PCG 10-Q Quarterly Report March 31, 2010

PG&E CORP

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10-Q 1 q1form10q.htm FORM 10-Q q1form10q.htm


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, 2010 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 Number _______________		Exact Name of Registrant as specified in its charter _______________				State or other Jurisdiction of Incorporation ______________			IRS Employer Identification Number ___________

1-12609		PG&E Corporation				California			94-3234914
1-2348		Pacific Gas and Electric Company				California			94-0742640

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ________________________________________						PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105 ______________________________________
Address of principal executive offices, including zip code

Pacific Gas and Electric Company (415) 973-7000 ________________________________________						PG&E Corporation (415) 267-7000 ______________________________________
Registrant's telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. [X] Yes [ ] 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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation				[X] Yes [ ] No

Pacific Gas and Electric 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 definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PG&E Corporation:			[X] Large accelerated filer					[ ] Accelerated Filer
			[ ] Non-accelerated filer				[ ] Smaller reporting company
Pacific Gas and Electric Company:			[ ] Large accelerated filer					[ ] Accelerated Filer
			[X] Non-accelerated filer				[ ] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:					[ ] Yes [X] No

Pacific Gas and Electric Company:					[ ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock Outstanding as of April 30, 2010:

PG&E Corporation						372,345,954
Pacific Gas and Electric Company						264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1 .	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	13
	NOTE 2:		New and Significant Accounting Policies	13
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	15
	NOTE 4:		Debt	18
	NOTE 5:		Equity	19
	NOTE 6:		Earnings Per Share	20
	NOTE 7:		Derivatives and Hedging Activities	22
	NOTE 8:		Fair Value Measurements	26
	NOTE 9:		Related Party Agreements and Transactions	32
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	32
	NOTE 11:		Commitments and Contingencies	33

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			39
	Cautionary Language Regarding Forward-Looking Statements			41
	Results of Operations			42
	Liquidity and Financial Resources			47
	Contractual Commitments			51
	Capital Expenditures			51
	Off-Balance Sheet Arrangements			52
	Contingencies			52
	Regulatory Matters			52
	Environmental Matters			53
	Other Matters			55
	Risk Management Activities			56
	Critical Accounting Policies			58

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			58
ITEM 4.	CONTROLS AND PROCEDURES			58

PART II.	OTHER INFORMATION

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			59
ITEM 5.	OTHER INFORMATION			59
ITEM 6.	EXHIBITS			60

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended
	March 31,
(in millions, except per share amounts)	2010			2009
Operating Revenues
Electric	$	2,510		$	2,426
Natural gas		965			1,005
Total operating revenues		3,475			3,431
Operating Expenses
Cost of electricity		920			883
Cost of natural gas		495			557
Operating and maintenance		991			1,059
Depreciation, amortization, and decommissioning		451			419
Total operating expenses		2,857			2,918
Operating Income		618			513
Interest income		2			9
Interest expense		(168	)		(181	)
Other (expense) income, net		(6	)		18
Income Before Income Taxes		446			359
Income tax provision		185			115
Net Income		261			244
Preferred dividend requirement of subsidiary		3			3
Income Available for Common Shareholders	$	258		$	241
Weighted Average Common Shares Outstanding, Basic		371			364
Weighted Average Common Shares Outstanding, Diluted		389			366
Net Earnings Per Common Share, Basic	$	0.69		$	0.65
Net Earnings Per Common Share, Diluted	$	0.67		$	0.65
Dividends Declared Per Common Share	$	0.46		$	0.42

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions)	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	258		$	527
Restricted cash		629			633
Accounts receivable:
Customers (net of allowance for doubtful accounts of $69 million in 2010 and $68 million in 2009)		1,528			1,609
Accrued unbilled revenue		638			671
Regulatory balancing accounts		1,468			1,109
Inventories:
Gas stored underground and fuel oil		59			114
Materials and supplies		196			200
Income taxes receivable		112			127
Prepaid expenses and other		733			667
Total current assets		5,621			5,657
Property, Plant, and Equipment
Electric		30,918			30,481
Gas		10,823			10,697
Construction work in progress		1,993			1,888
Other		14			14
Total property, plant, and equipment		43,748			43,080
Accumulated depreciation		(14,371	)		(14,188	)
Net property, plant, and equipment		29,377			28,892
Other Noncurrent Assets
Regulatory assets		5,602			5,522
Nuclear decommissioning funds		1,929			1,899
Income taxes receivable		596			596
Other		415			379
Total other noncurrent assets		8,542			8,396
TOTAL ASSETS	$	43,540		$	42,945

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2010			2009
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,251		$	833
Long-term debt, classified as current		842			342
Energy recovery bonds, classified as current		390			386
Accounts payable:
Trade creditors		882			984
Disputed claims and customer refunds		772			773
Regulatory balancing accounts		312			281
Other		481			349
Interest payable		795			818
Income taxes payable		268			214
Deferred income taxes		506			332
Other		1,281			1,501
Total current liabilities		7,780			6,813
Noncurrent Liabilities
Long-term debt		9,882			10,381
Energy recovery bonds		730			827
Regulatory liabilities		4,190			4,125
Pension and other postretirement benefits		1,968			1,773
Asset retirement obligations		1,603			1,593
Deferred income taxes		4,656			4,732
Other		2,110			2,116
Total noncurrent liabilities		25,139			25,547
Commitments and Contingencies
Equity
Shareholders’ Equity
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		-			-
Common stock, no par value, authorized 800,000,000 shares, issued 371,222,918 common and 480,848 restricted shares in 2010 and issued 370,601,905 common and 670,552 restricted shares in 2009		6,307			6,280
Reinvested earnings		4,302			4,213
Accumulated other comprehensive loss		(240	)		(160	)
Total shareholders’ equity		10,369			10,333
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		10,621			10,585
TOTAL LIABILITIES AND EQUITY	$	43,540		$	42,945

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2010			2009
Cash Flows from Operating Activities
Net income	$	261		$	244
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		506			463
Allowance for equity funds used during construction		(28	)		(25	)
Deferred income taxes and tax credits, net		137			235
Other changes in noncurrent assets and liabilities		(113	)		(51	)
Effect of changes in operating assets and liabilities:
Accounts receivable		114			301
Inventories		59			166
Accounts payable		87			(116	)
Income taxes receivable/payable		69			209
Regulatory balancing accounts, net		(377	)		(180	)
Other current assets		35			32
Other current liabilities		(381	)		(390	)
Other		26			2
Net cash provided by operating activities		395			890
Cash Flows from Investing Activities
Capital expenditures		(855	)		(1,079	)
Decrease in restricted cash		4			11
Proceeds from sales of nuclear decommissioning trust investments		337			387
Purchases of nuclear decommissioning trust investments		(343	)		(412	)
Other		9			7
Net cash used in investing activities		(848	)		(1,086	)
Cash Flows from Financing Activities
Borrowings under revolving credit facility		-			300
Repayments under revolving credit facility		-			(300	)
Net issuance of commercial paper, net of discount of $2 million in 2009		418			96
Proceeds from issuance of long-term debt, net of discount and issuance costs of $16 million in 2009		-			884
Long-term debt matured or repurchased		-			(600	)
Energy recovery bonds matured		(93	)		(89	)
Common stock issued		10			96
Common stock dividends paid		(157	)		(138	)
Other		6			(1	)
Net cash provided by financing activities		184			248
Net change in cash and cash equivalents		(269	)		52
Cash and cash equivalents at January 1		527			219
Cash and cash equivalents at March 31	$	258		$	271

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(193	)	$	(190	)
Income taxes, net		-			294
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	169		$	154
Capital expenditures financed through accounts payable		215			235
Noncash common stock issuances		-			33

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2010			2009
Operating Revenues
Electric	$	2,510		$	2,426
Natural gas		965			1,005
Total operating revenues		3,475			3,431
Operating Expenses
Cost of electricity		920			883
Cost of natural gas		495			557
Operating and maintenance		990			1,059
Depreciation, amortization, and decommissioning		451			419
Total operating expenses		2,856			2,918
Operating Income		619			513
Interest income		2			9
Interest expense		(156	)		(173	)
Other (expense) income, net		(6	)		21
Income Before Income Taxes		459			370
Income tax provision		195			131
Net Income		264			239
Preferred dividend requirement		3			3
Income Available for Common Stock	$	261		$	236

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions)	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	60		$	334
Restricted cash		629			633
Accounts receivable:
Customers (net of allowance for doubtful accounts of $69 million in 2010 and $68 million in 2009)		1,528			1,609
Accrued unbilled revenue		638			671
Related parties		1			1
Regulatory balancing accounts		1,468			1,109
Inventories:
Gas stored underground and fuel oil		59			114
Materials and supplies		196			200
Income taxes receivable		121			138
Prepaid expenses and other		732			662
Total current assets		5,432			5,471
Property, Plant, and Equipment
Electric		30,918			30,481
Gas		10,823			10,697
Construction work in progress		1,993			1,888
Total property, plant, and equipment		43,734			43,066
Accumulated depreciation		(14,358	)		(14,175	)
Net property, plant, and equipment		29,376			28,891
Other Noncurrent Assets
Regulatory assets		5,602			5,522
Nuclear decommissioning funds		1,929			1,899
Related parties receivable		24			25
Income taxes receivable		610			610
Other		326			291
Total other noncurrent assets		8,491			8,347
TOTAL ASSETS	$	43,299		$	42,709

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2010			2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	1,251		$	833
Long-term debt, classified as current		595			95
Energy recovery bonds, classified as current		390			386
Accounts payable:
Trade creditors		882			984
Disputed claims and customer refunds		772			773
Related parties		24			16
Regulatory balancing accounts		312			281
Other		478			347
Interest payable		779			813
Income tax payable		283			223
Deferred income taxes		511			334
Other		1,079			1,307
Total current liabilities		7,356			6,392
Noncurrent Liabilities
Long-term debt		9,534			10,033
Energy recovery bonds		730			827
Regulatory liabilities		4,190			4,125
Pension and other postretirement benefits		1,912			1,717
Asset retirement obligations		1,603			1,593
Deferred income taxes		4,686			4,764
Other		2,080			2,073
Total noncurrent liabilities		24,735			25,132
Commitments and Contingencies
Shareholders’ Equity
Preferred stock without mandatory redemption provisions:
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares		145			145
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares		113			113
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2010 and 2009		1,322			1,322
Additional paid-in capital		3,076			3,055
Reinvested earnings		6,786			6,704
Accumulated other comprehensive loss		(234	)		(154	)
Total shareholders’ equity		11,208			11,185
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	43,299		$	42,709

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2010			2009
Cash Flows from Operating Activities
Net income	$	264		$	239
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		491			456
Allowance for equity funds used during construction		(28	)		(25	)
Deferred income taxes and tax credits, net		138			234
Other changes in noncurrent assets and liabilities		(98	)		(48	)
Effect of changes in operating assets and liabilities:
Accounts receivable		114			298
Inventories		59			166
Accounts payable		94			(107	)
Income taxes receivable/payable		77			95
Regulatory balancing accounts, net		(377	)		(180	)
Other current assets		35			34
Other current liabilities		(387	)		(386	)
Other		26			1
Net cash provided by operating activities		408			777
Cash Flows from Investing Activities
Capital expenditures		(855	)		(1,079	)
Decrease in restricted cash		4			11
Proceeds from sales of nuclear decommissioning trust investments		337			387
Purchases of nuclear decommissioning trust investments		(343	)		(412	)
Other		5			2
Net cash used in investing activities		(852	)		(1,091	)
Cash Flows from Financing Activities
Borrowings under revolving credit facility		-			300
Repayments under revolving credit facility		-			(300	)
Net issuance of commercial paper, net of discount of $2 million in 2009		418			96
Proceeds from issuance of long-term debt, net of discount and issuance costs of $12 million in 2009		-			538
Long-term debt matured or repurchased		-			(600	)
Energy recovery bonds matured		(93	)		(89	)
Preferred stock dividends paid		(4	)		(3	)
Common stock dividends paid		(179	)		(156	)
Equity contribution		20			528
Other		8			2
Net cash provided by financing activities		170			316
Net change in cash and cash equivalents		(274	)		2
Cash and cash equivalents at January 1		334			52
Cash and cash equivalents at March 31	$	60		$	54

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(193	)	$	(190	)
Income taxes, net		-			163
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	215		$	235

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries, as well as, the accounts of variable interest entities (“VIEs”) for which the Utility is the primary beneficiary. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2009 in both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2009 Annual Report on Form 10-K filed on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2009 Annual Report.”

