servicing Order to an agent or subcontractor, provided that Utility shall remain fully responsible for performance of any delegated duties and shall provide DWR with 30 calendar days’ prior written notice of any such delegation, and further provided that such delegation does not, in the sole discretion of DWR, materially adversely affect DWR’s or its Assigns’ interests hereunder.

(c)

DWR agrees, and with respect to Utility, it is ordered that DWR may assign or pledge its rights to receive performance (including payment of Remittances) hereunder to a trustee or another party (“Assign(s)”) in order to secure DWR’s obligations under its bonds (as that term is defined in the Act), and any such Assign shall be a third party beneficiary of this Servicing Order; provided, however, that this authority to assign or pledge rights to receive performance hereunder shall in no event extend to any person or entity that sells power or other goods or services to DWR.  Notwithstanding the immediately preceding sentence, DWR may assign or pledge its rights to receive Remittances hereunder to another party in order to secure DWR’s other obligations under the Act.

(d)

Any person (i) into which Utility may be merged or consolidated, (ii) which may result from any merger or consolidation to which Utility shall be a party or (iii) which may succeed to the properties and assets of Utility substantially as a whole, which person in any of the foregoing cases executes an agreement of assumption to perform every obligation of the Utility hereunder, shall be the successor to Utility under this  Servicing Order without further act on the part of any of the Parties to this Servicing Order; provided, however, that Utility shall have delivered to DWR and its Assign(s) an opinion of counsel reasonably acceptable to DWR stating that such consolidation, merger or succession and such agreement of assumption complies with this Section 14.3(d) and that all of Utility’s obligations hereunder have been validly assumed and are binding on any such successor or assign.

(e)

Notwithstanding anything to the contrary herein, DWR’s rights and obligations hereunder shall be transferred, without any action or consent of either Party hereto, to any entity created by the State legislature which is required under Applicable Law to assume the rights and obligations of DWR under Division 27 of the California Water Code.

14.4.

Force Majeure.

Neither Party shall be liable for any delay or failure in performance of any part of this Servicing Order (including the obligation to remit money at the times specified herein) from any cause beyond its reasonable control, including but not limited to, unusually severe weather, flood, fire, lightning, epidemic, quarantine restriction, war, sabotage, act of a public enemy, earthquake, insurrection, riot, civil disturbance, strike, restraint by court order or Government Authority, or any combination of these causes, which by the exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by the exercise of due diligence is unable to overcome.  An Insolvency Event shall not constitute force majeure.  Notwithstanding anything to the contrary above, DWR agrees, and with respect to Utility it is ordered that, each Party’s obligation to pay money hereunder shall continue to the extent such Party is able to make such payment, and any amounts owed by Utility hereunder and received by Utility shall be held in trust for DWR (whether or not held together with other monies) and remitted to DWR as soon as reasonably practicable. DWR agrees, and with respect to Utility it is ordered that, any amounts paid or remitted pursuant to this Section 14.4 shall not bear interest which would otherwise accrue under Section 7.

14.5.

Severability.

DWR agrees, and with respect to Utility, it is ordered that in the event that any one or more of the provisions of this Servicing Order shall for any reason be held to be unenforceable in any respect under Applicable Law, such unenforceability shall not affect any other provision of this Servicing Order, but this Servicing Order shall be construed as if such unenforceable provision or provisions had never been contained herein.

14.6.

Third-Party Beneficiaries.

The provisions of this Servicing Order are exclusively for the benefit of the Parties and any permitted assignee of either Party.

14.7.

Governing Law.

This Servicing Order shall be interpreted, governed and construed under the laws of the State of California as if executed and performed wholly within the State of California.

14.8.

Reserved.

14.9.

Section Headings.

Section and paragraph headings appearing in this Servicing Order are inserted for convenience only and shall not be construed as interpretations of text.

14.10.

Applicable Law.

This Servicing Order and the Parties’ obligations hereunder shall be subject in all cases to the provisions of Applicable Law, except that this Servicing Order shall have no effect on the terms of any agreement between DWR and Utility, as modified from time to time after the Effective Date hereof. Furthermore, no default under any such other agreement between the Parties shall constitute a default hereunder, and each party hereby waives any right to set off any amounts owing to it under any such other agreement against any amounts owing hereunder.

Should a conflict exist between the provisions contained in this Servicing Order (including the attachments hereto) and either Applicable Law or the 20/20 Program, the provisions of Applicable Law or the 20/20 Program, as the case may be, shall govern.  In the event of a conflict between the provisions of this Servicing Order and any Attachments hereto (including each of the Service Attachments), then the provisions of the Attachments shall govern.  Nothing in this paragraph shall relieve the Parties from complying with their obligations under Section 10 to make amendments to this Servicing Order to reflect changed circumstances, including any amendments necessary due to amendments or supplements to the Operating Order or due to necessary reconciliation with the Operating Order.

14.11.

Reserved.

14.12.

Waivers.

DWR agrees, and with respect to Utility, it is ordered that none of the provisions of this Servicing Order shall be considered waived by either Party unless the Party against whom such waiver is claimed gives such waiver in writing.  DWR agrees, and with respect to Utility, it is ordered that the failure of either Party to insist in any one or more instances upon strict performance of any of the provisions of this Servicing Order or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.  DWR agrees, and with respect to Utility, it is ordered that waiver by either Party of any default by the other Party shall not be deemed a waiver of any other default.

14.13.

Reserved.

14.14.

Notices and Demands.

(a)

DWR agrees, and with respect to Utility, it is ordered that except as otherwise provided under this Servicing Order, all notices, demands, or requests pertaining to this Servicing Order shall be in writing and shall be deemed to have been given (i) on the date delivered in person, (ii) on the date when sent by facsimile (with receipt confirmed by telephone by the intended recipient or his or her authorized representative) or electronic transmission (with receipt confirmed telephonically or electronically by the intended recipient or his or her authorized representative) or by special messenger, or (iii) seventy-two (72) hours following delivery to a United States post office when sent by certified or registered United States mail postage prepaid, and addressed as set forth below:

Utility: San Diego Gas & Electric Company
8315 Century Park Court, CP21D
San Diego, California 92123-1548

Attn:

Matt Burkhart
Vice President - Electric and Fuel Procurement
Telephone: (858) 650-6150
Facsimile:  (858) 650-6191
Email:  mattburkhart@semprautilities.com

DWR: State of California
The Resources Agency
Department of Water Resources
California Energy Resources Scheduling Division
2033 Howe Avenue, Suite 220
Sacramento, California  95825

Attn:

Mr. Russell Mills
Chief Financial Management Office
Telephone: (916) 574-2756
Facsimile:  (916) 574-0301
Email:  millsr@water.ca.gov

(b)

DWR agrees, and with respect to Utility, it is ordered that each Party shall be entitled to specify as its proper address any other address in the United States, or specify any change to the above information, upon written notice to the other Party complying with this Section 14.14.

(c)

DWR agrees, and with respect to Utility, it is ordered that each Party shall designate on Attachment A the person(s) to be contacted with respect to specific operational matters.  Each Party shall be entitled to specify any change to such person(s) upon written notice to the other Party complying with this Section 14.14.

(d)

DWR agrees, and with respect to Utility, it is ordered that copies of documents required by this Servicing Order to be delivered to the Commission shall be delivered in accordance with this Section 14.14 and shall be addressed as set forth below:

California Public Utilities Commission 505 Van Ness Avenue, 4th Floor San Francisco, California 94102

Attn:

Ms. Julie Fitch
Energy Division Director
Telephone: (415) 703-2059
Facsimile:  (415) 703-2200
Email:  jf2@cpuc.ca.gov

14.15.

Good Faith.

DWR agrees to, and Utility is ordered to, perform all its actions, obligations and duties in connection with this Servicing Order in good faith.

14.16.

Approval.

This 2010 Servicing Order, which amends and restates the 2007 Servicing Order, shall be effective when approved by the Commission. Except as expressly provided otherwise herein, neither Party may commence performance hereunder until such date.  Any delay in the commencement of performance hereunder as a consequence of waiting for such approval(s) and the expiry of any waiting period shall not be a breach or default under this 2010 Servicing Order.

All references to the “Servicing Agreement” or to the “Agreement” in the original Servicing Agreement or in the 2003 Servicing Order or the 2007 Servicing Order shall hereafter mean this 2010 Servicing Order, unless the context requires a different interpretation. The Parties intend this 2010 Servicing Order to amend and restate the original Servicing Agreement, the 2003 Servicing Order and the 2007 Servicing Order and in the event of irreconcilable conflict between the terms of the original Servicing Agreement, the 2003 Servicing Order, the 2007 Servicing Order and this 2010 Servicing Order, the terms of this 2010 Servicing Order shall control.  The 2010 Servicing Order shall be effective at such time it has been approved by the Commission, and until such time, the 2007 Servicing Order shall remain in full force and effect, except as the 2007 Servicing Order shall have been modified by that certain Memorandum of Understanding dated as of February 4, 2009, and approved by the Commission on March 13, 2009.

14.17.

Attachments.

The following attachments are incorporated in this Servicing Order:

Service Attachment 1 - Utility Billing Services

SA1-1

Service Attachment 2 - DWR Surplus Energy Sales Revenues Remittance

SA2-1

Attachment A

-

Representatives and Contacts

A-1

Attachment B

-

Remittances of DWR Charges

B-1

Appendix A-1:

Bill Determination - Bundled Customers Bond Charge

A-1-1

Appendix A-2:

Bill Determination - Bundled Customers Power Charge

A-2-1

Appendix B-1:

Bill Determination - Direct Access Customers Bond Charge

B-1-1

Appendix B-2:

Bill Determination - Direct Access Customers Power Charge

B-2-1

Appendix C-1:

Bill Determination - Customer Generation Departing Load
Bond Charge

C-1-1

Appendix C-2:

Bill Determination - Customer Generation Departing Load
Power Charge

C-2-1

Appendix D-1:

Bill Determination - Municipal Departing Load Bond Charge

D-1-1

Appendix D-2:

Bill Determination - Municipal Departing Load Power Charge

D-2-1

Appendix E-1:

Bill Determination - Community Choice Aggregation Bond
Charge

E-1-1

Appendix E-2:

Bill Determination - Community Choice Aggregation Power
Charge

E-2-1

Attachment C

-

Sample Daily and Monthly Reports

C-1

Attachment D

-

[Reserved]

D-1

Attachment E

-

Additional Provisions

E-1

Attachment F

-

Calculation Methodology for Reduced Remittances Pursuant to 20/20 Program  F-1

Attachment G

-

SDG&E Fee Schedule

G-1

Attachment H

-

[Not Applicable]

H-1

SERVICE ATTACHMENT 1

SAN DIEGO GAS & ELECTRIC COMPANY

UTILITY BILLING SERVICES

Section 1.

Establishment and Maintenance of Utility Billing Services.

To the extent appropriate under Applicable Commission Orders, under Utility Billing Services with respect to Customers, Utility will include DWR Charges with its Utility Charges on such Customers’ Utility Bills on a consolidated basis.  In addition, to the extent appropriate under Applicable Commission Orders, Utility will calculate appropriate DWR Charges under or pursuant to Applicable Law with respect to all Customers and collect DWR Charges by preparing and presenting Utility Bills or by causing to be prepared and presented Non-Utility Bills.  In the event that any portions of DWR Charges are to be collected by a Non-Utility, with bills that have been calculated and prepared by Utility, Utility will cause the appropriate DWR Charges to be included in such Non-Utility Bills for collection on behalf of DWR.

Section 2.

Utility Billing Services Procedures.

2.1.

Compliance with Metering Standards.  Except to the extent that such Services are provided by a third-party:

(a)

Utility shall comply with all metering standards pursuant to Applicable Tariffs.

(b)

Utility shall read and validate data from meters, and edit and estimate such data, under the terms of Applicable Tariffs.

(c)

Utility shall maintain, store and provide current and historical meter and usage data as required by Applicable Tariffs.

2.2.

Presentation of DWR Charges on Utility Bill.

(a)

DWR Charges shall appear on all Utility Bills or Non-Utility Bills on consolidated basis with Utility Charges in the manner and at the time required by Applicable Law and Applicable Tariffs.

(b)

Notwithstanding subsection (a) above, the Utility may change the manner of bill presentation of DWR Charges upon the agreement of DWR or at the request of DWR and upon agreement by the Utility.  Such agreement by DWR or Utility is not to be unreasonably withheld.

(c)

Notwithstanding subsections (a) and (b) above, no change shall be made to Utility Bill formats without the approval of the Commission, if the Commission’s approval is required under Applicable Law and Applicable Tariffs.   

(d)

Notwithstanding subsections (a), (b), and (c) above, the Utility Bill shall (i) at all times contain a separate line item for Bond Charge, if applicable, and (ii) (A) so long as DWR is providing Power to Bundled Customers, contain a statement to the effect that the Utility Bills include charges for power provided by DWR for which DWR is collecting “X” cents per kilowatt hour (where X = the applicable Power Charge rate) or, (B) in the case of Customers other than Bundled Customers who are subject to any cost determined to be ongoing DWR power charge component of CRS, then indicate that Utility Bills include Cost Responsibility Surcharge for which DWR is collecting “X” cents per kilowatt hour (where X = the applicable CRS component rate).  

2.3.

Billing Costs.

DWR agrees that Utility shall be reimbursed for the reasonable costs of the Billing Services it performs for DWR under this Servicing Order, except for those costs that would have been incurred in providing Billing Services for Customers in the absence of this Servicing Order.  DWR agrees that the Commission has jurisdiction to address any dispute concerning the reasonableness of the costs of Billing Services charged to DWR under this Servicing Order.

2.4.

Adjustments to DWR Charges.

Utility will resolve all disputes with Customers subject to Utility Billing Service relating to DWR Charges consistent with Applicable Tariffs and prevailing industry standards. Utility will not waive any late payment fee or modify the terms of payment of any amounts payable by Customers subject to Utility Billing Services unless such action is consistent with the action taken with respect to its own Charges and Applicable Tariffs.

In the event that DWR is entitled by Applicable Law to collect any additional charge as a component of DWR Charges, DWR agrees, and Utility is ordered to negotiate the amendment(s) to this Servicing Order that is (or are) appropriate in order to facilitate the calculation and collection of such a charge, and any such amendment shall be submitted to the Commission for approval.  For purposes of this paragraph of Section 2.4, “charge” means any amount that DWR is entitled, under Applicable Law, to assess and collect from a Customer and is intended to be included in the term DWR Charges.

2.5.

Format of Utility Bills.

Utility shall conform to such requirements in respect of the format, structure and text of Utility Bills as Applicable Law and Applicable Tariffs shall from time to time prescribe. Utility shall, subject to the requirements of Sections 1 and 2 of this Service Attachment 1, determine the format and text of Utility Bills in accordance with its reasonable business judgment, and its policies and practices with respect to its own charges.

2.6.

Customer Notices.

(a)

If DWR Charges are revised at any time, Utility shall, to the extent and in the manner and timeframe required by Applicable Law, provide Customers subject to Utility Billing Services with notice announcing such revised DWR Charges. Such notice shall, as appropriate, include publication, inserts to or in the text of the bills or on the reverse side of bills delivered to such Customers, and/or such other means as Utility may from time to time use to communicate with its Customers subject to Utility Billing Services. The format of any such notice shall be determined by the mutual agreement of the Parties, subject to approval by the Commission’s public advisor.