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. Any significant changes to those policies or new significant policies are described in Note 2 below.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and related notes included in the 2009 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.

The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three months ended March 31, 2010 and 2009 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2010			2009			2010			2009
Service cost for benefits earned	$	69		$	66		$	10		$	8
Interest cost		161			155			23			21
Expected return on plan assets		(156	)		(145	)		(18	)		(17	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		13			11			6			4
Amortization of unrecognized (gain) loss		11			25			1			1
Net periodic benefit cost		98			112			28			23
Less: transfer to regulatory account (1)		(58	)		(71	)		-			-
Total	$	40		$	41		$	28		$	23

(1) The Utility recorded $58 million and $71 million for the three month periods ended March 31, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three months ended March 31, 2010 and 2009.

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to pension and other postretirement benefits and a decrease to other comprehensive loss of $148 million as of February 16, 2010. The impact to net periodic benefit cost for the three months ended March 31, 2010 was not significant.

Adoption of New Accounting Pronouncements

Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2010, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-17, “Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU No. 2009-17”). ASU No. 2009-17 amends the Consolidation Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) regarding when and how to determine, or re-determine, whether an entity is a VIE, which could require consolidation. In addition, ASU No. 2009-17 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach. Furthermore, ASU No. 2009-17 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities which the companies control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on voting equity interests alone. These entities are referred to as VIEs. A VIE is an entity which does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has (1) the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and (2) the power to direct the activities that are most significant to the VIE’s economic performance. The enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is the enterprise that will consolidate the VIE.

The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement. When determining whether a controlling financial interest exists, the Utility must first assess whether it absorbs any of a VIE’s expected losses or receives portions of the expected residual returns as a result of the arrangement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. Power plants typically are exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others. The Utility analyzes the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin to determine whether the Utility absorbs variability. Factors that may be considered when assessing the impact to the VIE’s gross margin include the pricing structure of the agreement and the cost of inputs and production, depending on the technology of the power plant.

For each variable interest, the Utility evaluates the activities of the power plant that most directly impact the VIE’s economic performance. The Utility’s assessment of the activities that are economically significant to the VIE’s performance often include decision making rights associated with designing the VIE, operating and maintenance activities, and re-marketing activities of the power plant after the end of its power purchase agreement with the Utility.

As of March 31, 2010, the Utility held a variable interest in VIEs as a result of power purchase agreements with entities that are single power plant owners of power plants. Each of these entities were designed to generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, hydroelectric, and other technologies. Under each of the power purchase agreements that represent a variable interest, the Utility is obligated to purchase electricity or capacity, or both, from the VIEs. The Utility does not provide any other financial or other support to these VIEs and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 11 below for further discussion.) As of March 31, 2010, the Utility was not the primary beneficiary of any power plant VIEs.

The Utility continues to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2010, as the Utility held a controlling financial interest and is the primary beneficiary. The Utility was the primary beneficiary as it was involved in the design of PERF and has exposure to losses and returns through its equity investment. The Utility consolidated PERF’s assets of $1.2 billion and liabilities of $1.1 billion (see Note 4 below for further discussion). The assets of PERF are only available to settle the liabilities of PERF.

The adoption of ASU 2009-17 did not have an impact on the Condensed Consolidated Financial Statements.

Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements

On January 1, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”). ASU No. 2010-06 requires disclosures regarding (1) significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and (2) fair value measurement inputs and valuation techniques. Furthermore, ASU No. 2010-06 requires presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable inputs (Level 3), beginning in the first quarter of 2011. The adoption of ASU No. 2010-06 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements

On March 31, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-09, “Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements” (“ASU No. 2010-09”). ASU No. 2010-09 does not significantly change the prior accounting for subsequent events but eliminates the requirement to disclose the date through which an SEC filer has evaluated subsequent events and the basis for that date. The adoption of ASU No. 2010-09 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

At March 31, 2010 and December 31, 2009, the Utility had current regulatory assets of $568 million and $427 million, respectively, consisting primarily of the current portion of price risk management regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below for further discussion.) Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	March 31, 2010		December 31, 2009
Pension benefits	$	1,421	$	1,386
Deferred income taxes		1,067		1,027
Energy recovery bonds		1,039		1,124
Utility retained generation		719		737
Price risk management		484		346
Environmental compliance costs		397		408
Unamortized loss, net of gain, on reacquired debt		197		203
Other		278		291
Total long-term regulatory assets	$	5,602	$	5,522

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 13 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.)

The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers offset by deferred income tax liabilities. The CPUC requires the Utility to pass through certain tax benefits to customers, ignoring the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.

The regulatory asset for energy recovery bonds (“ERBs”) represents the refinancing of the regulatory asset provided for in the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). (See Note 4 below.) The regulatory asset is amortized over the life of the bonds consistent with the period over which the related billed revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 15 years.

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)

The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation expense that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 30 years. (See Note 11 below.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.

At March 31, 2010 and December 31, 2009, “Other” consisted of regulatory assets relating to ARO expenses recorded in accordance with GAAP that are probable of future recovery through the ratemaking process, and removal costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), as approved by the CPUC for future recovery. “Other” also consisted of costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014, as well as costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004.

In general, the Utility does not earn a return on regulatory assets in which the related costs do not accrue interest. Accordingly, the Utility earns a return only on the Utility’s retained generation regulatory assets; unamortized loss, net of gain, on reacquired debt; and regulatory assets associated with the plan of reorganization.

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $138 million and $163 million, respectively, primarily consisting of the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates and the current portion of price risk management regulatory liabilities. Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms of one year or less. Current regulatory liabilities are included in Current Liabilities – Other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	March 31, 2010		December 31, 2009
Cost of removal obligation	$	2,991	$	2,933
Public purpose programs		566		508
Recoveries in excess of ARO		508		488
Other		125		196
Total long-term regulatory liabilities	$	4,190	$	4,125

The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

“Other” at March 31, 2010 and December 31, 2009 included the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year, the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered with Mirant Corporation, as well as insurance recoveries for hazardous substance remediation.

Regulatory Balancing Accounts

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.

The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in Other Noncurrent Assets – Regulatory assets and Noncurrent Liabilities – Regulatory liabilities in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, net

	Receivable (Payable)
	Balance at
(in millions)	March 31, 2010			December 31, 2009
Utility generation	$	572		$	355
Distribution revenue adjustment mechanism		287			152
Public purpose programs		128			83
Energy procurement costs		115			128
Gas fixed cost		(15	)		93
Energy recovery bonds		(163	)		(185	)
Other		232			202
Total regulatory balancing accounts, net	$	1,156		$	828

The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation revenues.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements, the actual costs of such programs, and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.

The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur during the following year. The Utility’s electric rates are set to recover such expected costs.

The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.

The ERB balancing accounts record certain benefits and costs associated with ERBs that are provided to, or received from, customers. In addition, these accounts ensure that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs was issued.

At March 31, 2010 and December 31, 2009, “Other” included the California Department of Water Resources (“DWR”) power charge collection balancing account, which ensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeter TM advanced metering project; and the transition access charge balancing account, which is used to pass through transmission high voltage access charges and credits.

NOTE 4: DEBT

Utility

Senior Notes

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.

Pollution Control Bonds

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode.

Credit Facility and Short-Term Borrowings

At March 31, 2010, the Utility had $265 million of letters of credit outstanding under the Utility’s $1.94 billion revolving credit facility.

The revolving credit facility also provides liquidity support for commercial paper offerings. At March 31, 2010, the Utility had $751 million of commercial paper outstanding at an average yield of 0.31%.

Energy Recovery Bonds

In 2005, PERF, a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component to be collected from the Utility’s electricity customers. The total amount of ERB principal outstanding was $1.1 billion at March 31, 2010.

While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets, including the recovery property, of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2010 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders’ Equity
Balance at December 31, 2009	$	10,585		$	11,185
Net income		261			264
Common stock issued		10			-
Share-based compensation amortization		15			-
Common stock dividends declared and paid		-			(179	)
Common stock dividends declared but not yet paid		(169	)		-
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Tax benefit from employee stock plans		2			1
Other comprehensive income		(80	)		(80	)
Equity contribution		-			20
Balance at March 31, 2010	$	10,621		$	11,208

For the three months ended March 31, 2010, PG&E Corporation contributed equity of $20 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

Comprehensive Income

Comprehensive income consists of net income and accumulated other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, cumulative adjustments for employee benefit plans, net of tax, are included in accumulated other comprehensive income.

	PG&E Corporation					Utility
	Three Months Ended March 31,					Three Months Ended March 31,
(in millions)	2010			2009		2010			2009
Net income	$	261		$	244	$	264		$	239
Employee benefit plan adjustment, net of tax		(80	)		7		(80	)		7
Comprehensive Income	$	181		$	251	$	184		$	246

Dividends

During the three months ended March 31, 2010, PG&E Corporation paid common stock dividends totaling $157 million. On February 17, 2010, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $169 million, which was paid on April 15, 2010 to shareholders of record on March 31, 2010.

During the three months ended March 31, 2010, the Utility paid common stock dividends totaling $179 million to PG&E Corporation.

During the three months ended March 31, 2010, the Utility paid dividends totaling $4 million to holders of its outstanding series of preferred stock. On February 17, 2010, the Board of Directors of the Utility declared a dividend totaling $3 million on its outstanding series of preferred stock, payable on May 15, 2010, to shareholders of record on April 30, 2010.

NOTE 6: EARNINGS PER SHARE

Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation’s 9.50% Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of participating securities. All of the participating securities participate in dividends on a 1:1 basis with shares of common stock.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS:

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2010		2009
Basic
Income Available for Common Shareholders	$	258	$	241
Less: distributed earnings to common shareholders		169		154
Undistributed earnings	$	89	$	87
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	169	$	154
Undistributed earnings allocated to common shareholders		85		83
Total common shareholders earnings	$	254	$	237
Weighted average common shares outstanding, basic		371		364
Convertible Subordinated Notes		16		17
Weighted average common shares outstanding and participating securities		387		381
Net earnings per common share, basic
Distributed earnings, basic (1)	$	0.46	$	0.42
Undistributed earnings, basic		0.23		0.23
Total	$	0.69	$	0.65


(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.

In calculating diluted EPS, PG&E Corporation applies the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for three months ended March 31, 2010:

	Three Months Ended
(in millions, except per share amounts)	March 31, 2010
Diluted
Income Available for Common Shareholders	$	258
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		4
Income Available for Common Shareholders and Assumed Conversion	$	262

Weighted average common shares outstanding, basic		371
Add incremental shares from assumed conversions:
Convertible subordinated notes		16
Employee share-based compensation		2
Weighted average common shares outstanding, diluted		389
Total earnings per common share, diluted	$	0.67

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for the three months ended March 31, 2009:

	Three Months Ended
(in millions, except per share amounts)	March 31, 2009
Diluted
Income Available for Common Shareholders	$	241
Less: distributed earnings to common shareholders		154
Undistributed earnings	$	87

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	154
Undistributed earnings allocated to common shareholders		83
Total common shareholders earnings	$	237

Weighted average common shares outstanding, basic		364
Convertible subordinated notes		17
Weighted average common shares outstanding and participating securities, basic		381
Weighted average common shares outstanding, basic		364
Employee share-based compensation		2
Weighted average common shares outstanding, diluted		366
Convertible subordinated notes		17
Weighted average common shares outstanding and participating securities, diluted		383
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.42
Undistributed earnings, diluted		0.23
Total earnings per common share, diluted	$	0.65

Securities that were antidilutive and excluded from the calculation of diluted shares outstanding were insignificant for the periods presented above.