(b)

In addition, at least once each year, to the extent permitted by Applicable Law, Utility shall cause to be prepared and delivered to Customers subject to Utility Billing Services a notice stating, in effect, that DWR Power and DWR Charges, including such CRS components of DWR Charges, are owned by DWR and not the Utility, in the case where Utility Bills are presented.  Such notice shall be included, in a manner and format to be agreed upon by the Parties, subject to approval by the Commission’s public advisor, either as an insert to or in the text of the bills or on the reverse side of bills delivered to such Customers subject to Utility Billing Services or shall be delivered to such Customers by electronic means or such other means as Utility may from time to time use to communicate with such Customers.

(c)

To the extent that any DWR Charges are collected through Non-Utility Bills, Utility shall notify the Non-Utility as to any notices and provide inserts or the text of such notices to be sent to Customers.  At least once each year, such notice to be sent by a Non-Utility shall consist of the notice described in Section 2.6(b) above, stating, in effect, that DWR Power and DWR Charges, including such CRS components of DWR Charges, are owned by DWR and not the Non-Utility performing the billing and collection services.

2.7.

Delivery.

Utility shall deliver or cause to be delivered all Utility Bills (i) by United States Mail in such class or classes as are consistent with policies and practices followed by Utility with respect to its own charges or (ii) by any other means, whether electronic or otherwise, that Utility may from time to time use to present its own charges to Customers.  In the case of Utility Billing Service, Utility shall pay from its own funds all costs of issuance and delivery of Utility Bills, including but not limited to printing and postage costs as the same may increase or decrease from time to time, except to the extent that the presentation of DWR Charges and any associated bill messages or notices (including, without limitation, bill inserts and published notices) materially increase the costs in which case such increase in costs shall be borne solely by DWR.  To the extent practicable, Utility agrees to give DWR seven calendar days prior written notice of any such additional costs.  Any such increased costs shall be invoiced to DWR as Additional Charges and shall be subject to the provisions of Section 7 of the Servicing Order.

Section 3.

Customer Payments.

Utility shall permit Customers receiving Utility Bills to pay DWR Charges through any of the payment options then offered by Utility to such Customers for payment of Utility Charges appearing on the Utility Bill.  Utility shall not permit Customers to direct how partial payments of balances due on Utility Bills will be applied.  Utility will credit all payments received from a Customer as set forth in Attachment B hereto and Appendices thereto.

Section 4.

Collection and Nonpayment.

4.1.

Collection of DWR Charges.

Utility will collect or cause to be collected DWR Charges in accordance with its standard practices, and will notify Customers subject to Utility Bills of amounts overdue for DWR Charges in accordance with such practices.  Such collection practices shall conform to all requirements of Applicable Law and Applicable Tariffs.  Utility will post all payments for DWR Charges as promptly as practicable, including all payments received from any Non-Utility which are components of DWR Charges, but in no case less promptly than Utility posts payments for Utility Charges.

4.2.

Termination of Customer’s Electrical Service.

Utility shall adhere to and carry out disconnection policies in accordance with Applicable Law.

Section 5.

Taxes and Fees Service.

Subject to Section 7.3, Utility will calculate and collect through Utility Bills or Non-Utility Bills and remit to the various authorities the taxes and fees assessed to Customers on DWR Charges.

Section 6.

Late Payments.

In the event that Utility receives late payment interest charges from a Customer subject to Utility Billing Service, such payment shall be allocated to DWR based upon the same proportion that DWR Charges bear to the total Utility Charges on the Utility Bill.  Other than the third-party fees or costs set forth in Section C3 of Attachment B hereto, Utility shall not allocate to DWR any other additional late payment service charges or collection fees (including but not limited to disconnection or reconnection services or similar charges related to Customer defaults).   

SA 1-

SERVICE ATTACHMENT 2

SAN DIEGO GAS & ELECTRIC COMPANY

DWR SURPLUS ENERGY SALES REVENUES REMITTANCE

Consistent with the principles set forth in Exhibits C and D of the Operating Order (as such Exhibits may be amended or supplemented on or after the Effective Date of the 2007 Servicing Order), prior to the MRTU Effective Date Utility shall determine and remit DWR Surplus Energy Sales Revenues, consisting of a Preliminary Monthly Surplus Energy Sales Remittance Amount and a Delivery Month Surplus Energy Sales True-up Amount with respect to each Delivery Month, all as further provided in this Service Attachment 2.  Each “Delivery Month” consists of all days prior to the MRTU Effective Date within a calendar month of the Term, including the calendar month of the date immediately preceding the MRTU Effective Date.  Any capitalized term used but not defined in this Service Attachment 2 shall have the meanings provided in Exhibit C of the Operating Order or this Servicing Order.

1.

Definitions.

“Preliminary Hourly DWR Surplus Energy Sales Amount” is the product of (i) the Preliminary Hourly DWR Surplus Energy Percentage multiplied by (ii) the hourly Surplus Energy Sales Revenues resulting from Forward Market Sales determined in accordance with the principles in Exhibit C of the Operating Order.  The Preliminary Hourly DWR Surplus Energy Percentage is the DWR Surplus Energy Percentage determined in accordance with the principles in Exhibit C of the Operating Order using the most up-to-date scheduled DWR Supply and Utility Supply information available to Utility and a reasonable estimate of ISO Uninstructed Energy.

“Final Hourly DWR Surplus Energy Sales Amount” is DWR’s share of the hourly Surplus Energy Sales Revenues resulting from the Forward Market Sales and the ISO Real-Time Market Sales determined in accordance with the principles in Exhibits C and D of the Operating Order.

2.

Preliminary Monthly Surplus Energy Sales Remittance Amount. By the 23^rd day of the month, or if such date is not a Utility Business Day then the immediately succeeding Utility Business Day, during the Term (each, a “Monthly Settlement Date”), Utility shall calculate and notify DWR in writing as to the “Preliminary Monthly Surplus Energy Sales Remittance Amount,” which is the aggregation of all Preliminary Hourly DWR Surplus Energy Sales Amounts within the subject Delivery Month.  By the Monthly Settlement Date, the calculation of the Preliminary Monthly Surplus Energy Sales Remittance Amount shall be presented to DWR in the Preliminary Surplus Energy Sales Calculation Summary Report substantially in the form set forth in Section 2B of Attachment C to this Servicing Order.

By the second Utility Business Day following each Monthly Settlement Date, Utility shall remit to DWR the Preliminary Monthly Surplus Energy Sales Remittance Amount to the extent that Utility received such revenues as of the Monthly Settlement Date.  The remittance of the Preliminary Monthly Surplus Energy Sales Remittance Amount shall be accompanied by an entry in the Surplus Energy Sales Payment Report, substantially in the form set forth in Section 2A of Attachment C to this Servicing Order.   

3.

Final Monthly Surplus Energy Sales Remittance Amount. By the Monthly Settlement Date, Utility shall also calculate the “Final Monthly Surplus Energy Sales Remittance Amount,” which is the aggregation of all Final Hourly DWR Surplus Energy Sales Amounts with respect to a Delivery Month that is the same calendar month as the ISO trade month for which the ISO Final Market Invoice is due before the Monthly Settlement Date, as well as any Additional Adjustments contemplated in Section 6 of this Service Attachment 2.  The ISO Final Market Invoice due dates are specified in the ISO annual payment calendar.  By the Monthly Settlement Date, Utility shall (a) present the calculation of the Final Monthly Surplus Energy Sales Remittance Amount to DWR in the Final Surplus Energy Sales Calculation Summary Report substantially in the form set forth in Section 2C of Attachment C to this Servicing Order and (b) submit to DWR the Real Time Surplus Energy Sales Calculation Supporting Workbook substantially in the form set forth in Section 2D of Attachment C to this Servicing Order.  Utility will also provide to DWR the Real Time Surplus Energy Sales Calculation Resource Location ID Master List in accordance to the timeline and substantially in the form set forth in Section 2E of Attachment C to this Servicing Order.

4.

Delivery Month Surplus Energy Sales True-up Amount. By each Monthly Settlement Date, Utility will subtract the Preliminary Monthly Surplus Energy Sales Remittance Amount previously remitted to DWR for the subject Delivery Month from the Final Monthly Surplus Energy Sales Remittance Amount as set forth in Section 3 of this Service Attachment 2 to determine the “Delivery Month Surplus Energy Sales True-up Amount” and present such calculation as appropriate entries in the Final Surplus Energy Sales Calculation Summary Report as specified in Section 2C of Attachment C to this Servicing Order.  By the second Utility Business Day following the Monthly Settlement Date of each month, Utility shall remit such Delivery Month Surplus Energy Sales True-up Amount to DWR if the amount is positive, to the extent that Utility received such revenues as of the Monthly Settlement Date.  If the Delivery Month Surplus Energy Sales True-up Amount is negative, this negative True-up Amount may be used to offset the prospective Preliminary Monthly Surplus Energy Sales Remittance Amount and, if the negative True-up Amount exceeds the prospective Preliminary Monthly Surplus Energy Sales Remittance Amount, the Utility and DWR shall confer concerning the offset of the excess amount.  Any remittances or request for DWR payment to be prepared under this Section 4 shall be accompanied by an appropriate entry in the Surplus Energy Sales Payment Report as specified in Section 2A of Attachment C to this Servicing Order.   

5.

Adjustments and True-ups. If for any period of three consecutive months, the absolute value of the difference between the three-month aggregate Preliminary Monthly Surplus Energy Sales Remittance Amount and the three-month aggregate Final Monthly Surplus Energy Sales Remittance Amount resulting from Forward Market Sales is greater than 10% for such period, the Parties shall negotiate changes to the methodology provided in this Service Attachment 2 so as to reasonably reduce the Forward Market Sales portion of the Delivery Month Surplus Energy Sales True-up Amount for future months.  Either Party may, in addition to any other remedies available to the Party, submit the matter to the Commission or other appropriate forum for resolution in the event that the Parties cannot mutually agree to a revised methodology.

6.

Additional Adjustments.  The Final Monthly Surplus Energy Sales Remittance Amount of a month may also reflect any Additional Adjustments to the Surplus Energy Sales Revenue of a month for which a prior Delivery Month Surplus Energy Sales True-up Amount has been remitted.  Additional Adjustments shall consist of any Delivery Month Surplus Energy Sales True-up Amount that Utility received after a prior Delivery Month Surplus Energy Sales True-up Amount remittance and those adjustments mutually agreed to by the Parties, adjustments as a result of settled disputes between the Utility and the third-party purchaser of surplus Power or adjustments expressly permitted under the Contract Allocation Order or by Applicable Law or the Operating Order, as may be amended from time to time.   

Each Additional Adjustment shall be accompanied by a detailed written report in a form to be mutually acceptable to the receiving Party.  As reasonably requested by DWR, Utility shall provide supporting documentation of any Additional Adjustments.

7.

DWR Right to Verify Monthly Surplus Energy Sales Remittance Amount.  DWR agrees that it shall have the right but not the obligation following the receipt of the Final Surplus Energy Sales Calculation Summary Report for each Delivery Month to conduct such verification procedures as determined reasonably necessary. In the event that DWR does not agree with the Final Monthly Surplus Energy Sales Remittance Amount following its verification, and to the extent that informal procedures do not resolve the differences identified by DWR, DWR agrees that it will notify Utility in writing of a dispute with respect to such remitted amount.  If the Parties are unable to resolve any disputes relating to such DWR Surplus Sales Energy Revenues, either Party may, upon giving five Business Days’ notice to the other Party pursue such appropriate remedies including the submission of the dispute to the Commission or other appropriate forum for proposed resolution.

SA 2-

ATTACHMENT A

SAN DIEGO GAS & ELECTRIC COMPANY

REPRESENTATIVES AND CONTACTS

A.

Parties Representatives:

Utility Representative:

San Diego Gas & Electric Company

Electric and Fuel Procurement

8315 Century Park Court

San Diego, California 92123

Attn: Michael Strong

Manager, Settlements & Systems

Telephone:

(858) 654-6154

Facsimile:

(858) 654-6190

Email: mgstrong@semprautilities.com

DWR Representative:

State of California

The Resources Agency

Department of Water Resources

California Energy Resources Scheduling Division

2033 Howe Avenue, Suite 220

Sacramento, California 95825

Attn:

Russell Mills

Chief Financial Management Office

Telephone:

(916) 574-2756

Facsimile:

(916) 574-0301

Cellular:  

(916) 539-8198

Email:  millsr@water.ca.gov

B.

Utility Contact Persons:

The Utility shall make the following contact person(s) available with respect to the operational matters described below:

1.

Billing Services:

San Diego Gas & Electric Company

Financial Reporting & Remittance:

Financial Accounting

101 Ash Street, PZ05B

San Diego, California 92101

Attn: Alan Burye

Principal Accountant

Telephone:

(619) 696-2221

Facsimile:

(619) 696-4182

Email: aburye@semprautilities.com

For Utility Fees & Charges:

San Diego Gas & Electric Company

Customer Operations - South

8306 Century Park Court CP42I

San Diego, California 92123

Attn: Brad Baugh

Billing Manager

Telephone:

(858) 654-8330

Facsimile:

(858) 654-8393

Email: bbaugh@semprautilities.com

2.

Scheduling, Delivery and Transmission:

San Diego Gas & Electric Company

Electric and Fuel Procurement

8315 Century Park Court, CP21D

San Diego, California 92123

Attn:

Vince Bartolomucci

Manager - Energy Supply & Dispatch

Telephone:

(858) 650-6164

Facsimile:

(858) 650-6190

Email: vbartolomucci@semprautilities.com

3.

Surplus Energy Power Sales Remittances:

San Diego Gas & Electric Company

Electric and Fuel Procurement

8315 Century Park Court, CP21D

San Diego, California 92123

Attn:

Sue Garcia

Settlements & Administration Manager

Telephone:

(858) 650-6189

Facsimile:

(858) 650-6190

Email: sgarcia@semprautilities.com

4.

Utility Filings Impacting DWR Charges:

San Diego Gas & Electric Company

Rates, Revenues & Tariffs

8330 Century Park Court, CP32C

San Diego, California 92123

Attn:

Megan Caulson

Regulatory Tariff Manager

Telephone:

(858) 654-1748

Facsimile:

(858) 654-1788

Email: mcaulson@semprautilities.com

C.

DWR Contact Persons:

DWR will make the following contact persons available with respect to each of the operational matters described in Section B above:

State of California

The Resources Agency

Department of Water Resources

California Energy Resources Scheduling Division

2033 Howe Avenue, Suite 220

Sacramento, California  95825

Attn:

Russell Mills

Chief Financial Management Office

Telephone:

(916) 574-2756

Facsimile:

(916) 574-0301

Cellular:

(916) 539-8198

Email:

millsr@water.ca.gov

With a copy to:

Michael Wofford,

Chief IOU Remittance Section

Telephone:

(916) 574-0317

Facsimile:

(916) 574-2214

Email:

mwofford@water.ca.gov

A-

8/23/2010

ATTACHMENT B

SAN DIEGO GAS & ELECTRIC COMPANY

REMITTANCES OF DWR CHARGES

Consistent with the remittance methodology set forth in this Attachment B, SDG&E shall remit DWR Charges, consisting of all applicable Fund Types with respect to each applicable Customer Type, on each Utility Business Day of the Term.  

A.

Billing and Remittance of DWR Charges

In providing Utility Billing Services set forth in Service Attachment 1, the amount included in Utility Bills for the applicable Fund Type of the Customer Type of the DWR Charge shall be calculated by SDG&E as provided in the corresponding Appendix to this Attachment B.  By the 7th Utility Business Day after the end of a billing month during the Term, SDG&E will provide to DWR a Monthly Billing Report substantially in the form set forth in Section 1C of Attachment C.

Customer payments for DWR Charges will be collected by SDG&E on behalf of DWR, all as further provided in this Servicing Order.  SDG&E shall remit payments for DWR Charges on a daily basis following the process described in Section B of this Attachment B.

Customer payments for Utility Bills shall be allocated and applied using SDG&E’s payment posting priority process described below in Section G of this Attachment B.  All partial payments to SDG&E for Utility Bills will be prorated based on the said payment posting priority.  During SDG&E’s nightly processing during any Utility Business Day, payments for DWR Charges that SDG&E collects on behalf of DWR will be identified and aggregated separately for each Fund Type on all applicable Customer Types, and be credited to DWR’s account and be transmitted on the next Utility Business Day, separately for each Fund Type on all Customer Types by electronic funds transfer.  The Parties’ first preference for electronic funds transfer will be by ACH and their secondary preference will be by wire transfer.  SDG&E process timing will dictate which electronic funds transfer will be used.  

With respect to each Daily Remittance of DWR Charges, SDG&E shall clearly identify the appropriate Fund Type.  In determining the Daily Remittance amount of a Fund Type from an applicable Customer Type, SDG&E may net the amount due to DWR against the amount owed to SDG&E only if the adjustment amount belongs to the same Fund Type from the same Customer Type and SDG&E has obtained prior consent from DWR, which consent shall be given on a case by case basis.

B.

Proposed Process and Timeline for DWR Automated Daily Remittance

1.

Utility Business Day 0 – SDG&E receives Customer payment and payments are processed.  SDG&E’s billing system identifies payments and applies DWR portion based on pre-established payment posting criteria, representing a constructive account for DWR.  The Parties acknowledge that payments received from Customers consist of payments to SDG&E and payments to DWR and that until DWR’s portion is remitted to DWR, such funds will be held together by SDG&E.  Until remitted to DWR, SDG&E shall hold DWR’s portion of payments in trust for the benefit of DWR (whether or not held together with other monies), consistent with Applicable Law.

2.

Utility Business Day 1 - Payments are sent to DWR by 12:00 noon based on remittance schedule.  DWR acknowledges delays of up to 3 Utility Business Days may occur due to errors, system failures and other factors.  DWR agrees that such delays shall not constitute a default pursuant to Section 5.2 of the Servicing Order; provided, however, that SDG&E shall undertake commercially reasonable efforts to rectify any cause for such delay.  SDG&E shall promptly notify DWR when any such delay occurs and the expected date for returning to the normal schedule.  In cases where ACH electronic payment is remitted, SDG&E will remit to its bank on Utility Business Day 1.  DWR agrees that this payment meets SDG&E’s remittance schedule requirements pursuant to this Attachment B.

3.

Adjustments for misapplied payments, returned checks, payment transfers, and miscellaneous adjustments will be reflected in the Remittance with respect to each Fund Type of applicable Customer Type, as those adjustments are made in SDG&E’s billing system.

4.

Daily Remittances shall be accompanied by a single Daily Remittance Report separately identifying the remitted amounts of DWR Charges of each Fund Type of each Customer Type, substantially in the form set forth in Section 1A of Attachment C.  Each Daily Remittance Report shall be accompanied by the Remittance Netting Report, substantially in the form set forth in Section 1B of Attachment C.

C.

Collection of DWR Charges

1.

As permitted by Applicable Law, SDG&E will disconnect Customers’ electric service for unpaid DWR Charges.  Disconnection for DWR Charges will be performed in the same manner as SDG&E disconnects for its own charges and consistent with Applicable Tariffs.

2.

Responsibility for collection of any DWR Charges that remain unpaid 180 calendar days after the final statement was issued shall become the sole responsibility of DWR.  However, Customer payments received by SDG&E after such reversion to DWR will continue to be applied on a pro-rata basis to DWR.

3.

SDG&E may use collection agency services to recover outstanding balances on Customers’ closed accounts.  When DWR receives benefit of such services through recovery of payments to Customer accounts, Parties agree that DWR’s Remittances will be adjusted to account for the pro-rata share of collection agency fees associated with DWR’s portion of recovered charges.

By the 7th Utility Business Day after the end of a billing month during the Term, SDG&E will provide to DWR a Monthly DWR Charge-Off and Recovery Report, substantially in the form set forth in Section 1E of Attachment C.

D.

Survival of Payment Obligations

SDG&E has the right but not the obligation to pursue collection of DWR Charges after 180 calendar days following the termination of this Servicing Order pursuant to Section 5.  Provided, however, SDG&E may continue collection services for a period of 3 years after the Customer’s account was closed if prior to the termination of this Servicing Order the Parties reach a mutually satisfactory arrangement either to (i) reimburse SDG&E for its estimated reasonable costs to continue with collection and allocation activities for such period or (ii) estimate the amount of collections that are reasonably likely to be recovered, which amount (including discounts for cash flow impacts) SDG&E shall promptly remit to DWR in full satisfaction of its collection services.

E.

Deposits Securing DWR Charges

In accordance with Applicable Tariffs, SDG&E shall collect security deposits from Customers and return those security deposits to Customers.  Such security deposits will be applied pro rata to DWR Charges in the event a Customer’s billing account with SDG&E is closed.

F.

Other Operating Revenue Collected by SDG&E

DWR shall have no rights in or entitlements to charges associated with SDG&E’s collection or payment activities, including but not limited to, returned check charge, reconnection of service charge, field assignment charge, and other service charges related to billing, payment, or collections.  However, pursuant to Section 6 of Service Attachment 1, late payment interest charges will be applied pro-rata to DWR Charges.  By the 7^th Utility Business Day of each billing month during the Term, SDG&E will provide to DWR a Monthly Late Payment Charge Report presenting the calculation of pro-rata sharing of late payments for the preceding month substantially in the form set forth in Section 1D of Attachment C.  

G.

Payment Posting Priority for Utility Billing

l.

Priority

Payment posting rules for Utility Bills will assign equal priority to SDG&E gas and electric energy and service charges and DWR Charges to the extent that such charges are presented on a Utility Bill.  To the extent a Customer’s security deposit request has been included on the customer’s monthly billing statement, the Customer’s payment will be first applied to the outstanding deposit amount.  Thereafter, payments will be prorated among disconnectible SDG&E gas and electric energy and service charges and DWR Charges based on the amount owing in each statement, beginning with the oldest statement.  SDG&E’s payment posting priority enables SDG&E to make timely payments to SDG&E, DWR, and other agencies/Cities where SDG&E is required to collect surcharges, fees and taxes.  Any other outstanding disconnectible and non-disconnectible charges will be paid with any remaining credit balance.

2.

Payment Posting Rules for Utility Billing

a.

Payments will be applied to outstanding charges from the oldest statement first.

b.

The amount of payment applied to SDG&E’s gas and electric energy/service charges on a Utility Bill will be applied on a pro-rata basis between SDG&E gas and electric energy/service charges in the following illustrative manner:

Sample:	Electric	Gas	Total
Bill Date 1/10/06	$100.00	$100.00	$200.00
% of Total	50%	50%	100%
Payment 1/25/06	$50.00	$50.00	$100.00
% of Total	50%	50%	100%

3.

To the extent that SDG&E’s Utility Bill also includes applicable DWR Charges, the amount of payment/credit applied for electric energy/services on such Utility Bill will be prorated among all unpaid disconnectible SDG&E electric energy/service charges and DWR Charges based on the amount owing in each category in the following illustrative manner:

Sample:	SDG&E	Sum of All DWR Charges	FF/Taxes	Total
Bill Date 1/10/06	$35.00	$60.00	$5.00	$100.00
% of Total Billed	35%	60%	5%	100%
Payment 1/25/06	$17.50	$30.00	$2.50	$50.00
% of Total Payment	35%	60%	5%	100%

4.

The payment/credit for the sum of all DWR Charges determined in Step 3 above shall be further prorated between unpaid DWR Power Charge and Bond Charge of a Customer Types in the following illustrative manner:

Sample:	Power Charge	Bond Charge	Total
Bill Date 1/10/06	$54.00	$6.00	$60.00
% of Total Billed DWR Charges	90%	10%	100%
Total Payment Credited to DWR 1/25/06	$27.00	$3.00	$30.00
% of Total Payment Credit to DWR 1/25/06	90%	10%	100%

H.

Reporting of DWR Charges Billing, Collection and Remittance

Prior to the Effective Date of the 2007 Servicing Order, SDG&E sent e-mail notices to DWR at least monthly that provided the following billing data or information of DWR Charges as such charges became effective.

·

Daily aggregate of billed individual Customer consumptions for each Customer Type relating to DWR Charges;

·

Daily aggregate of billed individual Customer consumptions subject to each Fund Type on each applicable Customer Type, excluding Customer consumptions relating to Power Charge and Bond Charge on Bundled Customers;

·

DWR’s share of daily aggregate of billed individual Bundled Customer consumptions for determining Power Charge on Bundled Customers; and

·

Daily aggregate of billed dollar amounts for each Fund Type on each applicable Customer Type.

In addition, the billed individual Customer consumption and dollar amount for a Fund Type on a Customer Type in the billing data or information listed above would have been and will continue to be determined consistent with the methodology provided in the appropriate Appendix to this Attachment B.  

Further, SDG&E sent e-mail notices to DWR each Utility Business Day prior to the Effective Date of the 2007 Servicing Order that provided the following remittance information of DWR Charges as such charges became effective.

·

Remittance processing date;

·

Daily Remittance amounts for each Fund Type on each applicable Customer Type; and

·

Previous month recovery of charged off amounts.

Also prior to the Effective Date of the 2007 Servicing Order, SDG&E sent e-mail notices to DWR each month that provided a Monthly Late Payment Charge Report presenting the calculation of pro-rata sharing of late payment charge collection and a Monthly DWR Charge and Recovery Report presenting information concerning the charge-off and recovery of DWR Charges.

On and after the Effective Date of the 2007 Servicing Order, SDG&E provided the reports contemplated in this Attachment B, substantially in the forms set forth in Attachment C of the 2007 Servicing Order or as may from time to time be modified as mutually agreed to by the Parties or ordered by the Commission.  

On and after the MRTU Effective Date, SDG&E provides the reports contemplated in this Attachment B, substantially in the forms set forth in Attachment C of this 2010 Servicing Order.

To the extent that a different collection rate is to be applied to a sub-group within a Customer Type identified in the Servicing Order pursuant to a future Applicable Commission Order, unless SDG&E and DWR mutually agree to a different reporting format, SDG&E will provide the same information identified in the reporting form related to the original Customer Type as to any sub-group identified within that Customer Type.

Unless expressly provided otherwise, on and after the Effective Date of the 2007 Servicing Order, SDG&E was directed to transmit to DWR all the reports contemplated in Attachment B via secure electronic means or email (password protected or otherwise, as more specifically provided in Attachment C), provided in Microsoft Excel® workbook file format or, to the extent necessary from time to time in comma separated value or fixed width text files, all as further provided in Attachment C.  

I.

Historical Remittance Methodologies

Historical remittance methodologies for specific Fund Types on specific Customer Types for specific historical time periods may differ from the remittance methodologies described in this Attachment B.  Such historical remittance methodologies are included in the appropriate Appendices to this Attachment B.

J.

Utility Filings Impacting DWR Charges

To the extent that SDG&E intends to revise (i) any effective remittance rate for any DWR Charge or (ii) any SDG&E collected rates which would modify effective remittance rate for any CRS component, in either case, applicable to a Customer Type being collected under the 2007 Servicing Order through a filing prepared and submitted by SDG&E to the Commission (hereinafter “DWR Charge Revision”), SDG&E will notify DWR of any such future Commission filings as provided in this Paragraph.  Unless the Commission fails to provide SDG&E with at least two (2) Utility Business Days’ notice of a requirement to file a DWR Charge Revision, no less than two (2) Utility Business Days prior to SDG&E’s submission of the filing to the Commission, SDG&E will notify the DWR Contact Persons listed in Section C of Attachment A (“DWR Contact Persons”) or other DWR representative as mutually agreed to by the Parties, that SDG&E intends to submit a filing to the Commission that changes the effective DWR Charge remittance rate; provided, however, that in the event that SDG&E has less than two (2) Utility Business Days’ notice of a requirement to file, SDG&E will notify DWR as soon as is practicable.  In the event that the Commission has directed SDG&E and DWR to work collaboratively on the DWR Charge Revision, SDG&E will provide the relevant supporting work papers for the DWR Charge Revision to DWR no later than the time SDG&E provides notice as specified in this paragraph.  With respect to all other DWR Charge Revisions filed by SDG&E, after filing of the DWR Charge Revision with the Commission, SDG&E will provide the relevant supporting work papers for a DWR Charge Revision if such papers are requested by DWR.  Upon submission of the filing to the Commission, SDG&E will forward a copy of the final SDG&E filing to the DWR Contact Persons within two (2) Utility Business Days of the filing date.   When the Commission notifies SDG&E of its action concerning the filing, SDG&E will provide a copy of the Commission’s letter, resolution, or other document concerning the filing to the DWR Contact Persons within five (5 ) Utility Business Days of receipt thereof.  SDG&E further agrees to maintain a summary of its Commission filings concerning DWR Charges and other matters covered by the 2007 Servicing Order, and SDG&E will forward an updated copy of such summary to the DWR Contact Persons within 30 days of the end of each calendar quarter.   SDG&E’s non-compliance with its obligations under this Paragraph J will not constitute a material breach under the 2007 Servicing Order and shall not be considered an Event of Default under the 2007 Servicing Order.

K.

Collection of DWR Charges through Non-Utility Bills

In the event that any component of DWR Charges are calculated by SDG&E but billed and collected through Non-Utility Bills, SDG&E will agree to provide daily and monthly reports with respect to collections remitted through Non-Utility Bills in the same format as the Fund Type of the Customer Type provided in Attachment C of the 2007 Servicing Order.  To the extent that any of the requested data included in the reports are not reasonably available to SDG&E, upon notification by SDG&E, DWR agrees to modify the affected reports to be able to reasonably address the concerns of the Parties.

B-

Attachment B

APPENDIX A-1

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - BUNDLED CUSTOMER BOND CHARGE

This Appendix A-1 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed dollar amount of Bond Charge on a Bundled Customer.  

The dollar amount of Bond Charge billed or re-billed to a Bundled Customer is the product of (i) the electric consumption subject to Bond Charge billed or re-billed to the Bundled Customer and (ii) the Bundled Customer Bond Charge rate applicable to the period of such electric consumption.  All electric consumption of a Bundled Customer is subject to Bond Charge unless exempt by Applicable Commission Orders.  

In cases in which the Bundled Customer Bond Charge rate changes during the period of the electric consumption subject to Bond Charge billed or re-billed to a Bundled Customer, SDG&E shall apply each of the differing Bundled Customer Bond Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

A-1-

Attachment B

APPENDIX A-2

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - BUNDLED CUSTOMER POWER CHARGE

This Appendix A-2 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed dollar amount of Power Charge on a Bundled Customer.  In addition, this Appendix A-2 provides an account of historical remittance methodologies for Bundled Customer Power Charge applicable for specific historical time periods.  All capitalized terms shall have the meanings set forth in the body of the Servicing Order or Attachment B; provided that any capitalized terms specifically defined and used in this Appendix A-2 shall have the meanings set forth herein and, unless otherwise stated, such defined terms shall only apply in this Appendix A-2.

A.

Determination of Billed Dollar Amount for Power Charge on a Bundled Customer

The dollar amount of Power Charge billed or re-billed to a Bundled Customer shall be the product of (i) the electric consumption billed or re-billed to the Bundled Customer (ii) the Bundled Customer Power Charge rate in dollar per kilowatt-hour applicable to the period of the consumption and (iii) the corresponding “Individual Customer Billing Cycle Average DWR Percentage” (described below).