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers. The CPUC and the FERC allow the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas. As these costs are passed through to customers in rates, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of electricity and natural gas.

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

·	forward contracts that commit the Utility to purchase a commodity in the future;

·	swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity;

·	option contracts that provide the Utility with the right to buy a commodity at a predetermined price; and

·	futures contracts that are exchange-traded contracts that commit the Utility to purchase a commodity or make a cash settlement at a specified price and future date.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.

Commodity-Related Price Risk

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s customers is subject to change for a number of reasons, including:

·	periodic expirations or terminations of existing electricity purchase contracts, including the DWR’s contracts;

·	the execution of new electricity purchase contracts;

·	fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;


·	changes in the Utility’s customers’ electricity demands due to customer and economic growth or decline, weather, implementation of new energy efficiency and demand response programs, direct access, and community choice aggregation;

·	the acquisition, retirement, or closure of generation facilities; and

·	changes in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing resources.

The Utility enters into third-party power purchase agreements to ensure sufficient electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the cash flow variability associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases under some of those power purchase agreements. These financial swaps are considered derivative instruments.

Electric Transmission Congestion Revenue Rights

The California Independent System Operator (“CAISO”)-controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update on April 1, 2009. The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). CRRs are considered derivative instruments.

Natural Gas Procurement (Electric Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the future cash flow variability associated with fluctuating natural gas prices, the Utility purchases financial instruments such as futures, swaps, and options. These financial instruments are considered derivative instruments.

Natural Gas Procurement (Small Commercial and Residential Customers)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “core,” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot markets to balance such seasonal supply and demand.

Other Risk

At March 31, 2010, PG&E Corporation had $247 million of Convertible Subordinated Notes outstanding that will mature on June 30, 2010. The holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices. The dividend participation rights associated with the Convertible Subordinated Notes are embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other (expense) income, net).

Volume of Derivative Activity

At March 31, 2010, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts was as follows:

		Contract Volume (1)
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year But Less Than 3 Years		Greater Than 3 Years But Less Than 5 Years		Greater Than 5 Years (2)
Natural Gas (3) (MMBtus (4) )	Forwards, Futures, and Swaps		354,147,125		211,026,845		17,875,000		-
	Options		198,987,080		104,650,000		11,100,000		-

Electricity (Megawatt-hours)	Forwards, Futures, and Swaps		4,050,541		8,296,859		4,274,287		4,082,736
	Options		389,000		7,450		156,588		503,904
	Congestion Revenue Rights		75,220,639		66,937,314		66,870,770		111,554,263

PG&E Corporation Equity (Shares)	Dividend Participation Rights		16,370,789		-		-		-

(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.
(2) Derivatives in this category expire between 2015 and 2022.
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
(4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists. The net balances include outstanding cash collateral associated with derivative positions.

At March 31, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

(in millions)	Gross Derivative Balance (1)			Netting (2)			Cash Collateral (2)		Total Derivative Balances
Commodity Risk (PG&E Corporation and Utility)
Current Assets – Prepaid expenses and other	$	27		$	(10	)	$	46	$	63
Other Noncurrent Assets – Other		53			(34	)		55		74
Current Liabilities – Other		(332	)		10			168		(154	)
Noncurrent Liabilities – Other		(518	)		34			161		(323	)
Total commodity risk	$	(770	)	$	-		$	430	$	(340	)

Other Risk Instruments (3) (PG&E Corporation Only)
Current Liabilities – Other	$	(7	)	$	-		$	-	$	(7	)
Total derivatives	$	(777	)	$	-		$	430	$	(347	)

(1) See Note 8 below for a discussion of the valuation techniques used to calculate the fair value of these instruments.
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

At December 31, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

(in millions)	Gross Derivative Balance			Netting (1)			Cash Collateral (1)		Total Derivative Balances
Commodity Risk (PG&E Corporation and Utility)
Current Assets – Prepaid expenses and other	$	76		$	(12	)	$	77	$	141
Other Noncurrent Assets – Other		64			(44	)		13		33
Current Liabilities – Other		(231	)		12			54		(165	)
Noncurrent Liabilities – Other		(390	)		44			44		(302	)
Total commodity risk	$	(481	)	$	-		$	188	$	(293	)

Other Risk Instruments (2) (PG&E Corporation Only)
Current Liabilities – Other	$	(13	)	$	-		$	-	$	(13	)
Total derivatives	$	(494	)	$	-		$	188	$	(306	)

(1) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
(2) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

Expenses related to the dividend participation rights are not recoverable in customers’ rates. Therefore, changes in the fair value of these instruments are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income.

Gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:

	Commodity Risk (PG&E Corporation and Utility)
	Three months ended March 31,
(in millions)	2010			2009
Unrealized gain/(loss) - Regulatory assets and liabilities (1)	$	(289	)	$	(307	)
Realized gain/(loss) - Cost of electricity (2)		(106	)		(202	)
Realized gain/(loss) - Cost of natural gas (2)		(39	)		(23	)
Total commodity risk instruments	$	(434	)	$	(532	)
	Other Risk Instruments (3) (PG&E Corporation Only)
Other expense (income), net	$	1		$	(2	)
Total other risk instruments	$	1		$	(2	)


(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
(3) This category relates to dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

Cash inflows and outflows associated with the settlement of all derivative instruments are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At March 31, 2010, the additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered was as follows:

(in millions)
Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized	$	(551	)
Related derivatives in an asset position		-
Collateral posting in the normal course of business related to these derivatives		81
Net position of derivative contracts/additional collateral posting requirements (1)	$	(470	)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit-risk-related contingencies.

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, dividend participation rights, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

Level 1 —Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 —Include other inputs that are directly or indirectly observable in the marketplace.

Level 3 —Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. (See Note 12 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for further discussion of fair value measurements.)

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (money market investments, rabbi trusts, and dividend participation rights are held by PG&E Corporation and not the Utility):

Fair Value Measurements at March 31, 2010
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	195	$	-	$	-	$	195
Nuclear decommissioning trusts
U.S. equity securities (1)		813		30		-		843
Non-U.S. equity securities		328		-		-		328
U.S. government and agency securities		664		73		-		737
Municipal securities		4		86		-		90
Other fixed income securities		-		76		-		76
Total nuclear decommissioning trusts (2)		1,809		265		-		2,074
Price risk management instruments
Electric (3)		47		-		-		47
Total price risk management instruments		47		-		-		47
Rabbi trusts
Equity securities		22		-		-		22
Life insurance contracts		-		62		-		62
Total rabbi trusts		22		62		-		84
Long-term disability trust
U.S. equity securities (1)		3		28		-		31
Corporate debt securities (1)		-		148		-		148
Total long-term disability trust		3		176		-		179
Total assets	$	2,076	$	503	$	-	$	2,579
Liabilities:
Dividend participation rights	$	-	$	-	$	7	$	7
Price risk management instruments
Electric (4)		-		50		295		345
Gas (5)		-		1		41		42
Total price risk management instruments		-		51		336		387
Other liabilities		-		-		1		1
Total liabilities	$	-	$	51	$	344	$	395

(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.
(2) Excludes deferred taxes on appreciation of investment value.
(3) Balances include the impact of netting adjustments of $214 million to Level 1. Includes natural gas for electric portfolio. (4) Balances include the impact of netting adjustments of $129 million to Level 2, and $53 million to Level 3. Includes natural gas for electric portfolio. (5) Balances include the impact of netting adjustments of $34 million to Level 3. Includes natural gas for core customers.

Fair Value Measurements at December 31, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	189	$	-	$	4	$	193
Nuclear decommissioning trusts
U.S. equity securities (1)		762		6		-		768
Non-U.S. equity securities		344		-		-		344
U.S. government and agency securities		653		51		-		704
Municipal securities		1		89		-		90
Other fixed income securities		-		108		-		108
Total nuclear decommissioning trusts (2)		1,760		254		-		2,014
Rabbi trusts
Equity securities		21		-		-		21
Life insurance contracts		60		-		-		60
Total rabbi trusts		81		-		-		81
Long-term disability trust
U.S. equity securities (1)		52		23		-		75
Corporate debt securities (1)		-		113		-		113
Total long-term disability trust		52		136		-		188
Total assets	$	2,082	$	390	$	4	$	2,476
Liabilities:
Dividend participation rights	$	-	$	-	$	12	$	12
Price risk management instruments
Electric (3)		2		73		157		232
Gas (4)		1		-		60		61
Total price risk management instruments		3		73		217		293
Other liabilities		-		-		3		3
Total liabilities	$	3	$	73	$	232	$	308


(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.
(2) Excludes taxes on appreciation of investment value .
(3) Balances include the impact of netting adjustments of $108 million to Level 1, $48 million to Level 2, and $19 million to Level 3. Includes natural gas for electric portfolio.
(4) Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.

Trust Assets

The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust are comprised primarily of equity securities and debt securities. Equity securities primarily include investments in common stock and commingled funds comprised of equity across multiple industry sectors in the U.S. and other regions of the world. Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. Equity securities and debt securities are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. A market based valuation approach is generally used to estimate the fair value of debt securities classified as Level 2 instruments in the tables above. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. No trust assets were measured at fair value using significant unobservable inputs (Level 3) at March 31, 2010.

Price Risk Management Instruments

Price risk management instruments are composed of physical and financial derivative contracts, including futures, forwards, swaps, options, and CRRs that are exchange-traded or over-the-counter traded contracts. Futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical instrument. As observable market prices are available, these instruments are generally classified as Level 1 or Level 2 instruments.

Certain exchange-traded contracts are classified as Level 2 measurements because the contract term extends to a point at which the market is no longer considered active but where prices are still observable. This determination is based on an analysis of the relevant characteristics of the market such as trading hours and volumes, frequency of available quotes, and open interest. In addition, a number of over the counter contracts have been valued using unadjusted exchange prices of similar instruments in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments.

All energy options are classified as Level 3 and are valued using the Black’s Option Pricing Model using various assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. Some of these assumptions are derived from internal models as they are unobservable. The Utility’s demand response contracts with third-party aggregators of retail electricity customers contain a call option entitling the Utility to require that the aggregator reduce electric usage by the aggregator’s customers at times of peak energy demand or in response to a CAISO alert or other emergency.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on the forecasted settlement price at the delivery points underlying the CRR using internal models. The Utility also uses the most current annual auction prices published by the CAISO to calibrate internal models. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3 measurements.

The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. Certain power purchase agreements meet the definition of a derivative instrument. Some of these power purchase agreements do not qualify as normal purchases and sales, therefore, the fair value of these power purchase agreements are recorded on the Condensed Consolidated Balance Sheets. The Utility uses internal models to determine the fair value of these power purchase agreements. These power purchase agreements include contract terms that extend beyond the point for which an active market exists. The Utility utilizes market data for the underlying commodity to the extent that it is available in determining the fair value. For periods where market data is not available, the Utility extrapolates forward prices based on historical data. These power purchase agreements are considered Level 3 instruments as the determination of their fair value includes the use of unobservable forward prices.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between Level 1 and Level 2 for the three month period ended March 31, 2010. The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis, using significant unobservable inputs (Level 3):

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission-ing Trusts Equity Securities (1)		Long-Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (Liability) Balance as of December 31, 2009	$	4		$	(12	)	$	(217	)	$	-	$	-	$	-	$	(3	)	$	(228	)
Realized and unrealized gains (losses):
Included in earnings		-			-			-			-		-		-		-			-
Included in regulatory assets and liabilities or balancing accounts		-			-			(119	)		-		-		-		2			(117	)
Purchases, issuances, and settlements		(4	)		5			-			-		-		-		-			1
Transfers into Level 3		-			-			-			-		-		-		-			-
Transfers out of Level 3		-			-			-			-		-		-		-			-
Asset (Liability) Balance as of March 31, 2010	$	-		$	(7	)	$	(336	)	$	-	$	-	$	-	$	(1	)	$	(344	)

(1) Excludes deferred taxes on appreciation of investment value.

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission-ing Trusts Equity Securities (1)			Long-Term Disability Equity Securities			Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (Liability) Balance as of December 31, 2008	$	12		$	(42	)	$	(156	)	$	5		$	54		$	24	$	(2	)	$	(105	)
Realized and unrealized gains (losses):
Included in earnings		-			2			-			-			(7	)		-		-			(5	)
Included in regulatory assets and liabilities or balancing accounts		-			-			(20	)		(1	)		-			-		1			(20	)
Purchases, issuances, and settlements		(4	)		7			-			-			-			-		-			3
Transfers into Level 3		-			-			-			-			-			-		-			-
Transfers out of Level 3		-			-			-			-			-			-		-			-
Asset (Liability) Balance as of March 31, 2009	$	8		$	(33	)	$	(176	)	$	4		$	47		$	24	$	(1	)	$	(127	)

(1) Excludes deferred taxes on appreciation of investment value.

Financial Instruments

The carrying amount and fair value of PG&E Corporation’s and the Utility’s financial instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At March 31,				At December 31,
	2010				2009
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4):
PG&E Corporation	$	597	$	1,070	$	597	$	1,096
Utility		9,240		9,727		9,240		9,824
Energy recovery bonds (Note 4)		1,120		1,176		1,213		1,269

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility is unable to assert that it has the intent and ability to hold investments to maturity. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. (See Note 3 above.)

The following table summarizes unrealized gains and losses related to available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated (1) Fair Value
(in millions)
As of March 31, 2010
U.S. equity securities	$	382	$	462	$	(1	)	$	843
Non-U.S. equity securities		174		154		-			328
U.S. government and agency securities		686		53		(2	)		737
Municipal securities		89		2		(1	)		90
Other fixed income securities		75		1		-			76
Total	$	1,406	$	672	$	(4	)	$	2,074
As of December 31, 2009
U.S. equity securities	$	344	$	425	$	(1	)	$	768
Non-U.S. equity securities		182		163		(1	)		344
U.S. government and agency securities		656		52		(4	)		704
Municipal securities		89		1		-			90
Other fixed income securities		108		2		(2	)		108
Total	$	1,379	$	643	$	(8	)	$	2,014

(1) Excludes taxes on appreciation of investment value.

The following table summarizes the estimated fair value of debt securities classified by the contractual maturity date of the security:

As of March 31, 2010	(in millions)
Less than 1 year	$	65
1–5 years		394
5–10 years		234
More than 10 years		210
Total maturities of debt securities	$	903

The following table provides a summary of activity for available-for-sale securities:

	Three Months Ended March 31,			Three Months Ended March 31,
	2010			2009
(in millions)
Proceeds received from sales of securities	$	337		$	387
Gross realized gains on sales of securities held as available-for-sale		15			8
Gross realized losses on sales of securities held as available-for-sale		(5	)		(34	)

In general, investments held in the nuclear decommissioning trust are exposed to various risks, such as interest rate, credit, and market volatility risks. It is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.

NOTE 9: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were as follows:

	Three Months Ended
	March 31,
(in millions)	2010		2009
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1
Utility expenses from:
Administrative services received from PG&E Corporation	$	16	$	19
Utility employee benefit due to PG&E Corporation		10		6

At March 31, 2010 and December 31, 2009, the Utility had a receivable of $25 million and $26 million, respectively, from PG&E Corporation included in Accounts receivable – Related parties and Other Noncurrent Assets – Related parties receivable on the Utility’s Condensed Consolidated Balance Sheets, and a payable of $24 million and $16 million, respectively, to PG&E Corporation included in Accounts payable – Related parties on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. At March 31, 2010 and December 31, 2009, the Utility held $515 million in escrow, including interest earned, for payment of the remaining net disputed claims. These amounts are included within Restricted cash on the Condensed Consolidated Balance Sheets.

While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be credited to customers.

The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 2009 to March 31, 2010:

(in millions)
Balance at December 31, 2009	$	946
Interest accrued		8
Less: Supplier Settlements		-
Balance at March 31, 2010	$	954

At March 31, 2010, the Utility’s net disputed claims liability was $954 million, consisting of $772 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within Accounts payable – Disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $675 million (classified on the Condensed Consolidated Balance Sheets within Interest payable) partially offset by accounts receivable from the CAISO and the PX of $493 million (classified on the Condensed Consolidated Balance Sheets within Accounts receivable – Customers).

Interest accrues on the liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims.

PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that the Utility will be required to pay.

NOTE 11: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental compliance and remediation, tax matters, and legal matters.

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.

At March 31, 2010, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)
2010	$	1,674
2011		2,260
2012		2,309
2013		2,307
2014		2,268
Thereafter		38,464
Total	$	49,282

Payments made by the Utility under power purchase agreements amounted to $201 million and $663 million for the three months ended March 31, 2010 and March 31, 2009, respectively. The amounts above do not include payments related to the DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities (“QF”s) are treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as capital leases. (These amounts are also included in the table above.) The fixed capacity payments are discounted to their present value in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the Amount representing interest.

(in millions)
2010	$	43
2011		50
2012		50
2013		50
2014		42
Thereafter		162
Total fixed capacity payments		397
Amount representing interest		85
Present value of fixed capacity payments	$	312

Minimum lease payments associated with the lease obligation are included in Cost of electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. The timing of the Utility’s recognition of the lease expense conforms to the ratemaking treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April 2014 and September 2021.

At March 31, 2010 and December 31, 2009, PG&E Corporation and the Utility had $32 million included in Current Liabilities – Other, and $280 million and $282 million included in Noncurrent Liabilities – Other, respectively, representing the present value of the fixed capacity payments due under these contracts recorded on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The corresponding assets at March 31, 2010 and December 31, 2009 of $312 million and $314 million, including amortization of $97 million and $94 million, respectively, are included in Property, Plant, and Equipment on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation to transport natural gas from the points at which the Utility takes delivery (typically in Canada and the southwestern United States supply basins) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in its market area in order to better meet winter peak customer loads.

The Utility also purchases natural gas to fuel its owned-generation facilities. Contract terms typically range in length from one to three years.

At March 31, 2010, the Utility’s undiscounted obligations for natural gas purchases, gas transportation services, and gas storage were as follows:

(in millions)
2010	$	549
2011		309
2012		83
2013		61
2014		44
Thereafter		115
Total (1)	$	1,161

(1) Total does not include Ruby Pipeline reservation cost commitment described below.

Payments for natural gas purchases, gas transportation services, and gas storage amounted to $553 million and $456 million for the three months ended March 31, 2010 and March 31, 2009, respectively.

Ruby Pipeline

On April 5, 2010, the FERC issued an order authorizing El Paso Corporation to construct, operate, and maintain its proposed 675-mile gas transmission pipeline (“Ruby Pipeline”), which would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border and have an initial capacity of 1.5 billion cubic feet per day. Construction of the project is scheduled to begin in late spring 2010, and the facilities are scheduled to be in service beginning March 2011. The Utility has contracted for firm service rights on the Ruby Pipeline of 0.37 billion cubic feet per day beginning in 2011. Under these agreements the Utility will have a cumulative commitment of $1.4 billion over 15 years.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 16 years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2014, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2011. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At March 31, 2010, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2010	$	152
2011		82
2012		69
2013		107
2014		135
Thereafter		1,215
Total	$	1,760

Payments for nuclear fuel amounted to $53 million and $17 million for the three months ended March 31, 2010 and March 31, 2009, respectively.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company in 2000. PG&E Corporation’s primary remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

Utility

Energy Efficiency Programs and Incentive Ratemaking

The CPUC has established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet the CPUC’s energy savings goals through implementation of the utilities’ 2006-2008 energy efficiency programs. In accordance with this mechanism, the CPUC has awarded the Utility interim incentive revenues totaling $75 million through December 31, 2009 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. The amount of additional incentive revenues the Utility may earn, if any, is subject to verification of the final energy savings over the 2006-2008 program cycle and the completion of the true-up process.

On April 8, 2010, the assigned CPUC commissioner issued a ruling to provide guidance on the 2006-2008 true-up process, noting that the CPUC had directed the parties to convene a settlement conference to seek agreement on the 2010 final true-up amounts to avoid potential controversy and delay that could arise from basing the amounts solely upon the final verification report to be issued by the CPUC’s Energy Division. The ruling stated that the CPUC can consider alternative approaches in calculating the final true-up amounts in addition to the Energy Division’s report and directed the Energy Division to calculate various true-up amounts based on a range of possible scenarios that use different assumptions about energy savings, goals, and costs.

On May 4, 2010, the Energy Division released various scenarios of additional incentive amounts using data from the Energy Division’s draft verification report released on April 15, 2010. The calculation scenarios for the Utility range from a penalty of $75 million, based on a scenario using the Energy Division’s evaluated results, to a reward of $105 million. The CPUC has scheduled a settlement conference for May 28, 2010 for the parties to discuss the various scenarios. The CPUC's adopted schedule for the final true-up process calls for a final decision by the end of 2010. PG&E Corporation and the Utility are unable to predict the amount, if any, of additional incentive revenues or penalties the Utility may be assessed for the 2006-2008 program cycle.

It is expected that the CPUC will issue a decision by the end of 2010 to develop a more streamlined framework to determine incentive amounts for future energy efficiency program cycles.

Spent Nuclear Fuel Storage Proceedings

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete. During 2009 the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. It is uncertain when the appeal will be addressed by the Ninth Circuit.

As a result of the DOE’s failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. Any appeal of this award must be filed by May 31, 2010.

The Utility estimates it has incurred $175 million between 2005 and 2009 to build on-site storage facilities. The Utility will also seek to recover these costs. Amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $39.7 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Under the Terrorism Risk Insurance Program Reauthorization Act of 2007 (“TRIPRA”), acts of terrorism may be “certified” by the Secretary of the Treasury. For a certified act of terrorism, NEIL can obtain compensation from the federal government and will provide up to the full policy limits to the Utility for an insured loss. If one or more non-certified acts of terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion within a 12-month period plus the additional amounts recovered by NEIL for these losses from reinsurance. (TRIPRA extends the Terrorism Risk Insurance Act of 2002 through December 31, 2014.)

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The $12.6 billion balance of liability protection is covered by a loss-sharing program among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 megawatts (“MW”) or higher. If a nuclear incident results in costs in excess of $375 million, then the Utility may be responsible for up to $117.5 million per reactor, with payments in each year limited to a maximum of $17.5 million per incident until the Utility has fully paid its share of the liability. Since Diablo Canyon has two nuclear reactors, each with a rated capacity of over 100 MW, the Utility may be assessed up to $235 million per incident, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53.3 million of liability insurance.

Environmental Matters

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under environmental laws. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances at former manufactured gas plant (“MGP”) sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless a more objective estimate can be achieved. Amounts recorded are not discounted to their present value.

The Utility had an undiscounted and gross environmental remediation liability of $613 million at March 31, 2010 and $586 million at December 31, 2009. The following table presents the changes in the environmental remediation liability from December 31, 2009:

(in millions)
Balance at December 31, 2009	$	586
Additional remediation costs accrued:
Transfer to regulatory account for recovery		52
Amounts not recoverable from customers		5
Less: Payments		(30	)
Balance at March 31, 2010	$	613

The $613 million accrued at March 31, 2010 consists of the following:

·	$43 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

·	$180 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

·	$84 million related to remediation at divested generation facilities;

·	$124 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

·	$132 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

·	$50 million related to remediation decommissioning fossil-fueled sites.

In February 2010, the Utility began contacting the owners of property located on eight former MGP sites in the Utility’s service territory to offer to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Three of these sites are located in urban, residential areas of San Francisco. Until the Utility’s investigation of these MGP sites is complete, the extent of the Utility’s obligation to remediate is established, and any appropriate remedial actions are determined, the Utility is unable to determine the amounts it may spend in the future to remediate these sites and no amounts have been accrued for these sites (other than investigative costs for some of the sites).