In cases in which the Bundled Customer Power Charge rate changes during the period of the electric consumption subject to Power Charge billed or re-billed to a Bundled Customer, SDG&E shall apply each of the differing Bundled Customer Power Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

SDG&E shall determine the “Individual Customer Billing Cycle Average DWR Percentage” over the period of electric consumption subject to Power Charge billed or re-billed to a Bundled Customer as the average of all hourly “Rate Group Average DWR Energy Percentages” over such period weighted by the statistical or dynamic load profile of the rate group of the Bundled Customer over the same period.  SDG&E shall calculate each hourly “Rate Group Average DWR Energy Percentage” of a rate group as the rate group pro rata share of the Hourly Percentage Factor described in Part I and Part II of this Appendix A-2, in proportion to the rate group’s statistical or dynamic load profile in the same hour as further detailed in SDG&E’s Tariff.

SDG&E shall determine the “Hourly Percentage Factor” in accordance with the principles set forth in Attachment H of the 2003 Servicing Order, which included Part I that provides the detailed process of the More Precise Remittance Methodology applicable for Power Charges from Bundled Customers before the Operating Order Effective Date and Part II that provides the detailed process of the Post-Transition Remittance Methodology applicable for Power Charges on Bundled Customers on and after the Operating Order Effective Date.  With formatting changes, Attachment H of the 2003 Servicing Order is provided below in Part I and Part II of Part A of this Appendix A-2.

Part I:

More Precise Remittance Methodology

The methodology in this Part I shall be applied for remittance of Power Charges from Bundled Customers before the Operating Order Effective Date.

a).

SDG&E Remittance Percentage Calculation and True-up

In accordance with SDG&E’s Schedule EECC, as it may be modified or superseded by the Commission from time to time, SDG&E calculates each hour the percentage of Bundled Customers electricity use that is supplied by DWR (the “Hourly Percentage Factor”).  This percentage is calculated using Final Hour-Ahead Schedules that reflect estimated Customer electricity use.  “Estimated Customer Use” shall be defined as the forecasted Customer usage used to establish the Final Hour-Ahead Schedule adjusted using other data that may become available within one day of the Trade Day, as appropriate, to more accurately reflect actual Bundled Customer usage. As final settlement statements reflecting actual meter data and electricity deliveries are received from the ISO, SDG&E will calculate the actual Hourly Percentage Factors.  For each hour, the estimated Hourly Percentage Factor will be subtracted from the actual Hourly Percentage Factor to determine the Hourly Percentage Factor difference.  At the end of each month, a weighted average Hourly Percentage Factor difference will be calculated using all trade dates for which SDG&E has received from the ISO final settlement statements during such month.  This weighted average difference will then be adjusted, if necessary, by commodity revenue dollars for the different periods to obtain an adjustment percentage that will be applied as an hourly adjustment in the next month’s calculations of Hourly Percentage Factors.

b).

Detailed Process

l.

Hourly Percentage Factor Calculation - This calculation is performed on T+1 (the day after the energy is used).

For each day T (trade date) SDG&E will retrieve from ISO published CERS hour-ahead final schedule the amount of DWR energy that is scheduled from SDG&E.

For each day T SDG&E will develop estimates of Bundled Customer usage and imbalance energy for each hour.

These two components, along with output from the True-up Process, will be used to calculate the Hourly Percentage Factor.  SDG&E will calculate the Hourly Percentage Factor for each hour of a trade day T by: (i) dividing the CERS’ Final Hour Ahead Schedule plus estimated imbalance energy schedule for such hour by the SDG&E Estimated Customer Usage for such hour; and (ii) adding the true-up adjustment percentage applicable for the current month, calculated in accordance with Section B.2, below.

2.

True-up Process.  The ISO publishes final settlement statements on T + 51 Utility Business Days.  The actual meter data on the final settlement statements will be used to calculate the actual Hourly Percentage Factor.  The CERS Hour Ahead Final Schedule quantity will be divided by the actual meter data to obtain the actual Hourly Percentage Factor, except that during the term of the Restated Letter Agreement, the sum of the CERS Hour Ahead Final Schedule quantity and the imbalance energy for each corresponding hour will be divided by the actual meter data to obtain the actual Hourly Percentage Factor.

For each hour, the estimated Hourly Percentage Factor will be subtracted from the actual Hourly Percentage Factor to determine the Hourly Percentage Factor difference.

At the end of each month, a weighted average Hourly Percentage Factor difference will be calculated using all trade dates for which final settlement statements were received during that current month.  The weight for the average will be the total Customer load, based on actual meter data for each hour. For all trade dates, for which final settlement statements were received during the current month, the actual meter data will be obtained.  For each hour, the Hourly Percentage Factor difference will be multiplied by the actual meter data for that hour and then divided by the sum of actual meter data for all hours in the month.  All the individual hour weighted results for that month will then be summed to obtain the weighted average Hourly Percentage Factor difference.

The Hourly Percentage Factor will then be adjusted by the commodity revenue dollars for the two time periods: (i) trade dates for which final settlement statements were received, and (ii) next calendar month).  Average commodity revenue dollars represent the combined billed electric commodity revenues for both SDG&E and DWR (in dollars).  The weighted average Hourly Percentage Factor difference will be multiplied by commodity revenue dollars for the trade dates for which final settlement statements were received divided by next forecasted average commodity revenue dollars for the next calendar month.

This adjusted percentage will then be applied as the true-up adjustment percentage in the next month’s Hourly Percentage Factor calculations. The true-up adjustment percentage will be added to the calculation of the Hourly Percentage Factor in accordance with Item 1 of this Part I.

Part II:

Post-Transition Remittance Methodology

The methodology in this Part II shall be applied for remittance of Power Charge on Bundled Customers on and after the Operating Order Effective Date.

a).

SDG&E Remittance Percentage Calculation and True-up

In accordance with SDG&E’s Schedule EECC, as it may be modified or superseded by the CPUC from time to time, SDG&E calculates each hour the percentage of Bundled Customers electricity use that is supplied by DWR (the “Hourly Percentage Factor”).  

1.

Prior to the MRTU Effective Date.  This percentage is calculated using Final Hour-Ahead Schedules and other information reasonably available to SDG&E within one day of the Trade Day that reflect estimated dispatched quantities of SDG&E integrated portfolio resources including the Allocated Contracts as well as estimated Bundled Customer electricity use.  “Estimated Customer Use” shall be defined as the forecasted Customer usage used to establish the Final Hour-Ahead Schedule adjusted using other data that may become available within one day of the Trade Day, as appropriate, to more accurately reflect actual Customer usage.  As final settlement statements reflecting actual meter data and electricity deliveries are received from the ISO, SDG&E will calculate the actual Hourly Percentage Factor.  For each hour, the estimated Hourly Percentage Factor will be subtracted from the actual Hourly Percentage Factor to determine the Hourly Percentage Factor difference.  At the end of each month, a weighted average Hourly Percentage Factor difference will be calculated using all trade dates for which SDG&E has received from the ISO final settlement statements during such month.  This weighted average difference will then be adjusted, if necessary, by commodity revenue dollars for the different periods to obtain an adjustment percentage that will be applied as an hourly adjustment in the next month’s calculations of Hourly Percentage Factor.

2.

On and after the MRTU Effective Date.  The term “Hourly Percentage Factor” is replaced by the term “DWR Percentage Calculation” which is the percentage of DWR Contract power relative to the total Estimated Bundled Customer Load, as further described in Section A of Part II of Exhibit C of the 2010 Operating Order.  The amount applied to determine DWR Percentage Calculation for DWR Remittance Basis and Estimated Bundled Customer Load shall be as shown in DWR Remittance Basis Calculation Report, substantially in the form set forth in Section 3B of Attachment C.

More specifically as to SDG&E, the Estimated Bundled Customer Load is calculated hourly, using the integration of actual area MW load for one hour obtained from SDG&E’s Energy Management System (“EMS”) and subtracting out hourly transmission losses, which include hourly Palo Verde flow losses and forecasted hourly Non-Bundled Customer Load, consisting of Direct Access Customers, Customer Generation Departing Load Customers, Municipal Departing Load Customers and Community Choice Aggregation Customers, as such Customer Types are specifically defined in the Servicing Order and may exist from time to time with respect to SDG&E.

b).

Detailed Process - Prior to the MRTU Effective Date.  The following provisions shall apply prior to the MRTU Effective Date:

1.  Hourly Percentage Factor Calculation.  This calculation is performed on T + 1 (the day after the energy is used).

For each day T (trade date) SDG&E will retrieve from ISO published hour-ahead final schedules of SDG&E integrated portfolio resources including the Allocated Contracts.

For each day T, SDG&E will develop estimates of Bundled Customer usage.

These two components, along with output from the True-up Process, will be used to calculate the Hourly Percentage Factor.  SDG&E will calculate the Hourly Percentage Factor for each hour of a trade day T in accordance with the principles provided in Exhibit C of the Operating Order; and (ii) adding the true-up adjustment percentage applicable for the current month, calculated in accordance with Item.2 below.

2.  True-up Process.  The ISO publishes final settlement statements on T + 51 Utility Business Days.  The actual meter data on the final settlement statements will be used to calculate the actual Hourly Percentage Factor in accordance with the principles provided in Exhibit C of the Operating Order.

For each hour the estimated Hourly Percentage Factor will be subtracted from the actual Hourly Percentage Factor to determine the Hourly Percentage Factor difference.

At the end of each month, a weighted average Hourly Percentage Factor difference will be calculated using all trade dates for which final settlement statements were received during that current month.  The weight for the average will be the total Bundled Customer load, based on actual meter data for each hour.  For all trade dates, for which final settlement statements were received during the current month, the actual meter data will be obtained.  For each hour, the Hourly Percentage Factor difference will be multiplied by the actual meter data for that hour and then divided by the sum of actual meter data for all hours in the month.  All the individual hour weighted results for that month will then be summed to obtain the weighted average Hourly Percentage Factor difference.

The Hourly Percentage Factor will then be adjusted by the commodity revenue dollars for the two time periods: (i) trade dates for which final settlement statements were received, and (ii) next calendar month.  Average commodity revenue dollars represent the combined billed electric commodity revenues for both SDG&E and DWR (in dollars).  The weighted average Hourly Percentage Factor difference will be multiplied by commodity revenue dollars for the trade dates for which final settlement statements were received divided by next forecasted average commodity revenue dollars for the next calendar month.

This adjusted percentage will then be applied as the true-up adjustment percentage in the next month’s Hourly Percentage Factor calculations. The true-up adjustment percentage will be added to the calculation of the Hourly Percentage Factor in accordance with Sub-section (b)(l) above.

c).

Detailed Process - On and after the MRTU Effective Date.  The following provisions shall apply on and after the MRTU Effective Date:

On and after the MRTU Effective Date, there will not be true-ups of Estimated Bundled Customer Load component that is applied to determine DWR Percentage Calculation.  Actual DWR Remittance Basis will be adjusted, corrected or updated as set forth in the SDG&E IST True-Up Report or in the DWR Remittance Basis True-up Report, described in Section 3(B) or 3(D) of Attachment C of this Servicing Order.

In addition, SDG&E will provide DWR with a monthly report indicating the daily Estimated Bundled Customer Load, the ISO metered load, and a monthly simple average of the daily variance amounts.  

B.

Additional Applicable Methodologies

1.

Transition Period.  The Parties recognize that prior to October 1, 2001, SDG&E has been remitting Power Charge for Bundled Customers to DWR based upon the interim remittance methodologies described in Decision 01-03-081, adopted by the Commission on March 27, 2001, and Decision 01-05-064, adopted by the Commission on May 15, 2001 (collectively the "Interim Remittance Methodologies").  SDG&E shall reconcile the amounts remitted pursuant to the Interim Remittance Methodologies at the time and in the manner set forth in Attachment B to the 2003 Servicing Order.

2.

Transition to Billing Effective Date and Reconciliation.  The Parties recognize that prior to the date on which SDG&E mailed a consolidated Utility Bill which reflected a separate line item or denotation of DWR Charges (the “Billing Effective Date”), SDG&E has remitted DWR Charges based upon the remittance methodology set forth in the Restated Letter Agreement, dated June 18, 2001 and referenced in Attachment E to this Servicing Order (the “Restated Letter Agreement”).  Commencing on the Business Day following the Billing Effective Date, SDG&E commenced daily remittances based upon the procedures set forth herein and in Section 4.2 of the Servicing Agreement approved by the Commission pursuant to Decision 01-09-013, as amended from time to time (“More Precise Billing Methodology”).  

3.

Post-Transition Remittance Methodology.  On and after the Operating Order Effective Date, SDG&E shall transition from using the More Precise Remittance Methodology to using the Post-Transition Remittance Methodology as provided in Attachments B and H attached to the 2003 Servicing Order, consistent with the Contract Allocation Order and the Settlement Principles for Remittances and Surplus Revenues as set forth in Exhibit C of the Operating Order, and as further set forth this Servicing Order and Attachment B and this Appendix A-2.  This transition will include the continuation of the More Precise Remittance Methodology true-up after the Operating Order Effective Date as long as necessary or appropriate (the “Transition Period”) to account for DWR Power provided to Bundled Customers prior to the Operating Order Effective Date. True-Up remittances during the Transition Period using the More Precise Remittance Methodology shall be made in addition to Remittances made in accordance with the Post Transition Remittance Methodology set forth in Attachment H of the 2003 Servicing Order.

4.

2003 One Time Bill Credit.  Pursuant to Commission Decision 03-09-018 and consistent with SDG&E Advice Letter 1523-E, SDG&E implemented a one-time bill credit in the aggregate amount of $135,366,371 to refund DWR Power Charge to Bundled Customers who pay DWR Bond Charge in SDG&E’s service territory.  With the agreement of DWR and to fund this one-time bill credit, SDG&E withheld then on-going daily DWR Power Charge remittances SDG&E collected from Bundled Customers and Direct Access Customers commencing on September 18, 2003 and ending on November 18, 2003, inclusive, during which period SDG&E remitted no Power Charge from Bundled Customers and Direct Access Customers to DWR.  The one-time bill credit procedures are further provided in that certain letter agreement, dated August 30, 2004, between DWR and SDG&E.  Pursuant to the letter agreement, SDG&E credited DWR the undistributed One Time Bill Credit in the amount of $1,731,082.27 against amount DWR owed to SDG&E for DWR Charges related billing and collection system changes.

A-2-

Attachment B

APPENDIX B-1

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - DIRECT ACCESS BOND CHARGE

This Appendix B-1 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed dollar amount of Bond Charge on a Direct Access Customer.  

The dollar amount of Bond Charge billed or re-billed to a DA Customer shall be the product of (i) the electric consumption in kilowatt-hours subject to Bond Charge billed to the DA Customer and (ii) the DA Customer Bond Charge rate applicable to the period of such electric consumption.  All electric consumption of a DA Customer is subject to Bond Charge unless exempt by Applicable Commission Orders.  

In cases in which the DA Customer Bond Charge rate changes during the period of the electric consumption subject to Bond Charge billed or re-billed to a DA Customer, SDG&E shall apply each of the differing DA Customer Bond Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

The DA Customer Bond Charge is one of three SDG&E rate components known as the Customer Responsibility Surcharge.  As determined by Applicable Commission Orders, the CRS was capped at a specific amount with specific billing priorities.  As determined by Applicable Commission Orders, the DA Customer Bond Charge component received the first billing priority within the capped level that can be billed.  The billing priority of DA Customer Bond Charge, including the application of capped level that can be billed, will be as determined by the Commission from time to time.

B-1-

Attachment B

APPENDIX B-2

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - DIRECT ACCESS POWER CHARGE

This Appendix B-2 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed amount of Power Charge on a Direct Access Customer.  

The dollar amount of Power Charge billed or re-billed to a DA Customer shall be the product of (i) the electric consumption in kilowatt-hours subject to Power Charge billed to the DA Customer and (ii) the DA Customer Power Charge rate applicable to the period of such electric consumption.  All electric consumption of a DA Customer is subject to Power Charge unless exempt by Applicable Commission Orders.   

In cases in which the DA Customer Power Charge rate changes during the period of the electric consumption subject to Power Charge billed or re-billed to a DA Customer, SDG&E shall apply each of the differing DA Customer Power Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

The DA Customer Power Charge is one of three SDG&E rate components known as the Customer Responsibility Surcharge.  As determined by Applicable Commission Orders, the CRS was capped at a specific amount with specific billing priorities.  As determined by Applicable Commission Order, the DA Customer Power Charge component received the third billing priority within the capped level that can be billed.  The billing priority of DA Customer Power Charge, including the application of capped level that can be billed, will be as determined by the Commission from time to time.

B-2-

Attachment B

APPENDIX C-1

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - CUSTOMER GENERATION DEPARTING
LOAD BOND CHARGE

This Appendix C-1 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed amount of Bond Charge on Customer Generation Departing Load Customers.  

The dollar amount of Bond Charge billed or re-billed to a CGDL shall be the product of (i) the metered consumption in kilowatt-hours subject to Bond Charge billed to the CGDL and (ii) the CGDL Bond Charge rate applicable to the period of such electric consumption.  All electric consumption of a CGDL is subject to Bond Charge unless exempt by Applicable Commission Orders.  

In cases in which the CGDL Customer Bond Charge rate changes during the period of the metered consumption subject to Bond Charge billed or re-billed to a CGDL Customer, SDG&E shall apply each of the differing CGDL Customer Bond Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

The CGDL Bond Charge is one of three SDG&E rate components known as the Customer Responsibility Surcharge.  As determined by Applicable Commission Orders, the CRS was capped at a specific amount with specific billing priorities.  As determined by Applicable Commission Orders, the CGDL Bond Charge component received the first billing priority within the capped level that can be billed.  The billing priority of CGDL Bond Charge, including the application of capped level that can be billed, will be as determined by the Commission from time to time.

C-1-

Attachment B

APPENDIX C-2

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - CUSTOMER GENERATION DEPARTING
LOAD POWER CHARGE

This Appendix C-2 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed amount of Power Charge on Customer Generation Departing Load Customers.  

The dollar amount of Power Charge billed or re-billed to a CGDL shall be the product of (i) the metered consumption in kilowatt-hours subject to Power Charge billed to the CGDL and (ii) the CGDL Power Charge rate applicable to the period of such electric consumption.  All electric consumption of a CGDL is subject to Power Charge unless exempt by Applicable Commission Orders.  

In cases in which the CGDL Customer Power Charge rate changes during the period of the metered consumption subject to Power Charge billed or re-billed to a CGDL Customer, SDG&E shall apply each of the differing CGDL Customer Power Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

The CGDL Power Charge is one of three SDG&E rate components known as the Customer Responsibility Surcharge.  As determined by Applicable Commission Orders, the CRS was capped at a specific amount with specific billing priorities.  The billing priority of CGDL Power Charge, including the application of capped level that can be billed, will be as determined by the Commission from time to time.  

C-2-

Attachment B

APPENDIX D-1

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION OF - MUNICIPAL DEPARTING LOAD BOND CHARGE

Commission Decision 03-07-028, as amended, clarified or modified by Decision 03-08-076, Decision 04-11-014, Decision 04-12-059 and Decision 05-07-038 impose a CRS, including Bond Charge on certain Municipal Departing Load for load that departed bundled service on and after February 1, 2001.  

Upon effectiveness of Applicable Commission Order relating to the remittance of Bond Charge by Municipal Departing Load and to the extent SDG&E is involved, the Parties intend to update this Appendix D-1 to reflect the applicable remittance methods.  The Parties further agree that the commencement of billing and collection of Bond Charge on Municipal Departing Load is an event contemplated under Section 10(a)(vi) of this Servicing Order to the extent that SDG&E is involved in the transaction.

D-1-

Attachment B

APPENDIX D-2

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION -MUNICIPAL DEPARTING LOAD POWER CHARGE

Commission Decision 03-07-028, as amended, clarified or modified by Decision 03-08-076, Decision 04-11-014, Decision 04-12-059 and Decision 05-07-038 impose a CRS, including Power Charge on certain Municipal Departing Load for load that departed bundled service on and after February 1, 2001.  

Upon effectiveness of Applicable Commission Order relating to the remittance of Power Charge by Municipal Departing Load, and to the extent SDG&E is involved, the Parties intend to update this Appendix D-2 to reflect the applicable remittance methods.  The Parties further agree that the commencement of billing and collection of Power Charge on Municipal Departing Load is an event contemplated under Section 10(a)(vi) of this Servicing Order to the extent SDG&E is involved in the transaction.

D-2-

Attachment B

APPENDIX E-1

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - COMMUNITY CHOICE AGGREGATION BOND CHARGE

This Appendix E-1 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed dollar amount of Bond Charge on a Community Choice Aggregation Customer if and when a CCA establishes service within SDG&E’s service territory.  

The dollar amount of Bond Charge billed or re-billed to a CCA Customer shall be the product of (i) the electric consumption in kilowatt-hours subject to Bond Charge billed to the CCA Customer and (ii) the CCA Customer Bond Charge rate applicable to the period of such electric consumption.  All electric consumption of a CCA Customer is subject to Bond Charge unless exempt by Applicable Commission Orders.  

In cases in which the CCA Customer Bond Charge rate changes during the period of the electric consumption subject to Bond Charge billed or re-billed to a CCA Customer, SDG&E shall apply each of the differing CCA Customer Bond Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

E-1-

Attachment B

APPENDIX E-2

SAN DIEGO GAS & ELECTRIC COMPANY

BILL DETERMINATION - COMMUNITY CHOICE AGGREGATION POWER CHARGE

This Appendix E-2 to Attachment B of the Servicing Order sets forth specific methodology to be applied in determining the billed amount of Power Charge on a Community Choice Aggregation Customer.  

The dollar amount of Power Charge billed or re-billed to a CCA Customer shall be the product of (i) the electric consumption in kilowatt-hours subject to Power Charge billed to the CCA Customer and (ii) the CCA Customer Power Charge rate applicable to the period of such electric consumption.  All electric consumption of a CCA Customer is subject to Power Charge unless exempt by Applicable Commission Orders.   

In cases in which the CCA Customer Power Charge rate changes during the period of the electric consumption subject to Power Charge billed or re-billed to a CCA Customer, SDG&E shall apply each of the differing CCA Customer Power Charge rates over such period to a portion of such consumption in proportion to the number of calendar days within the period that each rate was effective.  

E-2-1

8/23/2010

ATTACHMENT C

SAN DIEGO GAS & ELECTRIC COMPANY

SAMPLE DAILY AND MONTHLY REPORTS

SDG&E will provide daily and monthly reports as further described in this Attachment C to DWR.  The sample report templates included this Attachment C have been included for illustrative purposes only.  Variations of reports specifications from those in this Attachment C may be implemented upon mutual agreement of the Parties.  The report specifications in this Attachment C include all contemplated categories of DWR Charges from Customer Types identified and currently pending in Commission proceedings as well as DWR’s sharing of surplus energy sales (prior to the MRTU Effective Date).  Upon approval of the Servicing Order by the Commission, actual reports submitted by SDG&E will only include categories of DWR Charges active during the reporting period.

Prior to the approval of the 2007 Servicing Order, SDG&E did not provide all remittance information and data in Microsoft Excel® workbook format.  SDG&E has implemented Microsoft Excel® workbook format as specified in this Attachment C by no later than six months after the Effective Date of the 2007 Servicing Order.  From time to time, if the need for a new format is identified by SDG&E or DWR, DWR agrees to discuss and agree to additional time as reasonably requested by SDG&E.

On and after the MRTU Effective Date, certain additional information shall be provided to DWR, all as provided in Section 3 of this Attachment C.

Unless otherwise specifically provided elsewhere in this Attachment C, SDG&E will submit all reports by secure electronic means or password protected e-mails addressed to “IOU_Remit@water.ca.gov” and, in either case, in a Microsoft Excel® workbook format, or to the extent necessary from time to time, in comma separated value or fixed width text files, with the appropriate filename and subject line, all as further provided in this Attachment C.

Section 1.

End-Use Customer Reports

A.

Daily Remittance Report

The Daily Remittance Report is to be prepared and submitted to DWR as a part of the Remittance Netting Report described in Sub-section B below on each Utility Business Day of the Term.  

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “fmr@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - Daily Remittance Report yyyymmdd v#.xls

Example: SDG&E - Daily Remittance Report 20090902 v1.xls

·

The subject line of e-mail: <utility name> - Daily Remittance Report for yyyymmdd

Example: SDG&E - Daily Remittance Report for 20090902

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the daily report with the subsequent version number.

Example:  SDG&E - Daily Remittance Report 20090902 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the daily cash balance amounts of DWR Charges with a separate entry for each Fund Type on each applicable Customer Type in the Daily Remittance Reports.  The following table defines such daily cash balance amounts.  SDG&E shall remit any positive daily cash balance amount due to DWR according to the timeline specified in the Attachment B of the Servicing Order.

DWR Account Reference	Fund Type	Customer Type	Collection Type	Description of Daily Cash
8021360001	Power	Bundled	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for Bundled Customers Power Charge
8021360002	Power	DA	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for DA Customers Power Charge
8021360003	Power	CGDL	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for CGDL Power Charge
8021360004	Power	CCA	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for CCA Power Charge
8021360010	Power	MDL	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for MDL Power Charge
8021360001	Power	Bundled	Late Payment Charge	Daily balance of late payment charges on Bundled Customers Power Charge
8021360002	Power	DA	Late Payment Charge	Daily balance of late payment charges on DA Customers Power Charge
8021360003	Power	CGDL	Late Payment Charge	Daily balance of late payment charges on CGDL Customers Power Charge
8021360004	Power	CCA	Late Payment Charge	Daily balance of late payment charges on CCA Customers Power Charge
8021360010	Power	MDL	Late Payment Charge	Daily balance of late payment charges on MDL Customers Power Charge
8021360001	Power	Bundled	Charge-off Recovery	Daily balance of recovered charge-off on Bundled Customers Power Charge
8021360002	Power	DA	Charge-off Recovery	Daily balance of recovered charge-off on DA Customers Power Charge
8021360003	Power	CGDL	Charge-off Recovery	Daily balance of recovered charge-off on CGDL Power Charge
8021360004	Power	CCA	Charge-off Recovery	Daily balance of recovered charge-off on CCA Power Charge
8021360010	Power	MDL	Charge-off Recovery	Daily balance of recovered charge-off on MDL Power Charge
8059000000	Bond	Bundled	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for Bundled Customers Bond Charge
8059000001	Bond	DA	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for DA Customers Bond Charge
8059000003	Bond	CGDL	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for CGDL Bond Charge
8059000004	Bond	CCA	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for CCA Bond Charge
8059000005	Bond	MDL	Remittance	Daily balance of Customer payment netted against any amount due to SDG&E for MDL Bond Charge
8059000000	Bond	Bundled	Late Payment Charge	Daily balance of late payment charges on Bundled Customers Bond Charge
8059000001	Bond	DA	Late Payment Charge	Daily balance of late payment charges on DA Customers Bond Charge
8059000003	Bond	CGDL	Late Payment Charge	Daily balance of late payment charges on CGDL Customers Bond Charge
8059000004	Bond	CCA	Late Payment Charge	Daily balance of late payment charges on CCA Customers Bond Charge
8059000005	Bond	MDL	Late Payment Charge	Daily balance of late payment charges on MDL Customers Bond Charge
8059000000	Bond	Bundled	Charge-off Recovery	Daily balance of recovered charge-off on Bundled Customers Bond Charge
8059000001	Bond	DA	Charge-off Recovery	Daily balance of recovered charge-off on DA Customers Bond Charge
8059000003	Bond	CGDL	Charge-off Recovery	Daily balance of recovered charge-off on CGDL Bond Charge
8059000004	Bond	CCA	Charge-off Recovery	Daily balance of recovered charge-off on CCA Bond Charge
8059000005	Bond	MDL	Charge-off Recovery	Daily balance of recovered charge-off on MDL Bond Charge

C-

Example:

Daily Remittance Report
Date:	9/2/2009
Utility Name:	SDG&E
DWR Account Reference	Fund Type	Customer Type	Collection Type	Daily Cash
8021360001	Power	Bundled	Remittance	$xxx,xxx.xx
8021360002	Power	DA	Remittance	$xxx,xxx.xx
8021360003	Power	CGDL	Remittance	$xxx,xxx.xx
8021360004	Power	CCA	Remittance	$xxx,xxx.xx
8021360010	Power	MDL	Remittance	$xxx,xxx.xx
8021360001	Power	Bundled	Late Payment Charge	$xxx,xxx.xx
8021360002	Power	DA	Late Payment Charge	$xxx,xxx.xx
8021360003	Power	CGDL	Late Payment Charge	$xxx,xxx.xx
8021360004	Power	CCA	Late Payment Charge	$xxx,xxx.xx
8021360010	Power	MDL	Remittance	$xxx,xxx.xx
8021360001	Power	Bundled	Charge Off Recovery	$xxx,xxx.xx
8021360002	Power	DA	Charge Off Recovery	$xxx,xxx.xx
8021360003	Power	CGDL	Charge Off Recovery	$xxx,xxx.xx
8021360004	Power	CCA	Charge Off Recovery	$xxx,xxx.xx
8021360010	Power	MDL	Charge Off Recovery	$xxx,xxx.xx
Power Charge Remittance Amount				$x,xxx,xxx.xx
8059000000	Bond	Bundled	Remittance	$xxx,xxx.xx
8059000001	Bond	DA	Remittance	$xxx,xxx.xx
8059000003	Bond	CGDL	Remittance	$xxx,xxx.xx
8059000004	Bond	CCA	Remittance	$xxx,xxx.xx
8059000005	Bond	MDL	Remittance	$xxx,xxx.xx
8059000000	Bond	Bundled	Late Payment Charge	$xxx,xxx.xx
8059000001	Bond	DA	Late Payment Charge	$xxx,xxx.xx
8059000003	Bond	CGDL	Late Payment Charge	$xxx,xxx.xx
8059000004	Bond	CCA	Late Payment Charge	$xxx,xxx.xx
8059000005	Bond	MDL	Late Payment Charge	$xxx,xxx.xx
8059000000	Bond	Bundled	Charge Off Recovery	$xxx,xxx.xx
8059000001	Bond	DA	Charge Off Recovery	$xxx,xxx.xx
8059000003	Bond	CGDL	Charge Off Recovery	$xxx,xxx.xx
8059000004	Bond	CCA	Charge Off Recovery	$xxx,xxx.xx
8059000005	Bond	MDL	Charge Off Recovery	$xxx,xxx.xx
Bond Charge Remittance Amount				$x,xxx,xxx.xx

iii)

Wiring or ACH transfer Information - The following information should appear in the wire or ACH transmittal:

<Utility Name> <Fund Type><Collection Date yyyymmdd>

Example:

SDG&E DWR Power 20090902

B.