The Utility expects to recover $361 million of the $613 million environmental remediation liability, in accordance with a CPUC-approved ratemaking mechanism under which the Utility is authorized to recover 90% of hazardous waste remediation costs without a reasonableness review. (Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable under this mechanism.) In addition, the CPUC and the FERC have authorized the Utility to recover $126 million in rates relating to remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility’s undiscounted future costs could increase to as much as $1 billion if the other potentially responsible parties are not financially able to contribute to these costs or if the extent of contamination or necessary remediation is greater than anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. In addition, it is reasonably possible that the Utility will incur losses related to certain MGP sites located in San Francisco but the Utility is unable to reasonably estimate the amount of such loss.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits.

PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability for legal matters is included in PG&E Corporation’s and the Utility’s Current Liabilities – Other in the Condensed Consolidated Balance Sheets, and totaled $58 million at March 31, 2010 and $57 million at December 31, 2009. PG&E Corporation and the Utility are not able to predict the ultimate outcome of the various legal matters, but after consideration of these accruals, PG&E Corporation and the Utility do not believe that losses associated with these matters would have a material adverse impact on their financial condition or results of operations.

Tax Matters

PG&E Corporation and the Utility receive a federal subsidy (“subsidy”) for maintaining a retiree medical benefit plan with prescription drug benefits that is actuarially equivalent to Medicare Part D. For federal income tax purposes, the subsidy was deductible when contributed to the benefit plan maintained for these benefits. The recently passed federal healthcare legislation eliminates the deduction for subsidy funded contributions after 2012. Although the change does not take effect immediately, PG&E Corporation and the Utility must recognize the accounting impact in the period in which the legislation is signed. As a result, during the three months ended March 31, 2010, PG&E Corporation and the Utility recognized an expense of $20 million (recorded as an increase to income tax provision and a reduction to deferred income tax asset for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).

The Internal Revenue Service (“IRS”) is currently auditing PG&E Corporation’s consolidated 2005–2007 income tax returns. For 2008 and 2009, PG&E Corporation participates in the Compliance Assurance Process, a real-time IRS audit intended to expedite issue resolution. The IRS accepted the 2008 return but excepted several items for further review, including the Utility’s request to change its method for determining what costs are deductible as a repair. The IRS previously approved the change in method subject to a field audit to determine the size of the adjustment that would result.

The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns and 1998-2007 amended income tax returns filed by PG&E Corporation.

PG&E Corporation believes that the final resolution of the federal and California audits will not have a material adverse impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in any other jurisdiction.

As of March 31, 2010, PG&E Corporation has $25 million of federal and California capital loss carry forwards based on filed tax returns, of which approximately $10 million will expire if not used by 2011. For all periods presented, PG&E Corporation has provided a full valuation allowance against its deferred income tax assets for capital loss carry forwards.

For a discussion of unrecognized tax benefits, see Note 9 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. It is reasonably possible that unrecognized tax benefits could decrease in the next 12 months by an amount ranging from $0 to $30 million for PG&E Corporation and the Utility.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

The Utility served 5.1 million electricity distribution customers and 4.3 million natural gas distribution customers at March 31, 2010. The Utility had $43.3 billion in assets at March 31, 2010 and generated revenues of $3.5 billion in the three months ended March 31, 2010.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. Before setting rates, the CPUC and the FERC authorize the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers to recover its reasonable operating and capital costs of providing utility services. The authorized revenue requirements also provide the Utility an opportunity to earn a return on “rate base;” i.e., the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers. The CPUC requires the Utility to maintain a certain capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) when financing its rate base and authorizes the Utility to earn a specific rate of return on each capital component.

This is a combined quarterly report of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. This combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of PG&E Corporation and the Utility should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q, as well as the MD&A, the audited Consolidated Financial Statements, and the Notes to the Consolidated Financial Statements incorporated by reference into their combined Annual Report on Form 10-K for the year ended December 31, 2009, is referred to in this Quarterly Report on Form 10-Q as the “2009 Annual Report.”

Significant developments that have occurred since the 2009 Annual Report was filed with the SEC on February 19, 2010 are discussed in this Quarterly Report on Form 10-Q.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three Months Ended March 31, 2010

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three months ended March 31, 2010 was $0.67 per share, compared to $0.65 per share for the same period in 2009. For the three months ended March 31, 2010, PG&E Corporation’s income available for common shareholders increased by $17 million, or 7%, to $258 million, compared to $241 million for the same period in 2009.

The increase in EPS and income available for common shareholders as compared to the same period in 2009 was primarily due to (1) an increase of $21 million, after tax, that the Utility earned on higher authorized capital investments, (2) a $6 million, after tax, decrease in employee termination costs, (3) a $24 million, after tax, decrease in costs related to Diablo Canyon, the amount attributable to the scheduled refueling outage in 2009, and (4) a $6 million, after tax, decrease in employee benefit costs due to improved market performance on trust assets held to fund the employee benefits in 2010. These positive factors were partially offset by (1) $25 million of costs incurred to support Proposition 16 - The Taxpayers Right to Vote Act, (2) a $20 million decrease in deferred tax assets triggered by recent federal healthcare legislation which eliminated the tax deductibility of the Medicare Part D federal subsidy, and (3) an increase of $12 million, after tax, in storm- and outage-related expenses incurred in the three months ended March 31, 2010 as compared to the same period in 2009.

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, recover its authorized costs timely, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation’s and the Utility’s results of operations and financial condition, including:

·	The Outcome of Regulatory Proceedings and the Impact of Ratemaking Mechanisms. During 2010, the CPUC will determine the amount of revenue requirements the Utility is authorized to recover from 2011 through 2013 for its electric and natural gas distribution operations and its electric generation operations in the 2011 General Rate Case (“2011 GRC”) and from 2011 through 2014 for its natural gas transportation and storage services in the Gas Transmission and Storage Rate Case. In addition, in the Utility’s most recent annual transmission owner (“TO”) rate case, the FERC will determine the amount of electric transmission revenues the Utility can recover beginning in March 2011. The decisions issued in the three associated rate cases will determine the majority of the Utility’s base revenue requirements for 2011 and future years. In addition, the Utility has requested the CPUC or the FERC to authorize additional base revenue requirements for specific capital expenditure projects such as new power plants, new or upgraded natural gas or electric transmission facilities, the installation of an advanced metering infrastructure, and other infrastructure improvements. (See “Capital Expenditures” below.) The outcome of these regulatory proceedings can be affected by many factors, including general economic conditions, the level of rates, and political and regulatory policies.

·	The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability . The Utility’s revenue requirements in general rate cases and TO rate cases are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses as well as to earn a return on equity (“ROE”) and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its CPUC-authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. In addition, the Utility may incur higher than anticipated operating expenses than provided for in the last general rate case. The Utility continuously re-prioritizes spending and seeks to achieve sustainable operational efficiencies to maximize its ability to earn its authorized return while maintaining and improving operational safety and reliability. (See “Results of Operations” below.) The Utility also seeks to make the amount and timing of its capital expenditures consistent with forecasted amounts and timing. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense but does not recover revenues to fully offset these expenses or earn an ROE until the increased capital expenditures are added to rate base in future rate cases. (See “Capital Expenditures” below.)

·	Capital Structure and Financing. The CPUC has authorized a capital structure for the Utility’s electric and natural gas distribution and electric generation rate base that consists of 52% common equity and 48% debt and preferred stock. This authorized capital structure will remain in effect through 2012. The CPUC also has authorized the Utility to earn a rate of return on each component of its capital structure, including an ROE of 11.35%. These rates will remain in effect through 2010. The rates for 2011 and 2012 are subject to an annual adjustment mechanism that will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Service utility bond index increases or decreases by more than 1% as compared to the applicable benchmark. The amount of the Utility’s authorized equity earnings is determined by the 52% equity component, the 11.35% ROE, and the aggregate amount of rate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically authorized, but rates are designed to allow the Utility to earn a reasonable rate of return. The Utility’s actual equity earnings could be more or less based on a number of factors, including the timing and amount of operating costs and capital expenditures. The CPUC periodically authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The timing and amount of the Utility’s future financing will depend on various factors, as discussed in “Liquidity and Financial Resources” below. PG&E Corporation regularly contributes equity to the Utility to maintain the Utility’s CPUC-authorized capital structure. PG&E Corporation may issue debt or equity in the future to fund these equity contributions.

In addition to the key factors discussed above, PG&E Corporation’s and the Utility’s future results of operations and financial condition are subject to risk factors. (See “Risk Factors” in the 2009 Annual Report.)

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures; estimated environmental remediation, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; the anticipated outcome of various regulatory and legal proceedings; estimated future cash flows; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

·	the Utility’s ability to manage capital expenditures and its operating and maintenance expenses within authorized levels;

·	the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;

·	the adequacy and price of electricity and natural gas supplies and whether the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by the California Independent System Operator (“CAISO”) will continue to function effectively, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

·	explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

·	the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

·	the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

·	changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

·	the occurrence of unplanned outages at the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, or other matters associated with the operations at Diablo Canyon;

·	whether the Utility can operate efficiently to achieve cost savings and identify and successfully implement additional sustainable cost-saving measures;

·	whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

·	the impact of federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

·	whether the Utility can successfully implement its program to install advanced meters for its electric and natural gas customers and integrate the new meters with its customer billing and other systems, the outcome of the independent investigation ordered by the CPUC and the California Legislature into customer concerns about the new meters, and the ability of the Utility to implement various rate changes including “dynamic pricing” by offering electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices;

·	how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;

·	the outcome of litigation, including litigation involving the application of various California wage and hour laws, and the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties;

·	the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

·	the impact of environmental laws and regulations and the costs of compliance and remediation;

·	the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

·	the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2009 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2010 and 2009:

	Three Months ended March 31,
(in millions)	2010			2009
Utility
Electric operating revenues	$	2,510		$	2,426
Natural gas operating revenues		965			1,005
Total operating revenues		3,475			3,431
Cost of electricity		920			883
Cost of natural gas		495			557
Operating and maintenance		990			1,059
Depreciation, amortization, and decommissioning		451			419
Total operating expenses		2,856			2,918
Operating income		619			513
Interest income		2			9
Interest expense		(156	)		(173	)
Other (expense) income, net		(6	)		21
Income before income taxes		459			370
Income tax provision		195			131
Net Income		264			239
Preferred dividend requirement		3			3
Income available for common stock	$	261		$	236
PG&E Corporation, Eliminations, and Other (1)
Operating revenues	$	-		$	-
Operating expenses		1			-
Operating loss		(1	)		-
Interest income		-			-
Interest expense		(12	)		(8	)
Other expense, net		-			(3	)
Loss before income taxes		(13	)		(11	)
Income tax benefit		(10	)		(16	)
Net (loss) gain	$	(3	)	$	5
Consolidated Total
Operating revenues	$	3,475		$	3,431
Operating expenses		2,857			2,918
Operating income		618			513
Interest income		2			9
Interest expense		(168	)		(181	)
Other (expense) income, net		(6	)		18
Income before income taxes		446			359
Income tax provision		185			115
Net Income		261			244
Preferred dividend requirement of subsidiary		3			3
Income available for common shareholders	$	258		$	241

(1) PG&E Corporation eliminates all intercompany transactions in consolidation.

Utility

The following presents the Utility’s operating results for the three months ended March 31, 2010 and 2009.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, and public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, a portion of the Utility’s customers’ demand for electricity (“load”) is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers.

The following table provides a summary of the Utility’s electric operating revenues:

	Three Months Ended
	March 31,
(in millions)	2010			2009
Electric operating revenues	$	2,866		$	2,821
DWR pass-through revenues (1)		(356	)		(395	)
Total electric operating revenues	$	2,510		$	2,426

(1) The Utility acts as a billing and collection agent on behalf of the DWR and remits the amounts collected from customers to the DWR. The Utility’s electric operating revenues are reflected net of the amounts remitted to the DWR.

The Utility’s total electric operating revenues increased by $84 million, or 3%, in the three months ended March 31, 2010 compared to the same period in 2009, reflecting an increase in revenues to recover the cost of electricity. The cost of electricity, which increased by $37 million in the three months ended March 31, 2010, is passed through to customers and does not impact net income. (See “Cost of Electricity” below.) Electric operating revenues, excluding the cost of electricity, increased by $47 million. This was primarily due to a $17 million increase for the 2010 attrition adjustment and $33 million to recover the capital costs of new assets placed in service and the associated rate of return.

The Utility’s electric operating revenues for future years are expected to increase, as authorized by the FERC in the TO rate cases and by the CPUC in the 2011 GRC. Additionally, the Utility’s future electric operating revenues will be impacted by the cost of electricity. The Utility also expects to continue to collect revenue requirements to recover capital expenditures related to specific projects approved by the CPUC, such as new Utility-owned generation projects. Revenues will increase to the extent that the CPUC approves the Utility’s proposals for other capital projects. (See “Capital Expenditures” below.) Revenue requirements associated with new or expanded public purpose, energy efficiency, and demand response programs will also impact electric operating revenues. Finally, the CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

Cost of Electricity

The Utility’s cost of electricity includes costs to purchase power from third parties, certain transmission costs, the cost of fuel used in its generation facilities, and the cost of fuel supplied to other facilities under tolling agreements. The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with the Utility’s own generation facilities, which are included in Operating and maintenance expense in the Condensed Consolidated Statements of Income. The cost of electricity provided to the Utility customers under power purchase agreements between the DWR and various power suppliers is also excluded from the Utility’s cost of electricity.

The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

	Three Months Ended
	March 31,
(in millions)	2010		2009
Cost of purchased power	$	842	$	839
Fuel used in own generation facilities		78		44
Total cost of electricity	$	920	$	883
Average cost of purchased power per kWh (1)	$	0.083	$	0.082
Total purchased power (in millions of kWh)		10,117		10,226

(1) Kilowatt-hour.

The Utility’s total cost of electricity increased by $37 million, or 4%, in the three months ended March 31, 2010 compared to the same period in 2009, primarily due to an increase in the amount of fuel used in its own generation facilities. The Utility generated more electricity in the three months ended March 31, 2010 as compared to the same period in 2009 when there was a refueling outage at Diablo Canyon. In addition, due to the expiration of a DWR power purchase contract at the end of 2009, the Utility increased the use of its own generation facilities, such as the new Gateway Generating Station, during the three months ended March 31, 2010 to meet customer demand previously satisfied with electricity provided under the DWR contract. The Utility’s mix of resources is determined by the availability of the Utility’s own electricity generation and the cost-effectiveness of each source of electricity.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power that the Utility produces, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or renegotiated.

The Utility’s future cost of electricity also may be affected by federal or state legislation or rules that may be adopted to regulate the emissions of greenhouse gases (“GHG”) from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. In particular, costs are likely to increase in the future when California’s statewide GHG emissions reduction law is implemented. (See “Environmental Matters” below.)

Natural Gas Operating Revenues

The Utility sells natural gas, natural gas transportation services, and natural gas storage services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout its service territory for delivery to the Utility’s distribution system, which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

The following table provides a summary of the Utility’s natural gas operating revenues:

	Three Months Ended
	March 31,
(in millions)	2010		2009
Bundled natural gas revenues	$	875	$	923
Transportation service-only revenues		90		82
Total natural gas operating revenues	$	965	$	1,005
Average bundled revenue per Mcf (1) of natural gas sold	$	9.21	$	9.14
Total bundled natural gas sales (in millions of Mcf)		95		101

(1) One thousand cubic feet.

The Utility’s total natural gas operating revenues decreased by $40 million, or 4%, in three months ended March 31, 2010 compared to the same period in 2009, primarily due to a $62 million decrease in the total cost of natural gas partially offset by a $9 million increase in the cost of public purpose programs. These costs are passed through to customers and do not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding items passed through to customers, increased by $13 million primarily due to an increase in authorized base revenues consisting of 2010 attrition adjustments and base revenues as a result of the 2007 Gas Accord IV Settlement Agreement.

The Utility’s future natural gas operating revenues will depend on the amount of revenue requirements authorized by the CPUC in the Utility’s 2011 GRC and the Gas Transmission and Storage rate case. (See “Regulatory Matters” below.) In addition, the Utility expects future natural gas operating revenues to increase to the extent that the CPUC approves the Utility’s separately funded projects. Finally, the CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues that the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and gas storage costs but excludes the transportation costs on intrastate pipelines for core and non-core customers, which are included in Operating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Notes 7 and 8 of the Notes to the Condensed Consolidated Financial Statements.)

The following table provides a summary of the Utility’s cost of natural gas:

	Three Months Ended
	March 31,
(in millions)	2010		2009
Cost of natural gas sold	$	444	$	515
Transportation cost of natural gas sold		51		42
Total cost of natural gas	$	495	$	557
Average cost per Mcf of natural gas sold	$	4.67	$	5.10
Total natural gas sold (in millions of Mcf)		95		101

The Utility’s total cost of natural gas decreased by $62 million, or 11%, in the three months ended March 31, 2010 compared to the same period in 2009, primarily due to the $49 million refund the Utility received in the first quarter of 2010 in settlement of litigation related to the manipulation of the natural gas market by third parties during 1999-2002, partially offset by higher market prices for natural gas, which are passed through to customers and do not impact net income.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility’s future cost of gas may be affected by federal or state legislation or rules to regulate the GHG emissions from the Utility’s natural gas transportation and distribution facilities and from natural gas consumed by the Utility’s customers.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses.

The Utility’s operating and maintenance expenses (including costs passed through to customers) decreased by $69 million, or 7%, in the three months ended March 31, 2010 compared to the same period in 2009. During the three months ended March 31, 2010, the pass-through costs of public purpose programs increased by $7 million as compared to the level of program spending in the same period in 2009. Excluding costs passed through to customers, operating and maintenance expenses decreased by $76 million, including a $49 million decrease in labor costs as compared to the same period in 2009 when there was a refueling outage at Diablo Canyon, a $10 million decrease in employee benefit costs due to improved market performance on trust assets held to fund the employee benefits in 2010 as compared to 2009, a $12 million decrease in the Utility’s uncollectible customer accounts as a result of customer outreach and increased collection efforts, and a $10 million decrease in severance costs as compared to the same period in 2009 primarily due to employee severance costs that were incurred in connection with the consolidation of some regional facilities. These decreases were partially offset by $21 million of higher costs related to the January 2010 winter storms.

The Utility anticipates that it will incur higher costs in the future to improve the safety and reliability of its electric and natural gas system infrastructure and to maintain its aging electric distribution system. The Utility also expects that it will incur higher expenses in future periods to obtain permits or comply with permitting requirements, including costs associated with renewing FERC licenses for the Utility’s hydroelectric generation facilities. To help offset these increased costs, the Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable cost savings.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $32 million, or 8%, in the three months ended March 31, 2010, as compared to the same period in 2009, primarily due to an increase in authorized capital additions.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in net capital additions. Additionally, depreciation expense in subsequent years will be determined based on rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case, and by the FERC in future TO rate cases.

Interest Income

In the three months ended March 31, 2010, the Utility’s interest income decreased by $7 million, or 78%, as compared to the same period in 2009, primarily due to lower interest rates affecting various regulatory balancing accounts and lower balances in those accounts. In addition, interest income decreased due to lower interest rates earned on funds held in escrow and a lower balance of funds held in escrow, pending the disposition of disputed claims that had been made in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements for information about the Chapter 11 disputed claims.)

The Utility’s interest income in future periods will be primarily affected by changes in the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates.

Interest Expense

In the three months ended March 31, 2010, the Utility’s interest expense decreased by $17 million, or 10%, as compared to the same period in 2009. This was primarily attributable to lower interest rates and outstanding balances on liabilities that the Utility incurs interest expense on (such as the liability for Chapter 11 disputed claims and various regulatory balancing accounts and regulatory assets). This decrease was partially offset by interest accrued on higher outstanding balances of long-term debt due to the timing of senior note issuances. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion.)

The Utility’s interest expense in future periods will be impacted by changes in interest rates, changes in the liability for Chapter 11 disputed claims, changes in regulatory balancing accounts and regulatory assets, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued. (See “Liquidity and Financial Resources” below.)

Other (Expense) Income, Net

The Utility’s other expense, net increased by $27 million, or 129%, in the three months ended March 31, 2010, as compared to the same period in 2009, primarily due to costs incurred to support the California’s Taxpayers’ Right to Vote Act, a California ballot initiative which would propose requiring local governments to gain voter support before using taxpayer money to establish electric service. These costs are not recovered in rates.

The Utility estimates it will incur approximately $10 million in the remainder of 2010 to support this California ballot initiative.

Income Tax Provision

The Utility’s income tax provision increased by $64 million, or 49%, for the three months ended March 31, 2010, as compared to the same period in 2009. The effective tax rates for the three months ended March 31, 2010 and 2009 were 42.4% and 35.3%, respectively. The increase in the effective tax rate for 2010 was primarily due to non-deductible expenses incurred to support the ballot initiative discussed above and the reversal of a deferred tax asset that had been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012 which were eliminated as part of the recently passed Federal healthcare legislation passed during March 2010. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 9.50% Convertible Subordinated Notes and 5.8% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three months ended March 31, 2010, as compared to the same period in 2009.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations depends on the levels of its operating cash flow and access to the capital markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal demand for electricity and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The Utility has a short-term borrowing authority of $4.0 billion, including $500 million that is restricted for use in certain contingencies.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, refinance debt, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, and make dividend payments primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital markets.

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding commercial paper and credit facilities at March 31, 2010:

(in millions)
Authorized Borrower	Facility	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	Revolving credit facility	February 2012	$	187	(1)	$	-	$	-		N/A	$	187
Utility	Revolving credit facility	February 2012		1,940	(2)		265		-	$	751		924
Total credit facilities			$	2,127		$	265	$	-	$	751	$	1,111

(1) Includes an $87 million sublimit for letters of credit and a $100 million sublimit for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.
(2) Includes a $921 million sublimit for letters of credit and a $200 million sublimit for swingline loans.

At March 31, 2010, PG&E Corporation and the Utility were in compliance with all covenants under these revolving credit facilities.

2010 Financings

On April 1, 2010, the Utility issued $250 million of 5.8% Senior Notes due March 1, 2037. The proceeds from this issuance were used to repay a portion of outstanding commercial paper.

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 for the benefit of the Utility. The proceeds were used to refund the corresponding pollution control bonds issued in 2005, which were purchased by the Utility in 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on April 1 and October 1.

In addition, PG&E Corporation issued 306,987 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating $10 million of cash through March 31, 2010. PG&E Corporation also contributed $20 million of cash to the Utility through March 31, 2010 to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC.

Future Financing Needs

The amount and timing of the Utility’s future financing needs will depend on various factors, including the conditions in the capital markets, the timing and amount of forecasted capital expenditures, and the amount of cash internally generated through normal business operations, among other factors. The Utility’s future financing needs will also depend on the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund the Utility’s operating expenses and capital expenditures to the extent that internally generated funds are not available. Assuming that PG&E Corporation and the Utility can access the capital markets on reasonable terms, PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures.

Dividends

During the three months ended March 31, 2010, PG&E Corporation paid common stock dividends of $0.42 per share, totaling $157 million. On February 17, 2010, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $169 million, which was paid on April 15, 2010 to shareholders of record on March 31, 2010.

During the three months ended March 31, 2010, the Utility paid common stock dividends totaling $179 million to PG&E Corporation.

During the three months ended March 31, 2010, the Utility paid dividends to holders of its outstanding series of preferred stock totaling $4 million. On February 17, 2010, the Board of Directors of the Utility declared a dividend totaling $3 million on its outstanding series of preferred stock, payable on May 15, 2010, to shareholders of record on April 30, 2010.