Remittance Netting Report

The Remittance Netting Report, which will include the items in the Daily Remittance Report described in Sub-section A, is to be submitted to DWR on any Utility Business Day of the Term on which SDG&E nets amount owed by DWR to SDG&E against the amount of Customer payment for a Charge Type on an applicable Customer Type.  

(i)

Delivery Mechanism and Naming Convention - The Remittance Netting Report should be attached to the same e-mail transmitting the Daily Remittance Report.

·

The format of the filename: <utility name> - Remittance Netting Report yyyymmdd v#.xls

Example: SDG&E - Remittance Netting Report 20090902 v1.xls

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the daily report with the subsequent version number.

(ii)

Required Information – The required information is shown in the following example.  Except for the Remittance Adjustment and Daily Remittance values, other required information is identical to that for the Daily Remittance Report.  The following table defines Remittance Adjustment and Daily Remittance.

Column	Description
Adjustments	Adjustment applied in determining the daily remittance amount
Net Cash	Actual dollar amount remitted to DWR on the given day for a DWR Charge Fund Type on an applicable Customer Type, equal to the difference between the Daily Cash and the Remittance Adjustment

Example:

C-

DAILY REMITTANCE REPORT
DATE:	9/1/2009
UTILITY NAME	SDGE
DWR ACCOUNT REFERENCE	FUND TYPE	CUSTOMER TYPE	COLLECTION TYPE	DAILY CASH	ADJUSTMENTS	NET CASH
				(a)	(b)	(a-b)
8021360001	POWER	BUNDLED	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360002	POWER	DA	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360003	POWER	CGDL	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360004	POWER	CCA	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360010	POWER	MDL	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360001	POWER	BUNDLED	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360002	POWER	DA	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360003	POWER	CGDL	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360004	POWER	CCA	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360010	POWER	MDL	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360001	POWER	BUNDLED	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360002	POWER	DA	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360003	POWER	CGDL	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360004	POWER	CCA	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8021360010	POWER	MDL	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
POWER CHARGE REMITTANCE AMOUNT				$x,xxx,xxx.xx	$x,xxx,xxx.xx	$x,xxx,xxx.xx
8059000000	BOND	BUNDLED	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000001	BOND	DA	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000003	BOND	CGDL	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000004	BOND	CCA	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000005	BOND	MDL	REMITTANCE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000000	BOND	BUNDLED	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000001	BOND	DA	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000003	BOND	CGDL	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000004	BOND	CCA	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000005	BOND	MDL	LATE PAYMENT CHARGE	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000000	BOND	BUNDLED	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000001	BOND	DA	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000003	BOND	CGDL	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000004	BOND	CCA	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
8059000005	BOND	MDL	CHARGE-OFF RECOVERY	$xxx,xxx.xx	$xxx,xxx.xx	$xxx,xxx.xx
BOND CHARGE REMITTANCE AMOUNT				$x,xxx,xxx.xx	$x,xxx,xxx.xx	$x,xxx,xxx.xx
GRAND TOTAL				$x,xxx,xxx.xx	$x,xxx,xxx.xx	$x,xxx,xxx.xx

C.

Monthly Billing Report

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility-name> - Monthly Billing Report yyyymmv#.xls

Example: SDG&E – Monthly Billing Report 200909v1.xls

·

The subject line of e-mail:  <utility-name> - Monthly Billing Report for yyyymm

Example: SDG&E – Monthly Billing Report for 200909

(ii)

Required Information and Timeline - The Monthly Billing Report submitted to DWR by the seventh Utility Business Day of a delivery month.  SDG&E shall report the data columns specified in the following table for each Fund Type of DWR Charges on each applicable Customer Type with daily quantities in the Monthly Billing Report.  This table is followed by a screen shot of a sample report in Excel.

Column #	Column	Description
1	Date	Utility Business Day (MM/DD/YY)
2	Total Bundled Billed kWh	Sum of all individual Bundled Customer electric consumptions in kilowatt-hours billed in a month
3	Bundled Power Billed kWh	Sum of all Individual Bundled Power Charge Billed kWhs in a month
4	Bundled Power Billed Amount ($)	Sum of all Individual Bundled Power Charge Billed Dollar Amounts in a month
5	Bundled Bond Billed kWh	Sum of all Individual Bundled Bond Charge Billed kWhs in a month
6	Bundled Bond Billed Amount ($)	Sum of all Individual Bundled Bond Charge Billed Dollar Amounts
7	Total DA Billed kWh	Sum of all individual DA Customer electric consumptions in kilowatt-hours billed in a month
8	DA Power Billed kWh	Sum of all Individual DA Power Charge Billed kWhs in a month
9	DA Power Billed Amount ($)	Sum of all Individual DA Power Charge Billed Dollar Amounts in a month
10	DA Bond Billed kWh	Sum of all Individual DA Bond Charge Billed kWhs in a month
11	DA Bond Billed Amount	Sum of all Individual DA Bond Charge Billed Dollar Amounts in a month
12	Total CGDL Billed kWh	Sum of all individual CGDL electric consumptions in kilowatt-hours billed in a month
13	CGDL Power Billed kWh	Sum of all Individual CGDL Power Charge Billed kWhs in a month
14	CGDL Power Billed Amount ($)	Sum of all Individual CGDL Power Charge Billed Dollar Amounts in a month
15	CGDL Bond Billed kWh	Sum of all Individual CGDL Bond Charge Billed kWhs in a month
16	CGDL Bond Billed Amount	Sum of all Individual CGDL Bond Charge Billed Dollar Amounts in a month
17	Total MDL Billed kWh	Sum of all individual MDL electric consumptions in kilowatt-hours billed in a month
18	MDL Power Billed kWh	Sum of all Individual MDL Power Charge Billed kWhs in a month
19	MDL Power Billed Amount ($)	Sum of all Individual MDL Power Charge Billed Dollar Amounts in a month
20	MDL Bond Billed kWh	Sum of all Individual MDL Bond Charge Billed kWhs in a month
21	MDL Bond Billed Amount	Sum of all Individual MDL Bond Charge Billed Dollar Amounts in a month
22	Total CCA Billed kWh	Sum of all individual CCA electric consumptions in kilowatt-hours billed in a month
23	CCA Power Billed kWh	Sum of all Individual CCA Power Charge Billed kWhs in a month
24	CCA Power Billed Amount ($)	Sum of all Individual CCA Power Charge Billed Dollar Amounts in a month
25	CCA Bond Billed kWh	Sum of all Individual CCA Bond Charge Billed kWhs in a month
26	CCA Bond Billed Amount	Sum of all Individual CCA Bond Charge Billed Dollar Amounts in a month

Example:

D.

Monthly Late Payment Charge Report

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility-name> - Monthly Late Payment Charge Report yyyymmvx.xls

Example: SDG&E – Monthly Late Payment Charge Report 200909v1.xls

·

The subject line of e-mail:  <utility-name> - Monthly Late Payment Charge Report for yyyymm

Example: SDG&E – Monthly Late Payment Charge Report for 200909

(ii)

Required Information and Timeline - The Monthly Late Payment Charge Report will be provided to DWR on the 7^th Utility Business Day after the end of a month of the term.  The table below lists the data columns that will be required for the Monthly Late Payment Charge Report and explains the formulas to be used for the calculated values in certain data columns.

Column #	Column Title	Description
1	Business Month	The SDG&E Business Month
2	LPC Bill	Total LPC billed in the Business Month
3	DWR Commodity Bill	DWR Bundled Power Charge Billed in the Business Month
4	DWR Bond Charge Bill	DWR Bond Charge billed to all applicable Customer Types the Business Month
5	DWR CRS Power Charge Bill	The Power Charge component of Customer Responsibility Surcharge billed to all applicable Customer Types in the Business Month
6	Total DWR Bill	Total amount of DWR Charge bills (Sum of values in Columns 3, 4 and 5 in the Business Month)
7	Utility Bill	SDG&E revenue billed in the Business Month
8	DWR LPC Share %	DWR’s share of LPC billed in the Business Month (Column 6 value in the preceding Business Month divided by Column 7 value in the preceding Business Month)
9	Gross DWR LPC Collection	The DWR’s Share of LPC collected in the Business Month (Column 8 value in the preceding Business Month multiplied by Column 2 value in the preceding Business Month)
10	C&I Charge-Off %	Percentage of the bad debt charge-off for amounts billed to commercial and industrial customers in the Business Month
11	DWR LPC Charge-Off	DWR’s share of late payment charge bad debt (Column 9 value  in the Business Month multiplied by Column 10 value in the same Business Month)
12	DWR LPC Collection Cost	DWR’s share of collection agency commission for collecting the late payment charge in the Business Month
13	Net DWR LPC Collection	Net DWR LPC collection in the Business Month (Column 9 value in the Business Month less Column 12 value in the same Business Month and less Column 11 value six Business Months ago)
14	DWR LPC Collection – Commodity	Net DWR LPC collection in the Business Month attributed to Power Charge billed to Bundled Customers  (Column 13 value in the Business Month multiplied by the ratio of the Column 3 value two Business Months ago to the Column 6 value two Business Months ago)
15	DWR LPC Collection – Bond	Net DWR LPC collection in the Business Month attributed to Bond Charge billed to all Customer Types  (Column 13 multiplied by the ratio of the Column 4 value two Business Months ago to the Column 6 value two Business Months ago)
16	CWR LPC Collection – CRS Power	Net DWR LPC collection in the Business Month attributed to the Power Charge component of the Cost Responsibility Surcharge billed to all Customer Types (Column 13 multiplied by the ratio of the Column 5 value two Business Months ago to the Column 6 value two Business Months ago)

Example:

E.

Monthly DWR Charge-Off and Recovery Report

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility-name> - Monthly DWR Charge-Off and Recovery Report yyyymmvx.xls

Example: SDG&E – Monthly DWR Charge-Off and Recovery Report 200909v1.xls

·

The subject line of e-mail:  <utility-name> - Monthly DWR Charge-Off and Recovery Report for yyyymm

Example: SDG&E – Monthly DWR Charge-Off and Recovery Report for 200909

(ii)

Required Information and Timeline - The Monthly DWR Charge-Off and Recovery Report will be provided to DWR on the 7^th Utility Business Day after the end of a month of the term.  The table below lists the data items that will be required for the Monthly DWR Charge-Off and Recovery Report.

Item #	Item	Description
1	Process Date	Date the report is created
2	Report Run Date	Date the report is printed
3	DWR Charge Off Information - Residential	Bad debt charge-off for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge on residential customers
4	DWR Charge Off Information – Commercial & Industrial	Bad debt charge-off for DWR Power Charge to Bundled Customers, DWR Bond Charge or DWR CRS Power Charge on commercial and industrial customers
5	DWR Charge Off Information – Total Charge Off	Sum of Items 3 and 4
6	Recovery Through Agency – Residential Bad Debt	Amount of bad debt recovered from residential customers by collection agencies for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge
7	Recovery Through Agency – Commercial & Industrial Bad Debt	Amount of bad debt recovered from commercial and industrial customers by collection agencies for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge
8	Total Bad Debt Recovery Thru Agency	Sum of Items 6 and 7
9	Recovery Non-Agency – Residential Bad Debt	Amount of bad debt recovered from residential customers by SDG&E for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge
10	Recovery Non-Agency – Commercial & Industrial Bad Debt	Amount of bad debt recovered from commercial and industrial customers by SDG&E for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge
11	Total Bad Debt Recovery Non-Agency	Sum of Items 9 and 10
12	DWR Total Recovery on Charged Off Accounts	Sum of Items 8 and 11
13	DWR Total Recovery on Final Accounts Through Agency	Amount of all outstanding balances of final accounts recovered by collection agencies for DWR Power Charge to Bundled Customer, DWR Bond Charge or DWR CRS Power Charge
14	DWR Recovery by Collection Agency – Charge Off Accounts	Item 8
15	DWR Recovery by Collection Agency – Final Accounts	Item 13
16	DWR Recovery by Collection Agency – Total to Base Collection Agency Fees on	Sum of Items 14 and 15

Example:

Section 2.

Surplus Energy Sales Reports - Prior to the MRTU Effective Date Only

The provisions set forth in this Section 2 shall be applicable prior to the MRTU Effective Date only.  

A.

Surplus Energy Sales Payment Report

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “fmr@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line.

·

The format of the filename: <utility name> - SS Payment Report yyyymm v#.xls

Example: SDG&E – SS Payment Report 200507 v1.xls

·

The subject line of e-mail: <utility name> - Surplus Energy Sales Payment Report for yyyymm

Example: SDG&E - Surplus Energy Sales Payment Report for 200507

Modifications to a submitted report should be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

(ii)

Required Information and Timeline - The Surplus Energy Sales Payment Report is to be submitted to DWR monthly on the day SDG&E remits to DWR the Preliminary Surplus Energy Sales Remittance Amount and the Delivery Month Surplus Energy Sales True-Up Amount.  The report should be consistent in form and substance to the example screenshot below.

Example:

San Diego Gas & Electric Company

Surplus Energy Sales Payment Report

July 21, 2005 Payment Date

DWR Account Reference: 8021360006

Description	Delivery Month	Credit*	Debit†	Net Payment	Note
Preliminary Payment	June-05	$x,xxx,xxx.xx	$x,xxx,xxx.xx	$x,xxx,xxx.xx
True-Up Payment	April-05	$x,xxx,xxx.xx	$x,xxx,xxx.xx	$x,xxx,xxx.xx
Total				$x,xxx,xxx.xx

*

Surplus Energy Sales payment amount before being netted with “Debit”

^†

Surplus Energy Sales payment reduction for amount owned by DWR to SDG&E.

(iii)

Wiring or ACH Transfer Information - The fund identification information to accompany the Electronic Transfer of Funds should follow similar format to the information of the Surplus Energy Sales Payment Report.  It should appear on the wire or ACH transmittal as follows.

<Utility Name> <DWR Account Reference> Surplus Energy Sales <Payment Date yyyymmdd>

Example: SDG&E 8021360006 DWR Surplus Energy Sales 20050720

The electronic transfer of funds for Surplus Energy Sales payment shall be completed by 12:00 noon, Pacific Prevailing Time.

B.

Preliminary Surplus Energy Sales Calculation Summary Report

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility name> - Preliminary SS Calculation Summary yyyymm v#.xls

Example: SDG&E – Preliminary SS Calculation Summary 200507 v1.xls

·

The subject line of e-mail: <utility name> - Preliminary Surplus Energy Sales Calculation Summary Report for yyyymm

Example: SDG&E - Preliminary Surplus Energy Sales Calculation Summary Report for 200507

Modifications to a submitted report should be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

(ii)

Required Information and Timeline - The Preliminary Surplus Energy Sales Calculation Summary Report is to be submitted to DWR by the Monthly Settlement Date of the delivery month.  The report should be consistent in form and substance to the example screenshot below.

Example:

C.

Final Surplus Energy Sales Calculation Summary Report

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility name> - Final SS Calculation Summary yyyymm v#.xls

Example: SDG&E – Final SS Calculation Summary 200507 v1.xls

·

The subject line of e-mail: <utility name> - Final Surplus Energy Sales Calculation Summary Report for yyyymm

Example: SDG&E - Final Surplus Energy Sales Calculation Summary Report for 200507

Modifications to a submitted report should be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

ii)

Required Information and Timeline - The Final Surplus Energy Sales Calculation Summary Report is to be submitted to DWR monthly by the Final Monthly Settlement Date of the delivery month.  The report should be consistent in form and substance to the example screenshot below.

Example:

D.