Utility

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

The Utility’s cash flows from operating activities for the three months ended March 31, 2010 and 2009 were as follows:

	Three Months Ended
	March 31,
(in millions)	2010			2009
Net income	$	264		$	239
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		491			456
Allowance for equity funds used during construction		(28	)		(25	)
Deferred income taxes and tax credits, net		138			234
Other changes in noncurrent assets and liabilities		(98	)		(48	)
Effect of changes in operating assets and liabilities:
Accounts receivable		114			298
Inventories		59			166
Accounts payable		94			(107	)
Income taxes receivable/payable		77			95
Regulatory balancing accounts, net		(377	)		(180	)
Other current assets		35			34
Other current liabilities		(387	)		(386	)
Other		26			1
Net cash provided by operating activities	$	408		$	777

In the three months ended March 31, 2010, net cash provided by operating activities decreased by $369 million compared to the same period in 2009, primarily due to tax refunds received in 2009 of $163 million with no similar refunds in 2010. These refunds represented the Utility’s portion of the settlement of the IRS audits of PG&E Corporation’s consolidated tax returns for tax years 2001 through 2004. In addition, operating cash flows decreased due to an increase of $43 million in net collateral paid by the Utility related to price risk management activities in 2010. Collateral payables and receivables are included in Other changes in noncurrent assets and liabilities, Other current assets, and Other current liabilities in the table above. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The remaining decreases in cash flows from operating activities consisted of miscellaneous other changes in operating assets and liabilities due to timing differences and seasonality.

The decrease in cash flows from operating activities was partially offset by $57 million that the Utility refunded to customers in 2009 with no similar refund in 2010.

Various factors can affect the Utility’s future operating cash flows, including the timing of cash collateral payments and receipts related to price risk management activity. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure to counterparties which primarily depends on electricity and gas price movement.

The Utility’s operating cash flows also will be impacted by electricity procurement costs and the timing of rate adjustments authorized to recover these costs. The CPUC has established a balancing account mechanism to adjust the Utility’s electric rates whenever the forecasted aggregate over-collections or under-collections of the Utility’s electric procurement costs for the current year exceed 5% of the Utility’s prior-year generation revenues, excluding generation revenues for DWR contracts. The Utility updated its forecasted 2010 electricity procurement costs in November 2009 for inclusion in the annual electric true-up proceeding, which adjusted electric and gas rates on January 1, 2010 to (1) reflect over- and under-collections in the Utility’s major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC and the FERC.

Investing Activities

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals, the occurrence of storms and other events causing outages or damage to the Utility’s infrastructure, and the completion of electricity and natural gas reliability improvements projects. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.

The Utility’s cash flows from investing activities for the three months ended March 31, 2010 and 2009 were as follows:

	Three Months Ended
	March 31,
(in millions)	2010			2009
Capital expenditures	$	(855	)	$	(1,079	)
Decrease in restricted cash		4			11
Proceeds from sales of nuclear decommissioning trust investments		337			387
Purchases of nuclear decommissioning trust investments		(343	)		(412	)
Other		5			2
Net cash used in investing activities	$	(852	)	$	(1,091	)

Net cash used in investing activities decreased by $239 million in the three months ended March 31, 2010 compared to the same period in 2009. This decrease was primarily due to a decrease of $224 million in capital expenditures as a result of the timing of capital projects.

Future cash flows used in investing activities are largely dependent on expected capital expenditures. (See “Capital Expenditures” below and in the 2009 Annual Report for further discussion of expected spending and significant capital projects.)

Financing Activities

The Utility’s cash flows from financing activities for the three months ended March 31, 2010 and 2009 were as follows:

	Three Months Ended
	March 31,
(in millions)	2010			2009
Borrowings under revolving credit facility	$	-		$	300
Repayments under revolving credit facility		-			(300	)
Net issuance of commercial paper, net of discount of $2 million in 2009		418			96
Proceeds from issuance of long-term debt, net of discount and issuance costs of $12 million in 2009		-			538
Long-term debt matured or repurchased		-			(600	)
Energy recovery bonds matured		(93	)		(89	)
Preferred stock dividends paid		(4	)		(3	)
Common stock dividends paid		(179	)		(156	)
Equity contribution		20			528
Other		8			2
Net cash provided by financing activities	$	170		$	316

In the three months ended March 31, 2010, net cash provided by financing activities decreased by $146 million compared to the same period in 2009. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

With the exception of dividend payments, interest, common stock issuance, the issuance of 5.75% Senior Notes in the principal amount of $350 million in March 2009, net tax refunds of $131 million in 2009, and transactions between PG&E Corporation and the Utility, PG&E Corporation had no material cash flows on a stand-alone basis for the three months ended March 31, 2010 and 2009.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and the purchase of fuel and transportation to support the Utility’s generation activities. In addition to those commitments disclosed in the 2009 Annual Report and those arising from normal business activities, the Utility issued $250 million of senior notes on April 1, 2010, and entered into a loan agreement to repay the California Infrastructure and Economic Development Bank which issued $50 million of tax-exempt pollution control bonds on behalf of the Utility on April 8, 2010. (Refer to the 2009 Annual Report, the Liquidity and Financial Resources section of the MD&A and Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements.)

CAPITAL EXPENDITURES

Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, Gas Transmission and Storage rate cases. (See “Regulatory Matters” below.) The Utility also collects additional revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric transmission projects, and the SmartMeter TM advanced metering infrastructure. The Utility’s proposals for significant capital projects that have been submitted for CPUC approval are discussed in the 2009 Annual Report. Recent developments in authorized or proposed capital projects since the 2009 Annual Report was filed are discussed below.

As previously disclosed, PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Williams Gas Pipeline Company, LLC, have been jointly pursuing the development of the proposed Pacific Connector Gas Pipeline, an interstate gas transmission pipeline that would connect with the proposed liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon being developed by Fort Chicago Energy Partners, L.P., as lead investor. The construction of the pipeline is dependent upon the construction of the LNG terminal. In December 2009, the FERC issued an order to authorize construction and operation of the LNG terminal and the pipeline. There are additional federal, state, and local permits and authorizations that must be obtained before construction can proceed. In addition, commitments must be obtained from LNG suppliers and shippers under long-term contracts of sufficient volumes to justify moving forward with construction of the LNG terminal and the pipeline. The desire of LNG suppliers to make such commitments is dependent on the world market for LNG, the price in various markets compared to the U.S. price, and the overall level of supply and demand for LNG. In the U.S., the gas supply landscape has changed considerably since the LNG terminal and pipeline were first contemplated. Enhanced drilling techniques have increased access to shale gas and created significant gas reserves which may decrease the need for LNG sourced natural gas. As such, PG&E Corporation cannot predict whether construction of the proposed LNG terminal and associated pipeline will occur nor whether PG&E Corporation will continue to invest in the proposed pipeline project.

Proposed Renewable Energy Development

On April 22, 2010, the CPUC voted to issue a final decision approving the Utility’s five-year proposal to build up to 250 MW of renewable generation resources based on solar photovoltaic (“PV”) technology and enter into power purchase agreements for an additional 250 MW of PV generation resources following an annual request for offers (“RFO”) for third parties to develop PV facilities. The CPUC authorized the Utility to recover the actual capital costs to develop up to 250 MW of solar PV generation facilities, subject to a corresponding cap of up to $1.45 billion. If total capital costs exceed the cost cap, the Utility could only recover such costs after obtaining CPUC approval. The CPUC also established an incentive mechanism that allows the Utility shareholders to retain 10% of the savings if the actual average per-kilowatt capital cost of the Utility-owned program is less than $3,920.00 per kilowatt. The remaining 90% of any such savings would be passed through to customers. As the Utility’s new PV facilities begin commercial operation, the project costs would be included in the Utility’s rate base, as the Utility had proposed, and the Utility would be entitled to earn a rate of return on the additional rate base. The Utility intends to begin an RFO for the power purchase agreement portion of the program and a separate RFO to request third parties to submit proposals to develop and construct the Utility-owned portion of the program after the CPUC approves the implementation details of each RFO.

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies; including Chapter 11 disputed claims, tax matters, legal matters, and environmental matters, which are discussed in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

This section of MD&A discusses significant regulatory developments that have occurred since the 2009 Annual Report was filed with the SEC.

2011 General Rate Case Application

On May 5, 2010, the CPUC’s Division of Ratepayer Advocates (“DRA”) submitted testimony in the Utility’s 2011 GRC recommending that the Utility’s 2011 revenue requirements be set at a level approximately $874 million lower than the Utility’s request. The DRA’s submission of testimony is part of the regular process in every GRC proceeding. The Utility’s December 21, 2009 GRC application requested a $1.10 billion revenue increase, including $53 million of revenue requirements for costs related to the new wholesale electricity markets in California and to implement new electric rates based on “dynamic pricing.” The requested revenue increase is comprised of increases in electricity distribution, utility-owned generation and gas distribution revenue requirements of $557 million, $331 million, and $213 million, respectively. The DRA’s recommendation would result in a total revenue requirement increase of $227 million comprised of electricity distribution and utility-owned generation increases of $176 million and $57 million, respectively, and a gas distribution revenue requirement reduction of $6 million.

The $874 million difference between the Utility’s request and the DRA’s recommendation reflects reductions in all cost categories including operating and maintenance costs, administrative and general expense, and capital investments. Among other assumptions as to future costs which differ from the Utility’s request, the DRA has assumed that the Utility would connect fewer customers, undertake less preventative maintenance, and replace aging equipment more slowly. The DRA has also recommended reductions in employee benefit costs and other overhead costs. The DRA recommends funding the Utility’s electric and gas distribution, and existing electric generation capital expenditures at $2.1 billion in 2011, as compared to the Utility’s projection of average annual capital expenditures of $2.7 billion from 2011 to 2013. (Capital expenditures related to the GRC do not include projected capital spending related to electric and gas transmission and other separately funded capital projects such as proposed new generation resources.)

The DRA has recommended attrition increases of $116 million for 2012 and $107 million for 2013, based on forecasted increases in the consumer price index, as compared to the Utility’s forecasted attrition increases of $275 million in 2012 and $343 million in 2013.

According to the CPUC’s procedural schedule, additional testimony from other parties must be submitted by May 19, 2010. The schedule contemplates hearings to be held this summer, followed by a proposed decision to be released by November 16, 2010 and a final CPUC decision to be issued by December 16, 2010.

PG&E Corporation and the Utility are unable to predict the amount of the revenue requirements that the CPUC will authorize or whether the current schedule will be maintained.

Electric Transmission Owner Rate Cases

On March 31, 2010, the Utility requested that the FERC approve an uncontested settlement in the Utility’s TO rate case that was filed on July 30, 2009. The settlement proposes to set an annual retail base revenue requirement of $875 million effective March 1, 2010. The Utility has reserved the difference between revenues based on rates requested by the Utility in its TO rate application which were used in the scheduled rate increase effective March 1, 2010, and expected revenues based on rates agreed to in the settlement. As a result, the settlement, if approved, will not impact the Utility’s results of operations or financial condition. If the settlement is approved by the FERC, the Utility will refund any over-collected amounts to customers, with interest, through an adjustment to rates in 2011.

2011 Gas Transmission and Storage Rate Case

As discussed in the 2009 Annual Report the Utility filed an application with the CPUC to initiate the Utility’s 2011 Gas Transmission and Storage rate case so that the CPUC can determine the rates and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011.

The Utility has requested that the CPUC issue a final decision by the end of 2010 in order to put new rates into place by January 1, 2011. If the CPUC does not issue a final decision by the end of 2010, the September 2007 CPUC decision approving the 2008 Gas Transmission and Storage rate case provides that the rates and terms and conditions of service in effect as of December 31, 2010 will remain in effect, with an automatic 2% escalation in rates, for local transmission only, starting January 1, 2011.

Energy Efficiency Programs and Incentive Ratemaking

It is expected that the CPUC will issue a decision by the end of 2010 to develop a more streamlined framework to determine incentive amounts for future energy efficiency program cycles.

Direct Access

As authorized by California Senate Bill 695, on March 11, 2010, the CPUC adopted a plan to re-open “direct access” on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2009 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Recent developments since the 2009 Annual Report was filed are discussed below.

Renewable Energy Resources

In an effort to reduce GHG emissions, California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, hydroelectric facilities with a capacity of 30 MW or less, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from these eligible renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. For the year ending December 31, 2009, the Utility’s RPS-eligible renewable resource deliveries equaled 14.4% of its total retail electricity sales. Most of the renewable energy that was delivered was purchased by the Utility from third parties, mainly under agreements with qualifying facility generators and other bilateral contracts. The Utility’s small hydroelectric and solar facilities also provided additional renewable energy. Some small hydroelectric energy is also provided under contracts with certain irrigation districts. As of March 31, 2010, the Utility believes it will meet the RPS mandate for 2010 through reliance on the CPUC’s flexible compliance rules.

In March 2010, the CPUC issued a decision authorizing the use of tradable renewable energy credits (“RECs”), the green attributes of renewable power, for RPS compliance. A tradable REC refers to a certificate of proof of the procurement of the green attributes separate from the associated energy, which certificate may be transferred to any third party and resold. Previously, investor-owned utilities were not allowed to use RECs purchased separately from the associated energy for purposes of RPS compliance. In its recent decision the CPUC authorized the limited use of REC-only transactions for RPS compliance. The CPUC defined a REC-only transaction broadly. Not only does it include a transaction for the procurement of stand–alone RECs, but it includes a transaction for the procurement of both RECs and energy if the delivery of the energy to California customers must rely on intermediary energy transactions. As a result, most of the Utility’s existing contracts with out-of-state renewable generation facilities have been reclassified as REC-only contracts. The CPUC also imposed limits on both the quantity of REC-only transactions that the investor-owned utilities may use for RPS compliance and the price that the utilities may pay for REC-only transactions. The decision sets the maximum price per REC at $50 and limits the quantity of tradable RECs that the utilities can buy to 25% of their annual RPS compliance obligations, subject to certain grandfathering provisions that allow a utility to exceed these limits if the contracts have already been approved by the CPUC. If a utility has contracts pending before the CPUC that would cause them to exceed the quantity limit, the CPUC may still authorize the contract; however, if the utility has already exceeded the REC-only quantity limitation, the utility may be limited in its ability to claim RPS compliance credit for deliveries under the contract. These limits expire on December 31, 2011, unless extended.

The Utility believes that the CPUC’s decision will significantly reduce out-of-state renewable energy procurement opportunities, at least in the near-term. In addition, the limitations on supplies of RPS-eligible procurement created by the CPUC’s decision may ultimately increase the cost of achieving the State’s renewable energy targets. Several parties, including the Utility, have requested modification and rehearing of numerous aspects of this decision. On May 6, 2010, the CPUC voted to stay its earlier decision authorizing the use of tradable RECs until the CPUC has issued a decision on the petitions for modification. The CPUC also imposed a temporary moratorium on CPUC approval of any contracts for REC-only transactions that are signed after May 6, 2010 pending resolution of the petitions. The CPUC has indicated that it will consider the petitions for modification on June 24, 2010.

In addition, on March 12, 2010, the California Air Resources Board (“CARB”), the state agency charged with setting and monitoring emission limits, issued draft regulations that would require all load-serving entities, including the utilities, to meet gradually increasing annual renewable energy targets of 20% in 2012 through 2014, 24% in 2015 through 2017, 28% in 2018 through 2019, and 33% in 2020 and beyond. The draft regulations propose to adopt existing RPS definitions of eligible renewable resources, with some exceptions for publicly-owned utilities. However, the CARB is still considering whether it will allow the unlimited use of stand-alone RECs for compliance or if it will impose some limitation on their use. Under the draft regulations, any failure to meet one of the annual renewable energy targets would be a violation of an emission limitation and subject to penalties. The CARB has stated its intention to issue revised draft regulations by June 3, 2010. The CARB is scheduled to vote on the draft regulations on July 22-23, 2010.

The Utility’s ability to comply with the renewable energy requirements largely depends on the timely development of renewable generation facilities by third party developers. The development of renewable generation facilities by third parties or by the Utility is subject to many risks, including risks related to permitting, financing, technology, fuel supply, environmental matters, and the construction of sufficient transmission capacity.

Water Quality

There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Although the EPA has not yet issued revised regulations, on May 4, 2010, the California Water Resources Control Board ("Water Board") adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state's nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are "wholly out of proportion" to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be "wholly unreasonable" after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the "wholly out of proportion" test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be "wholly unreasonable." If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. (See Note 16 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for more information.) Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Water Board’s policy by December 31, 2024.

Remediation

In February 2010, the Utility began contacting the owners of property located on eight former manufactured gas plant (“MGP”) sites in the Utility’s service territory to offer to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Three of these sites are located in urban, residential areas of San Francisco. Until the Utility’s investigation of these MGP sites is complete, the extent of the Utility’s obligation to remediate is established, and any appropriate remedial actions are determined, the Utility is unable to determine the amounts it may spend in the future to remediate these sites and no amounts have been accrued for these sites (other than investigative costs for some of the sites). Although it is reasonably possible that the Utility will incur losses in the future related to these sites, the Utility is unable to reasonably estimate the amount of such loss. The Utility expects that it will recover 90% of the costs to remediate MGP sites under a ratemaking mechanism established by the CPUC. The Utility will seek to recover remaining costs through insurance. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

OTHER MATTERS

The CPUC has authorized the Utility to recover $2.2 billion in estimated project costs, including $1.8 billion of capital expenditures to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory by the end of 2012. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed the authorized $2.2 billion without a reasonableness review by the CPUC. The remaining 10% will not be recoverable in rates. If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review. As of March 31, 2010, the Utility has incurred $1.47 billion in connection with its SmartMeterTM program.

Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes. These meters will allow the implementation of “dynamic pricing” rates that the CPUC has ordered the Utility to implement. Dynamic pricing rates are designed to reflect the cost of electricity production during periods of high demand.

In late March 2010, the California State Senate established a committee to investigate and review the deployment of the “smart grid” throughout California, focusing on the Utility’s SmartMeterTM program. It is expected that the committee will investigate the integrity and reliability of new metering technologies and the consumer protections in place with respect to billing, disconnection, and real-time pricing. On April 26, 2010, a senior executive of the Utility testified before the committee stating that, of the approximately 5.5 million meters that have been installed, the Utility has determined that 8 meters failed to measure energy usage in line with accepted standards, and another approximately 0.7% of the meters experienced issues involving the meter’s wireless communications, the data storage on the device, or human error at installation. As the senior executive testified, these issues do not necessarily cause high or inaccurate bills. The committee is expected to submit its report to the California Senate, including recommendations for appropriate legislation, by November 30, 2010.

On March 30, 2010, the CPUC selected an independent consultant to assess the Utility’s SmartMeterTM program, including meter and billing accuracy, customer complaints, end-to-end operational processes, and overall program planning and performance. It is expected that the independent CPUC assessment will be completed by August 2010. A class action lawsuit filed in the Superior Court in Bakersfield, California, has been stayed pending the results of the CPUC’s investigation. The class action plaintiffs allege that the new meters, wireless network, and software and billing system, have led to electric bill overcharges.

Finally, on April 15, 2010, a private group filed an application asking the CPUC to impose a moratorium on installation and activation of the new meters pending an evidentiary hearing on the potential health, environmental, and safety impacts of the radio frequency ("RF") technology used in the Utility’s SmartMeterTM program.

The Utility is continuing to install the new meters. The outcome of these matters may have an effect on the Utility’s ability to recover costs to implement advanced metering if the CPUC finds that the costs are not reasonable or are otherwise disallowed. Further, if the Utility is prohibited from continuing to install the new meters, or if the Utility otherwise fails to recognize the expected benefits of its advanced metering infrastructure, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially adversely affected.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electricity transmission, natural gas transportation, and storage; other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risks through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

Price Risk

The Utility is exposed to commodity price risk as a result of its electricity procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility sells most of its capacity based on the volume of gas that the Utility’s customers actually ship, which exposes the Utility to volumetric risk.

The Utility uses value-at-risk to measure the shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

The Utility’s value-at-risk calculated under the methodology described above was $11 million at March 31, 2010. The Utility’s high, low, and average values-at-risk at March 31, 2010 were $17 million, $10 million, and $14 million, respectively.

See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk management activities.

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At March 31, 2010, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would affect net income for the twelve months ended March 31, 2010 by $10 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

The Utility conducts business with counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. If a counterparty failed to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table below). Credit Collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.

The following table summarizes the Utility’s net credit risk exposure to its counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of March 31, 2010 and December 31, 2009:

(in millions)	Gross Credit Exposure Before Credit Collateral (1)		Credit Collateral		Net Credit Exposure (2)		Number of Wholesale Customers or Counterparties >10%		Net Exposure to Wholesale Customers or Counterparties >10%
March 31, 2010	$	192	$	23	$	169		3	$	138
December 31, 2009	$	202	$	24	$	178		3	$	154

(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principals involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 2009 Annual Report. They include:

·	regulatory assets and liabilities;

·	environmental remediation liabilities;

·	asset retirement obligations;

·	accounting for income taxes; and

·	pension and other postretirement plans.

For the period ended March 31, 2010, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and no material changes to the important assumptions underlying the critical accounting estimates.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see “Risk Management Activities” above under Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations).

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of March 31, 2010, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

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

During the quarter ended March 31, 2010, PG&E Corporation made equity contributions totaling $20 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures.

The Utility did not make any sales of unregistered equity securities during the quarter ended March 31, 2010.

Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period	Total Number of Shares Purchased			Average Price Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1 through January 31, 2010		7,437	(1)	$	44.50		-	$	-
February 1 through February 28, 2010		-			-		-		-
March 1 through March 31, 2010		-			-		-		-
Total		7,437		$	44.50		-	$	-

(1) Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock.

During the quarter ended March 31, 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility’s earnings to fixed charges ratio for the three months ended March 31, 2010 was $3.40. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2010 was $3.33. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the three months ended March 31, 2010 was $3.14. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.

ITEM 6. EXHIBITS

3	Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4	Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

*10.1	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010

*10.2	Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.3	Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

***101.INS	XBRL Instance Document

***101.SCH	XBRL Taxonomy Extension Schema Document

***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

***101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

***101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

***

Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

SARA A. CHERRY

Sara A. Cherry

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated: May 7, 2010

EXHIBIT INDEX

3	Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4	Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

10.1 10.2 *10.3	Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

***101.INS	XBRL Instance Document

***101.SCH	XBRL Taxonomy Extension Schema Document

***101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

***101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

***101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

***

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Condensed Consolidated Financial Statementsprint Note 1: Organization and Basis Of Presentationprint Note 2: New and Significant Accounting Policiesprint Note 3: Regulatory Assets, Liabilities, and Balancing Accountsprint Note 4: Debtprint Note 5: Equityprint Note 6: Earnings Per Shareprint Note 7: Derivatives and Hedging Activitiesprint Note 8: Fair Value Measurementsprint Note 9: Related Party Agreements and Transactionsprint Note 10: Resolution Of Remaining Chapter 11 Disputed Claimsprint Note 11: Commitments and Contingenciesprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 5. Other Informationprint Item 6. Exhibitsprint

Customer name	Ticker
Exelon Corporation	EXC
The Williams Companies, Inc.	WMB
WEC Energy Group, Inc.	WEC
Xcel Energy Inc.	XEL

Supplier name	Ticker
Exxon Mobil Corporation	XOM
Waste Management, Inc.	WM
WEC Energy Group, Inc.	WEC
The Southern Company	SO
Rockwell Automation, Inc.	ROK
Parker-Hannifin Corporation	PH
3M Company	MMM
American Electric Power Company, Inc.	AEP

PCG 10-Q Quarter ended March 31, 2010