Real Time Surplus Energy Sales Calculation Supporting Workbook

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility name> - RT SS Calculation Supporting Workbook yyyymm v#.xls

Example: SDG&E – RT SS Calculation Supporting Workbook 200507 v1.xls

·

The subject line of e-mail: <utility name> - RT SS Calculation Supporting Workbook for yyyymm

Example: SDG&E - RT SS Calculation Supporting Workbook for 200507

Modifications to a submitted report should be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

(ii)

Required Information and Timeline - The Real Time Surplus Energy Sales Calculation Supporting Workbook is to be submitted to DWR by Final Monthly Settlement Date of the delivery month.  The report should be consistent in form and substance to the example screenshot below.  The 25^th hour in the example below is intended for the Pacific Daylight Saving Time to Pacific Standard Time switching date in the fall and should be left blank on any other day.

C-

Example:

C-

C-

E.

Real Time Surplus Energy Sales Calculation Resource Location ID Master List

(i)

Naming Convention - The transmittal of this report should use the following naming convention.

·

The format of the filename: <utility name> - RT SS Location IDs v#.xls

Example: SDG&E – RT SS Location IDs  v1.xls

·

The subject line of e-mail: <utility name> - RT SS Location IDs Version #

Example: SDG&E - RT SS Location IDs Version 1

Updates to a submitted list should be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

(ii)

Required Information and Timeline - The Real Time Surplus Energy Sales Calculation Resource Location ID Master List is to be submitted to DWR initially by the 7^th calendar day after the Effective Date of this Operating Order and with any change to the list subsequently.  The list is to be provided consistent in form and substance to the example screenshot below.

Example:

C-

Section 3.

Additional Reports - On and after the MRTU Effective Date

The reports described in this Section 3 may be submitted as a single document or as individual documents within a workbook, so long as available reports are prepared and submitted to DWR within the timeline described below.  For any report not ready for submission within the timeline described below, the Utility will notify DWR as to the date on which such report is reasonably expected to be available.

A.

IST Report

The IST Report is to be submitted to DWR within 5 Utility Business Days after the end of each calendar month during the Term.  

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “IOU_Remit@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - IST Report yyyymm v#.xls

Example: SDG&E - IST Report 200904 v1.xls

·

The subject line of e-mail: <utility name> - IST Report for yyyymm

Example: SDG&E - IST Report for 200904

If significant modifications are required to a submitted report then this will be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

Example:  SDG&E - IST Report 200904 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the Inter-SC Trade amounts of DWR Contracts with a separate entry for each hour of the date and for each Contract in the IST Reports.  SDG&E shall report the data columns specified in the following table for each Inter-SC Trade Amounts.  The report should be consistent in form and substance to the following table in Excel format.  

C-

Example:

Market (DA/RT)	DATE	HR	Product Type	Selling SC	Buying SC	Trading Location	Submitted Qty.	Adjusted Qty.	Counter Qty.
xx	xx/xx/xxxx	1	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	2	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	3	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	4	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	5	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	6	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	7	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	8	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	9	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	10	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	11	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	12	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	13	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	14	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	15	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	16	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	17	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	18	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	19	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	20	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	21	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	22	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	23	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	24	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx
xx	xx/xx/xxxx	25	xxxxx	xxxxx	xxxx	xxxx	xx.xx	xx.xx	xx.xx

C-

Trade Name	Trade Type	Depend on Trade	Submit SC	Trade Status	Submitted
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx
xxxxxxxxxx	xxxxx		xxxx	xxxxxxx	xxxxx

C-

Market Status	Physical/APN ISTs	CPTs	IST Quantities NOT considered for Remittance	IST Quantities for Remittance Basis	Comments
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx
xxxxx	xxxxx	xxxxx		xxxxx

B.

SDG&E IST True-up Report

The IST True-up Report is to be submitted to DWR within 5 Utility Business Days after the end of each calendar month during the Term.  This report is to be submitted for minor amount of corrections to previously submitted IST Reports.

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “IOU_Remit@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - IST True-up Report yyyymm v#.xls

Example: SDG&E - IST True-up Report 200904 v1.xls

·

The subject line of e-mail: <utility name> - IST Report for yyyymm

Example: SDG&E - IST True-up Report for 200904

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the report with the subsequent version number.

Example:  SDG&E - IST True-up Report 200904 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the Inter-SC Trade amounts of DWR Contracts with a separate entry for each hour of the date and for each Contract in the IST Reports where a correction is required.  SDG&E shall report the data columns specified in the following table for each Inter-SC Trade Amounts.  The report should be consistent in form and substance to the following table in Excel format.  

Example:

Date	Hour	Contract	Original Amount (Remittance Basis Report)	Revised Amount (Remittance Basis Report)	Correction Remittance Basis Report (E  - D)
A	B	C	D	E	F
mm/dd/yyyy	xx	xxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx

Original IST Report	Revised IST Report	Correction to IST Report (I = H-G)	Comments
G	H	I	J
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx

C-

C.

DWR Remittance Basis Calculation Report

The DWR Remittance Basis Calculation Report is to be submitted to DWR within 15 Utility Business Days after the end of each calendar month during the Term.  

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “IOU_Remit@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - DWR Remittance Basis Calculation Report yyyymm v#.xls

Example: SDG&E - DWR Remittance Basis Calculation Report 200904 v1.xls

·

The subject line of e-mail: <utility name> - DWR Remittance Basis Calculation Report for yyyymm

Example: SDG&E - DWR Remittance Basis Calculation Report for 200904

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the monthly report with the subsequent version number.

Example:  SDG&E - DWR Remittance Basis Calculation Report 200904 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the daily Remittance Basis and Estimated Bundled Customer Load amounts for Bundled Customers in the DWR Remittance Basis Calculation Reports.  SDG&E shall report the data columns specified in the following table for the hourly quantities of each DWR Contract, the Estimated Bundled Customer Load and the DWR Percentage Calculation.  The report should be consistent in form and substance to the following table in Excel format.

C-

Example:

DWR Remittance Basis Calculation Report
Date
		Col 1	Col 2	Col 3	Col 4	Col 5	Col 6	Col 7	Col 8	Col 9
			Bear - Energy		CalPeak - Generation			Shell - Wind		Sunrise OMAR Data
Hour Ending		Estimated Load	Bear B	Bear C	Border	Enterprise	El Cajon	Whitewater Hill	Whitewater Cabazon	SUNRIS2PL1X3 Generation
1		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
2		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
3		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
4		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
5		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
6		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
7		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
8		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
9		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
10		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
11		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
12		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
13		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
14		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
15		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
16		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
17		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
18		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
19		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
20		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
21		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
22		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
23		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
24		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
		xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
Source:
Column 1		Represents Estimated Meter Load based on Actual EMS Data
Column 2		From SIBR represents Bear B DA ISTs
Column 3		From SIBR represents Bear C DA ISTs
Column 4		From SIBR represents CalPeak (Border) RTM ISTs*
Column 5		From SIBR represents CalPeak (Enterprise) RTM ISTs*
Column 6		From SIBR represents CalPeak (El Cajon) RTM ISTs*
Column 7		From SIBR represents (WIND) Whitewater Hill RTM ISTs
Column 8		From SIBR represents (WIND) Whitewater Cabazon RTM ISTs
Column 9		Data represents Sunrise Generation (SUNRIS2PL1X3) as shown in OMAR System - Channel 4
Column 10		Total Sum of Columns (2 thru 9)
Column 11		True-up Adjustment for Previous Period Corrections
Column 12		Total With Adjustments (10 and 11)
Column 13		Total percentage for DWR  - (Column 12 divided by Column 1)
Column 14		Total percentage SDGE - (1 - Column 13)
Note:
	*  Upon appointment of SDG&E as the Scheduling Coordinator for the CalPeak (Border), CalPeak (Enterprise) and CalPeak (El Cajon) Contracts, the data for these Contracts will represent the amount of Generation for each Contract as shown in OMAR System rather than the quantities described above.

Col 10	Col 11	Col 12	Col 13	Col 14
Total	True-up	Total	%	%	Comment for adjustment
Energy, Wind & Generation	Adjustment from Previous Period	With Adjustment	DWR	SDGE
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx

C-

D.

DWR Remittance Basis True-up Report

The DWR Remittance Basis True-up Report is to be submitted to DWR within 15 Utility Business Days after the end of each calendar month during the Term.  

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “IOU_Remit@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - DWR Remittance Basis True-up Report yyyymm v#.xls

Example: SDG&E - DWR Remittance BasisTrue-up Report 200904 v1.xls

·

The subject line of e-mail: <utility name> - DWR Remittance Basis True-up Report for yyyymm

Example: SDG&E - DWR Remittance Basis True-up Report for 200904

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the monthly report with the subsequent version number.

Example:  SDG&E - DWR Remittance Basis True-up Report 200904 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the hourly corrections of energy from DWR Contracts amounts used to calculate DWR Percentage and Day and Hour when the correction was made to DWR percentage.  SDG&E shall report the data columns specified in the following table for the hourly quantities of the original amount of DWR Contract, the revised amount quantity of DWR Contract, the correction required, the day and hour the correction is made and the reason for the  correction. Corrections are not to be made such that they will cause the hourly DWR percentage to become negative. The report should be consistent in form and substance to the following table in Excel format.

C-

Example:

Date	Hour	Contract	Original Amount (Remittance Basis Report)	Revised Amount (Remittance Basis Report)	Correction Remittance Basis Report (E  - D)
A	B	C	D	E	F
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx
mm/dd/yyyy	xx	xxxxxxxx	xxx,xxx.xx	xxx,xxx.xx	xxx,xxx.xx

C-

Date of Adjustment	Hour of Adjustment	Comments
G	H	I
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx
mm/dd/yyyy	xx

C-

E.

EBCL Deviation Report

The EBCL Deviation Report is to be submitted to DWR within 5 Utility Business Days after the end of each calendar month during the Term.  

(i)

Delivery Mechanism and Naming Convention - This report should be sent by e-mail to the e-mail address “IOU_Remit@water.ca.gov” (or by such secure electronic means as reasonably determined appropriate by SDG&E) with the following filename and subject line:

·

The format of the filename: <utility name> - EBCL Deviation Report yyyymm v#.xls

Example: SDG&E - EBCL Deviation Report 200904 v1.xls

·

The subject line of e-mail: <utility name> - EBCL Deviation Report for yyyymm

Example: SDG&E - EBCL Deviation Report for 200904

Modifications to a submitted report will be accomplished by resending all the data including the necessary modifications and renaming the monthly report with the subsequent version number.

Example:  SDG&E - EBCL Deviation Report 200904 v2.xls

(ii)

Required Information and Timeline - SDG&E shall report the monthly Estimated Bundled Customer Load and the final ISO submitted Bundled Customer Load information in the EBCL Deviation Reports.  SDG&E shall report the data columns specified in the following table for the monthly quantities of the Estimated Bundled Customer Load, the Final ISO Submitted Bundled Customer Load, and the deviation percentage as further described below.  The report should be consistent in form and substance to the following table in Excel format.

C-

Example:

SDG&E
Monthly Load Deviation
Final - yyyy
Month	Estimated Bundled Customer Load	Final CAISO Submitted Bundled Customer Load	Final Deviation
	MWh	MWh	%
	A	B	C=ABS((B-A)/B)
December yyyy-1	xxx,xxx	xxx,xxx	xx.xx
January	xxx,xxx	xxx,xxx	xx.xx
February	xxx,xxx	xxx,xxx	xx.xx
March	xxx,xxx	xxx,xxx	xx.xx
April	xxx,xxx	xxx,xxx	xx.xx
May	xxx,xxx	xxx,xxx	xx.xx
June	xxx,xxx	xxx,xxx	xx.xx
July	xxx,xxx	xxx,xxx	xx.xx
August	xxx,xxx	xxx,xxx	xx.xx
September	xxx,xxx	xxx,xxx	xx.xx
October	xxx,xxx	xxx,xxx	xx.xx
November	xxx,xxx	xxx,xxx	xx.xx
December	xxx,xxx	xxx,xxx	xx.xx

C-

ATTACHMENT D

[Reserved]

D-

ATTACHMENT E

SAN DIEGO GAS & ELECTRIC COMPANY

ADDITIONAL PROVISIONS

1.

The Restated Letter Agreement between San Diego Gas & Electric Company (SDG&E) and the California Department of Water Resources (DWR), dated June 18, 2001, as it may be amended or modified from time to time (the “Restated Letter Agreement”). The Restated Letter Agreement provides for continued DWR procurement for SDG&E customers of SDG&E’s “full net short” (consisting of substantially all of the power and ancillary services not provided by SDG&E’s retained generation) through December 31, 2002. The reference to the Restated Letter Agreement in this Attachment E provides no independent basis for enforcement of the Restated Letter Agreement.

2.

Memorandum of Understanding (MOU) with the California Department of Water Resources (DWR), dated June 18, 2001, San Diego Gas & Electric Company (SDG&E) and its parent Company, Sempra Energy. The MOU contemplates the implementation of a series transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. The MOU contemplates, among other matters, the sale of SDG&E’s transmission system to DWR or another state agency. The MOU also contemplates that DWR’s net-short procurement obligations contained in the Restated Letter Agreement are subject to earlier termination upon the satisfaction of regulatory and other conditions intended to assure SDG&E’s timely recovery of costs incurred in resuming power procurement for its customers. The reference to the MOU in this Attachment E provides no independent basis for enforcement of the MOU.

3.

Letter Agreement between the California Department of Water Resources (DWR) and San Diego Gas & Electric Company (SDG&E). This Letter Agreement provides for the payment of SDG&E’s costs to (i) implement and maintain a billing system to remit customer payments to DWR, (ii) implement the 20/20 program, and (iii) implement load curtailment programs under Assembly Bill (AB) IX, related Executive Orders, and California Public Utilities Commission (CPUC) orders and decisions.

4.

Notwithstanding (i) the terms, execution or operation of the Servicing Order, (ii) the approval of, any modification to, or any other action taken with respect to or having an effect on the Servicing Order by the Commission or any other Governmental Authority, or (iii) any other action taken by a Governmental Authority, Utility hereby reserves all rights (if any) in any forum to contest, oppose, appeal, comment on, or otherwise seek to revisit, alter, modify or set aside any present or future decisions, orders, opinions, rulings, or actions or omissions to act by the Commission or any other Governmental Authority, whether in draft, interim or final form, arising out of, relating to, or connected with (x) the calculation of DWR Charges or DWR Revenues and the allocation of costs and amounts of electric capacity and output among the customers of electrical corporations, (y) the interpretation and/or legality of Applicable Law or Applicable Orders, or (z) remittance of such calculated amounts by Utility to DWR or its Assign(s) under Applicable Law or Applicable Commission Orders in a manner inconsistent with this Servicing Order or Utility’s ability to perform its utility functions.

E-

ATTACHMENT F

SAN DIEGO GAS & ELECTRIC COMPANY

CALCULATION METHODOLOGY FOR REDUCED REMITTANCES

PURSUANT TO 20/20 PROGRAM

A.

Reimbursement of 20/20 Rebate Costs

1.

DWR agrees that Utility shall recover the amount of customer credits under the 20/20 Program as follows:

a.

Under the remittance provision of Attachment B of this Servicing Order, Utility shall reduce any remittances to DWR under the Act or the California Public Utilities Commission (CPUC) Resolution E-3770 by the daily amount equal to the total of such customer credits on the following Business Day after the presentation of credits on customer bill.

b.

If the amount that Utility is entitled to offset on any day exceeds the funds otherwise due to DWR, the balance will be carried over to the next day. If it appears that the amount Utility is entitled to offset will exceed the funds due to DWR for more than 3 consecutive days, then Utility will invoice DWR with an estimate of the amount due to Utility. DWR will pay such invoice within 1 Business Day of receipt. For purposes of this Attachment F, the credits or payments shall refer to the 20 percent reduction applied to customers’ total net electric charges (including applicable rate surcharges), and shall include credits or payments made to resolve Customer disputes or reflect corrected bills following the end of the program.

B.

Customer credits under the 20/20 Program will be applied to Customer accounts as follows:

Customer credits under the 20/20/ Program will be applied to customer accounts at time of billing and allocated to DWR according to the same payment posting priority set forth in Attachment B, Section G. In those instances in which the credit exceeds the outstanding charges, the excess credit will remain on the account and be applied to future charges in the same manner.

C.

Reimbursement of 20/20 Program Implementation Costs

DWR agrees to pay to Utility an implementation fee and recurring fees in order to cover Utility’s reasonable development and on-going costs for the procedures, systems and mechanisms that are necessary to implement and support the 20/20 Program. Utility shall invoice DWR for payment of the implementation fee and recurring fees with reasonable supporting documentation in accordance with Section 7.2 of the Servicing Order.  Final invoice to be submitted to DWR no later than February 28, 2003.

D.

Estimated Costs:

l.

The intent is to reimburse the actual, incremental costs incurred by SDG&E. SDG&E will exercise reasonable commercial efforts in managing their operations to minimize costs and keep within the budgeted costs shown in the table below.

2.

SDG&E shall invoice DWR after a 20/20 Program implementation activity described below has been completed and will undertake reasonable commercial efforts to track and keep costs within the estimated costs shown in this Attachment F.

3.

SDG&E will invoice DWR based on actual costs and provide DWR with an invoice itemizing and documenting such costs.

4.

With the exception of Customer Service Representative calls, SDG&E is unable to track, itemize and document costs for Customer Bill Inquiries without undertaking extensive system programming and hardware upgrades. Specifically, these types of inquiries include field calls, meter re-reads, re-bills and meter tests. Based on 2001 20/20 Program activity levels, SDG&E does not anticipate any incremental increase in costs for these activities. Accordingly, SDG&E has not included cost estimates for these types of Customer Bill Inquiries in the table below. However, DWR agrees that if SDG&E should experience a significant increase in activity levels for the types of customer bill inquiries described above, SDG&E will notify DWR and provide to DWR documentation reasonably necessary to establish such activity levels. SDG&E and DWR shall negotiate a mutually acceptable adjustment based on an estimate of reasonable costs for the applicable increased Customer Bill Inquiries.

Estimated DWR / 20/20 Rebate Program Budgeted Costs
			2002
	Expense Items	Quantity or Unit          Costs
1	Systems Programming	One Time Fee	$16,100 - $18,500
2	Customer Communications (FAQ Sheets, Bill  Inserts, Mailing Costs & Other Communications)	One Time Fee	$484,750 - $686,300
3	Additional Postage for Bill Insert	One Time Fee	$280,000 - $300,000
4	Customer Service Representative Calls &  Training	Ongoing	$35,600 - $47,750
5	Advertising Campaign	Ongoing	See Footnote below.
6	Total Estimated Admin. Costs	Ongoing	$816,450 - $1,052,550 (does not include advertising costs)

___________________

Footnote: SDG&E will receive a percentage of the presently estimated $3 million cost to
implement a statewide advertising campaign which is contemplated by the CPUC and the Governor. This cost will be proportionately allocated among the three utilities.

E.

20/20 Program Reporting

1.

Daily - To the extent reasonably possible, each Business Day SDG&E shall provide DWR with a report showing the aggregated dollar amount and number of 20/20 Program credits applied to Customer accounts.

2.

Monthly - To the extent reasonably possible, SDG&E shall provide DWR with monthly reports showing the monthly total number of customer accounts by rate schedule and the corresponding 20/20 Program credit amount and energy use statistics as identified in the sample monthly report below. Monthly reports will be completed within 10 Business Days after the first of each month.

3.

Program Summary - To the extent that SDG&E completes any additional analysis of the results of the 20/20 Program, SDG&E will provide to DWR such analysis. Any additional findings, including “lessons learned” and recommendations for future similar programs, will also be provided to DWR.

F-

ATTACHMENT G

SAN DIEGO GAS & ELECTRIC COMPANY

FEE SCHEDULE

A.

DWR Billing Agent Cost Estimates:

The following chart provides an estimate of SDG&E’s implementation and administrative costs (“Billing Service Implementation Costs”) associated with providing Billing Services to DWR pursuant to the Servicing Order.

1.

SDG&E shall invoice DWR in accordance with Section 7.2 of the Servicing Order after a Billing Service activity has been completed and will exercise commercially reasonable efforts to track and keep costs within the estimated Billing Service Implementation Costs shown in this Attachment G.

2.

For the majority of SDG&E’s Billing Service Implementation Costs, SDG&E will invoice DWR based on actual costs and provide DWR with an invoice itemizing and documenting such costs.

3.

In certain circumstances SDG&E is unable to track, itemize and document Billing Services Implementation Costs without undertaking extensive system programming and hardware upgrades. Accordingly, DWR agrees that in these circumstances SDG&E shall utilize the SDG&E Estimated Billing Service Implementation Costs shown in this Attachment G for SDG&E’s invoicing purposes without undertaking a true-up to actual costs. However, DWR reserves the right to dispute all or any portion of such invoice in which event Section 7.1 shall govern the resolution of any such dispute. Provided, however, DWR and SDG&E shall undertake in good faith efforts to resolve any dispute prior to resorting to such dispute resolution process.

B.

Billing Service Implementation Costs

Additional Charges reflect SDG&E’s estimated costs for Billing Services, which the Parties agree may be used when SDG&E would incur increased costs as a result of performing DWR Billing Services pursuant to the Servicing Order. The items listed are intended to facilitate contract management and are not intended to reflect an exhaustive and inclusive list of Additional Charges that may arise.

Description	Set-Up Cost Estimate	Additional Charges	Comments
Energy Data Management	$32,000
DWR Remittance &   Reporting
Customer Billing/Payment    Processing	300,000
Training	12,000
Fact Sheet	11,000
Bill Insert	5,500		Shared cost due to multiple communication - DWR @ 20%
Brochure Revision	2,500		Shared cost due to multiple communication - DWR @ 20%
Website Changes	3,500
Direct Mail		$700,000	Each mailing to all customers
DWR Revenue Req. Ntc	500,000		May/June direct mailing to large & small customers
Bill Insert		26,500	One bill insert to all customers
Customer Contacts		6.25	Per contact
Customer Contract Training		40.00	Per hour per employee
Rebilling - Load Profile		3.00	Per month, per meter
Rebilling - IDR Metering		49.00	Per month, per meter
Increased Postage		Current Postage Rate	Per piece mailed. Postage rate consistent with rate used to mail SDG&E customer bills.
Actual Invoice Cost of   Annual Report (Section   8.4)		TBD	Cost dependent on audit requirements
Total - 2003 SO	$866,500
2006 SO Requirements
Enhanced Reporting	$10,000
Total - 2006 SO	$10,000

C.

DWR Bond Charge Implementation Cost Estimates:

The following chart provides an estimate for SDG&E’s implementation costs associated with the November 15, 2002 implementation of the DWR Bond Charge. SDG&E will provide DWR with additional estimates in the future for the implementation costs associated with the second phase of DWR Bond Charge implementation for issues such as Direct Access and Departed Load Customers.

D.

Reimbursement of DWR Bond Charge Costs:

1. DWR will pay SDG&E an implementation fee and recurring fees in order to cover SDG&E’s reasonable development and on-going costs for the procedures, systems and mechanisms that are necessary to implement the DWR Bond Charge on November 15, 2002. SDG&E shall invoice DWR for payment of the implementation fee and recurring fees with reasonable supporting documentation in accordance with Section 7.2 of the Servicing Order.

2. The intent is to reimburse the actual, incremental costs incurred by SDG&E. SDG&E will exercise reasonable commercial efforts in managing their operations to minimize costs and keep within the budgeted costs shown in the table below.

3. SDG&E shall invoice DWR after a DWR Bond Charge implementation activity described below has been completed and will undertake reasonable commercial efforts to track and keep costs within the estimated costs shown in Section C of this Attachment G.

4. SDG&E will invoice DWR based on actual costs and provide DWR with an invoice itemizing and documenting such costs.

5. SDG&E is unable to track, itemize and document costs for Customer Bill Inquiries related to the DWR Bond Charge without undertaking extensive system programming and hardware upgrades. At this time, SDG&E does not anticipate any incremental increase in costs for these activities. Accordingly, SDG&E has not included cost estimates for Customer Bill Inquiries in the table below. However, DWR agrees that if SDG&E should experience a significant increase in customer bill inquiries associated with the DWR Bond Charge, SDG&E will notify DWR and provide to DWR documentation reasonably necessary to establish such activity levels. SDG&E and DWR shall negotiate a mutually acceptable adjustment based on an estimate of reasonable costs for the applicable increased Customer Bill Inquiries.

DWR Bond Charge Implementation Costs:

Item Number	Expense Items	Quantity or Unit Costs	2002
1	Systems Programming	One Time Fee	$110,000
2	Additional Postage for Bill Messages	One-Time	$  20,000
4	Customer Service Representative Training	One-Time	$  10,000
	Total Estimated Admin Costs		$140,000

E.

Summary of Estimated Costs from the 2003 Servicing Order and Actual Payments to SDG&E for Billing Services:

Charges	2001	2002	2003	2004	2005
Initial Set-up	$866,500	$132,000	$132,000	$132,000	$132,000
Bond Charge Set-up	--	140,000	--	--	--
$1 Billion Refund Set-up	--	--	168,000	--	--
LPP System Correction	--	--	--	--	500,000
Total Estimated Amount	$866,500	$272,000	$300,000	$132,000	$632,000
Total Actual Payment	$732,003	$0	$77,200	$69,545	$578,348

G-

ATTACHMENT H

[Provisions of Attachment H have been incorporated in
Appendix A-2 of Attachment B of the Servicing Order.]

H-

EX-12

Converted by EDGARwiz

EX-12

EXHIBIT 12.2
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							March 31,
		2006	2007	2008	2009	2010	2011
Fixed Charges and Preferred Stock Dividends:
Interest		$ 102	$ 105	$ 107	$ 118	$ 153	$ 43
Interest portion of annual rentals		3	3	1	1	1	-
Total fixed charges		105	108	108	119	154	43
Preferred stock dividends (1)		8	7	7	7	7	2
Combined fixed charges and preferred stock dividends for purpose of ratio		$ 113	$ 115	$ 115	$ 126	$ 161	$ 45
Earnings:
Pretax income from continuing operations		$ 394	$ 406	$ 451	$ 550	$ 531	$ 143
Total fixed charges (from above)		105	108	108	119	154	43
Less: Interest capitalized		1	3	13	4	1	-
Total earnings for purpose of ratio		$ 498	$ 511	$ 546	$ 665	$ 684	$ 186
Ratio of earnings to combined fixed charges and preferred stock dividends		4.41	4.44	4.75	5.28	4.25	4.13
Ratio of earnings to fixed charges		4.74	4.73	5.06	5.59	4.44	4.33
(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-12

EXHIBIT 12.3
PACIFIC ENTERPRISES
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							March 31,
		2006	2007	2008	2009	2010	2011
Fixed Charges:
Interest		$ 78	$ 78	$ 68	$ 75	$ 72	$ 19
Interest portion of annual rentals		4	3	2	1	2	-
Preferred dividends of subsidiary (1)		2	2	2	2	2	-
Total fixed charges		84	83	72	78	76	19
Preferred stock dividends (1)		6	6	6	6	6	1
Combined fixed charges and preferred stock dividends for purpose of ratio		$ 90	$ 89	$ 78	$ 84	$ 82	$ 20
Earnings:
Pretax income from continuing operations		$ 426	$ 408	$ 394	$ 415	$ 465	$ 105
Total fixed charges (from above)		84	83	72	78	76	19
Less: Interest capitalized		1	1	-	1	1	-
Less: Preferred dividends of subsidiary (1)		1	1	1	2	1	-
Total earnings for purpose of ratio		$ 508	$ 489	$ 465	$ 490	$ 539	$ 124
Ratio of earnings to combined fixed charges and preferred stock dividends		5.64	5.49	5.96	5.83	6.57	6.20
Ratio of earnings to fixed charges		6.05	5.89	6.46	6.28	7.09	6.53
(1)	In computing this ratio, “Preferred dividends of subsidiary” and "Preferred stock dividends" represent the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-12

EXHIBIT 12.4
SOUTHERN CALIFORNIA GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							March 31,
		2006	2007	2008	2009	2010	2011
Fixed Charges:
Interest		$ 72	$ 72	$ 65	$ 74	$ 72	$ 19
Interest portion of annual rentals		4	3	2	1	2	-
Total fixed charges		76	75	67	75	74	19
Preferred stock dividends (1)		2	2	2	2	2	-
Combined fixed charges and preferred stock dividends for purpose of ratio		$ 78	$ 77	$ 69	$ 77	$ 76	$ 19
Earnings:
Pretax income from continuing operations		$ 397	$ 391	$ 385	$ 418	$ 463	$ 105
Add: Total fixed charges (from above)		76	75	67	75	74	19
Less: Interest capitalized		1	1	-	1	1	-
Total earnings for purpose of ratio		$ 472	$ 465	$ 452	$ 492	$ 536	$ 124
Ratio of earnings to combined fixed charges and preferred stock dividends		6.05	6.04	6.55	6.39	7.05	6.53
Ratio of earnings to fixed charges		6.21	6.20	6.75	6.56	7.24	6.53
(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-31

EXHIBIT 31.1

CERTIFICATION

I, Donald E. Felsinger, certify that:

1.

I have reviewed this report on Form 10-Q of Sempra Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Donald E. Felsinger

Donald E. Felsinger

Chief Executive Officer

EX-31

EXHIBIT 31.2

CERTIFICATION

I, Mark A. Snell, certify that:

1.

I have reviewed this report on Form 10-Q of Sempra Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Mark A. Snell

Mark A. Snell

Chief Financial Officer

EX-31

EXHIBIT 31.3

CERTIFICATION

I, Jessie J. Knight, Jr., certify that:

1.

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

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer

EX-31

EXHIBIT 31.4

CERTIFICATION

I, Robert M. Schlax, certify that:

1.

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

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-31

EXHIBIT 31.5

CERTIFICATION

I, Michael W. Allman, certify that:

1.

I have reviewed this report on Form 10-Q of Pacific Enterprises;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Michael W. Allman

Michael W. Allman

Chief Executive Officer

EX-31

EXHIBIT 31.6

CERTIFICATION

I, Robert M. Schlax, certify that:

1.

I have reviewed this report on Form 10-Q of Pacific Enterprises;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-31

EXHIBIT 31.7

CERTIFICATION

I, Michael W. Allman, certify that:

1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Michael W. Allman

Michael W. Allman

Chief Executive Officer

EX-31

EXHIBIT 31.8

CERTIFICATION

I, Robert M. Schlax, certify that:

1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-32

Exhibit 32.1

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Donald E. Felsinger

Donald E. Felsinger

Chief Executive Officer

EX-32

Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Mark A. Snell

Mark A. Snell

Chief Financial Officer

EX-32

Exhibit 32.3

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer

EX-32

Exhibit 32.4

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-32

Exhibit 32.5

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Pacific Enterprises (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Michael W. Allman

Michael W. Allman

Chief Executive Officer

EX-32

Exhibit 32.6

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Pacific Enterprises (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-32

Exhibit 32.7

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Michael W. Allman

Michael W. Allman

Chief Executive Officer

EX-32

Exhibit 32.8

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended March 31, 2011 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 9, 2011

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer