ex13.htm

SELECTED FINANCIAL DATA
	2008		2007		2006		2005		2004(1)
(in millions, except per share amounts)
PG&E Corporation(2) For the Year
Operating revenues	$	14,628	$	13,237	$	12,539	$	11,703	$	11,080
Operating income		2,261		2,114		2,108		1,970		7,118
Income from continuing operations		1,184		1,006		991		904		3,820
Earnings per common share from continuing operations, basic		3.23		2.79		2.78		2.37		9.16
Earnings per common share from continuing operations, diluted`		3.22		2.78		2.76		2.34		8.97
Dividends declared per common share (3)		1.56		1.44		1.32		1.23		-
At Year-End
Book value per common share(4)	$	24.64	$	22.91	$	21.24	$	19.94	$	20.90
Common stock price per share		38.71		43.09		47.33		37.12		33.28
Total assets		40,860		36,632		34,803		34,074		34,540
Long-term debt (excluding current portion)		9,321		8,171		6,697		6,976		7,323
Rate reduction bonds (excluding current portion)		-		-		-		290		580
Energy recovery bonds (excluding current portion)		1,213		1,582		1,936		2,276		-
Preferred stock of subsidiary with mandatory redemption provisions		-		-		-		-		122
Pacific Gas and Electric Company For the Year
Operating revenues	$	14,628	$	13,238	$	12,539	$	11,704	$	11,080
Operating income		2,266		2,125		2,115		1,970		7,144
Income available for common stock		1,185		1,010		971		918		3,961
At Year-End
Total assets	$	40,537	$	36,310	$	34,371	$	33,783	$	34,302
Long-term debt (excluding current portion)		9,041		7,891		6,697		6,696		7,043
Rate reduction bonds (excluding current portion)		-		-		-		290		580
Energy recovery bonds (excluding current portion)		1,213		1,582		1,936		2,276		-
Preferred stock with mandatory redemption provisions		-		-		-		-		122


(1) Financial data reflects the recognition of regulatory assets provided under the December 19, 2003 settlement agreement entered into among PG&E Corporation, Pacific Gas and Electric Company, and the California Public Utilities Commission to resolve Pacific Gas and Electric Company’s proceeding under Chapter 11 of the U.S. Bankruptcy Code. Pacific Gas and Electric Company’s reorganization under Chapter 11 became effective on April 12, 2004.
(2) Matters relating to discontinued operations are discussed in the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations” and in Note 6 of the Notes to the Consolidated Financial Statements.
(3) The Board of Directors of PG&E Corporation declared a cash dividend of $0.30 per share for the first three quarters of 2005. In the fourth quarter of 2005, the Board of Directors increased the quarterly cash dividend to $0.33 per share. Beginning in the first quarter of 2007, the Board of Directors increased the quarterly cash dividend to $0.36 per share. Beginning in the first quarter of 2008, the Board of Directors increased the quarterly cash dividend to $0.39 per share. The Utility paid quarterly dividends on common stock held by PG&E Corporation and a wholly owned subsidiary aggregating to $589 million in 2008 and $547 million in 2007. See Note 7 of the Notes to the Consolidated Financial Statements.
(4) Book value per common share includes the effect of participating securities. The dilutive effect of outstanding stock options and restricted stock are further disclosed in Note 9 of the Notes to the Consolidated Financial Statements.

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 approximately 5.1 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2008. The Utility had approximately $40.5 billion in assets at December 31, 2008 and generated revenues of approximately $14.6 billion in the 12 months ended December 31, 2008.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility generates revenues mainly through the sale and delivery of electricity and natural gas at rates set by the CPUC and the FERC. Rates are set to permit the Utility to recover its authorized “revenue requirements” from customers. Revenue requirements are designed to allow the Utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in Utility facilities (“rate base”). Changes in any individual revenue requirement affect customer rates and could affect the Utility’s revenues.

This is a combined annual report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 for which the Utility absorbs a majority of the risk of loss or gain. 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 Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in this annual report.

Summary of Changes in Earnings per Common Share and Net Income for 2008

PG&E Corporation’s diluted earnings per common share (“EPS”) for 2008 was $3.63 per share, compared to $2.78 per share for 2007. PG&E Corporation’s 2008 net income increased by approximately $332 million, or 33%, to $1,338 million, compared to 2007 net income of $1,006 million. The increase in diluted EPS and net income in 2008 is primarily due to a settlement of federal tax audits of PG&E Corporation’s consolidated tax returns for 2001 through 2004, which increased net income by $257 million. (Approximately $154 million of this amount has been reported as discontinued operations on PG&E Corporation’s Consolidated Statements of Income because it relates to a former subsidiary of PG&E Corporation, National Energy & Gas Transmission, Inc. (“NEGT”), which PG&E Corporation disposed of in 2004.) The 2008 increase in diluted EPS and net income also includes approximately $98 million representing the Utility’s return on equity (“ROE”) on higher authorized capital investments and approximately $25 million in incentive earnings awarded by the CPUC in 2008 for the Utility’s energy efficiency program performance in 2006 and 2007.

These increases in net income were partially offset by higher operating and maintenance expenses of approximately $50 million due to storm-related outages, natural gas system maintenance activities, and the extended outage to replace the steam generators in one of the nuclear generating units at the Utility’s Diablo Canyon nuclear generating facilities (“Diablo Canyon”).

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation 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, timely recover its authorized costs, 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 and the Utility’s results of operations and financial condition, including:

●	The Outcome of Regulatory Proceedings and the Impact of Ratemaking Mechanisms. Most of the Utility’s revenue requirements are set based on its costs of service in proceedings such as the General Rate Case (“GRC”) filed with the CPUC and transmission owner (“TO”) rate cases filed with the FERC. Unlike the current GRC, which set revenue requirements for a four-year period (2007 through 2010), it is expected that the next GRC will set revenue requirements for the Utility’s electric and natural gas distribution operations and electric generation operations for a three-year period (2011 through 2013). From time to time, the Utility also files separate applications requesting the CPUC or the FERC to authorize additional revenue requirements for specific capital expenditure projects, such as new power plants, gas or electric transmission facilities, installation of an advanced metering infrastructure, and reliability or system infrastructure improvements. The Utility’s revenues will also be affected by incentive ratemaking, including the CPUC’s customer energy efficiency shareholder incentive mechanism. (See “Regulatory Matters” below.) In addition, the CPUC has authorized the Utility to recover 100% of its reasonable electric fuel and energy procurement costs and has established a timely rate adjustment mechanism to recover such costs. As a result, the Utility’s revenues and costs can be affected by volatility in the prices of natural gas and electricity. (See “Risk Management Activities” below.)

●	Capital Structure and Return on Common Equity. The Utility’s current CPUC-authorized capital structure includes a 52% common equity component. The CPUC has authorized the Utility to earn an ROE of 11.35% on the equity component of its electric and natural gas distribution and electric generation rate base. The Utility’s capital structure is set until 2011, and its cost of capital components, including an 11.35% ROE, will only be changed before 2011 if the annual automatic adjustment mechanism established by the CPUC is triggered. If the 12-month October through September average yield for the Moody’s Investors Service (“Moody’s”) utility bond index increases or decreases by more than 1% as compared to the applicable benchmark, the Utility can adjust its authorized cost of capital effective on January 1 of the following year. The 12-month October 2007 through September 2008 average yield of the Moody’s utility bond index did not trigger a change in the Utility’s authorized cost of capital for 2009. The Utility can also apply for an adjustment to either its capital structure or cost of capital at any time in the event of extraordinary circumstances.


●	The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses, as well as to earn an 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 authorized rate of return and the amount of PG&E Corporation’s net income available for shareholders. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense, but does not recover revenues to offset these expenses or earn an ROE, until the capital expenditures are added to rate base in future rate cases. Items that could cause higher expenses than provided for in the last GRC primarily relate to the Utility’s efforts to maintain the aging infrastructure of its electric and natural gas systems, to improve the reliability and safety of its electric and natural gas systems, higher debt interest rates, and technology infrastructure and support. In addition, the Utility intends to accelerate the work associated with system-wide gas leak surveys and targets completing this work in a little more than a year. This is expected to result in additional costs. (See “Results of Operations” below.) The Utility continually seeks to achieve operational efficiencies and improve reliability while creating future sustainable cost-savings to offset these higher anticipated expenses. The Utility also seeks to make the amount and timing of its capital expenditures consistent with budgeted amounts and timing.

●	The Availability and Terms of Debt and Equity Financing. The amount and timing of the Utility’s future financing needs will depend on various factors, some of which include the conditions in the capital markets, the amount and timing of scheduled principal and interest payments on long-term debt, the amount and timing of planned capital expenditures, and the amount and timing of interest payments related to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 15 of the Notes to the Consolidated Financial Statements.) The amount of the Utility’s short-term financing will vary depending on the level of operating cash flows, seasonal demand for electricity and natural gas, volatility in electricity and natural gas prices, and collateral requirements related to price risk management activity, among other factors. The Utility has continued to have access to the capital markets despite the recent financial turmoil and economic downturn, although interest rates on the Utility’s short-term and long-term debt have increased. For example, the Utility’s $600 million principal amount of 10-year senior notes, issued on October 21, 2008, bears interest at 8.25% compared to the Utility’s $700 million principal amount of 10-year senior notes, issued in December 2007 and March 3, 2008 that bear interest at 5.625%. In addition, the Utility’s commercial paper issuance rate reached a high of 7.3% on September 30, 2008 and a low of 1.2% as of December 26, 2008. In order to maintain the Utility’s CPUC-authorized capital structure, PG&E Corporation will be required to contribute equity to the Utility. The timing and amount of these future equity contributions will affect the timing and amount of any future equity or debt issuances by PG&E Corporation. (See “Liquidity and Financial Resources” below.)

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

FORWARD-LOOKING STATEMENTS

This combined annual report and the letter to shareholders that accompanies it, contain 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 liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, estimated future cash flows and the level of future equity or debt issuances, and 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 the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets, including the ability of the Utility and its counterparties to post or return collateral;

●	the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and 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, including the development of alternative energy sources, or other reasons;

●	operating performance of Diablo Canyon, the availability of nuclear fuel, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

●	whether the Utility can maintain the cost savings it has recognized from operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures;

●	whether the Utility incurs substantial expense to improve the safety and reliability of its electric and natural gas systems;

●	whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives the Utility may earn in a timely manner;

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

●	the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;


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

●	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, especially given the recent deteriorating conditions in the economy and financial markets;

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

●	the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; 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 and the Utility’s future financial condition and results of operations see the discussion in the section entitled “Risk Factors” below. 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 Consolidated Statements of Income for 2008, 2007, and 2006:

	Year ended December 31,
	2008			2007			2006
(in millions)
Utility
Electric operating revenues	$	10,738		$	9,481		$	8,752
Natural gas operating revenues		3,890			3,757			3,787
Total operating revenues		14,628			13,238			12,539
Cost of electricity		4,425			3,437			2,922
Cost of natural gas		2,090			2,035			2,097
Operating and maintenance		4,197			3,872			3,697
Depreciation, amortization, and decommissioning		1,650			1,769			1,708
Total operating expenses		12,362			11,113			10,424
Operating income		2,266			2,125			2,115
Interest income		91			150			175
Interest expense		(698	)		(732	)		(710	)
Other income (expense), net(1)		14			38			(7	)
Income before income taxes		1,673			1,581			1,573
Income tax provision		488			571			602
Income available for common stock	$	1,185		$	1,010		$	971
PG&E Corporation, Eliminations, and Other(2)
Operating revenues	$	-		$	(1	)	$	-
Operating expenses		5			10			7
Operating loss		(5	)		(11	)		(7	)
Interest income		3			14			13
Interest expense		(30	)		(30	)		(28	)
Other expense, net		(32	)		(9	)		(6	)
Loss before income taxes		(64	)		(36	)		(28	)
Income tax benefit		(63	)		(32	)		(48	)
Income (loss) from continuing operations		(1	)		(4	)		20
Discontinued operations(3)		154			-			-
Net income (loss)	$	153		$	(4	)	$	20
Consolidated Total
Operating revenues	$	14,628		$	13,237		$	12,539
Operating expenses		12,367			11,123			10,431
Operating income		2,261			2,114			2,108
Interest income		94			164			188
Interest expense		(728	)		(762	)		(738	)
Other income (expense), net(1)		(18	)		29			(13	)
Income before income taxes		1,609			1,545			1,545
Income tax provision		425			539			554
Income from continuing operations		1,184			1,006			991
Discontinued operations(3)		154			-			-
Net income	$	1,338		$	1,006		$	991


(1) Includes preferred stock dividend requirement as other expense.
(2) PG&E Corporation eliminates all intercompany transactions in consolidation.
(3) Discontinued operations reflect items related to PG&E Corporation’s former subsidiary NEGT. See Note 6 of the Notes to the Consolidated Financial Statements for further discussion.

Utility

In the Utility’s last GRC, the CPUC authorized the Utility’s revenue requirements for 2007 through 2010 for its basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. Effective January 1, 2007, the CPUC authorized the Utility to collect annual revenue requirements of approximately $2.9 billion for electricity distribution, approximately $1.0 billion for natural gas distribution, and approximately $1.0 billion for electricity generation operations. The CPUC also authorized annual increases (known as attrition adjustments) to authorized revenues of $125 million in 2008, 2009, and 2010, to help avoid a reduction in earnings in years between GRCs due to inflation, increases in invested capital, and other similar items. In addition, the CPUC authorized a one-time additional adjustment of $35 million in 2009 for the cost of a second refueling outage at the Utility’s Diablo Canyon nuclear power plant. The Utility’s next GRC will be held in 2010 to establish revenue requirements beginning in 2011. The Utility expects to submit a draft of its GRC application and revenue requirement request to the CPUC staff in July or August of 2009.

Revenue requirements by the CPUC are independent, or “decoupled,” from the volume of sales, which eliminates volatility in the amount of revenues earned by the Utility due to fluctuations in customer demand. As a result, lower customer demand caused by the economic downturn has not and is not expected to have a material adverse impact on the Utility’s results of operations or financial condition. The Utility uses revenue or sales regulatory balancing accounts to accumulate differences between revenues and the Utility’s revenue requirements authorized by the CPUC. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.

The CPUC also conducts a proceeding to determine the Utility’s authorized capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rate of return (including an ROE) that the Utility may earn on the components of capital structure used to finance its electricity and natural gas distribution and electricity generation assets. For 2008 through 2010, the CPUC has authorized a capital structure that includes a 52% equity component. For 2009, the CPUC has authorized an 11.35% ROE for the Utility. The Utility’s rates of return will remain at current levels through 2010, unless the CPUC’s annual adjustment mechanism is triggered. The CPUC will review the Utility’s capital structure and cost of capital again for possible reset beginning in 2011.

The CPUC also authorizes the Utility’s revenue requirements and associated rates for the Utility’s natural gas transmission and storage services. In September 2007, the CPUC approved a multi-party settlement agreement, known as the Gas Accord IV, to establish the Utility’s natural gas transmission and storage rates and associated revenue requirements for 2008 through 2010. The Gas Accord IV establishes a 2008 natural gas transmission and storage revenue requirement of $446 million, with slight increases in 2009 and 2010. Although most of the Utility’s natural gas revenues are collected through balancing accounts, most of the Utility’s transportation service-only revenue is based on actual volumes of natural gas sold and therefore is subject to volumetric risk.

The Utility is also authorized to collect revenue requirements from customers to fund public purpose, demand response, and energy efficiency programs, including the California Solar Initiative program and the Self-Generation Incentive program. In addition, the Utility is authorized to collect revenue requirements to recover its capital costs for projects such as new Utility-owned generation resource facilities and the installation of advanced meters for its electric and gas customers. Finally, incentive ratemaking mechanisms allow rates to be adjusted to reflect incentive awards earned by the Utility, or obligations incurred by the Utility, to the extent certain benchmarks or goals are or are not met.

The FERC sets the Utility’s rates for electric transmission services. The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility can recover for its electric transmission costs is the TO rate case. The Utility is typically able to set the schedule for its TO rate cases and, if accepted by the FERC, to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. The Utility’s recovery of its FERC-authorized electric transmission revenue requirements can vary with the volume of electricity sales. As a result, lower customer demand caused by the economic downturn could affect the Utility’s results of operations or financial condition. (See “Regulatory Matters – Electric Transmission Owner Rate Cases” below.)

The Utility’s rates reflect the revenue requirement components authorized by the CPUC and the FERC. In annual true-up proceedings, the Utility requests the CPUC to authorize an adjustment to electric and gas rates 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. Generally, these rate changes become effective on the first day of the following year. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

The following presents the Utility’s operating results for 2008, 2007, and 2006.

Electric Operating Revenues

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, the Utility relies on electricity provided under long-term contracts entered into by the California Department of Water Resources (“DWR”) to meet a material portion of the Utility’s customers’ demand (“load”). The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and procurement and for electric transmission and distribution services, as well as amounts charged to customers to recover the costs of public purpose programs, energy efficiency programs, and demand side management.

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

	2008			2007			2006
(in millions)
Electric operating revenue	$	12,063		$	11,710		$	10,871
DWR pass-through revenue(1)		(1,325	)		(2,229	)		(2,119	)
Utility electric operating revenue	$	10,738		$	9,481		$	8,752

Utility electricity sales (in millions of kWh) (2)	74,783	64,986	64,725


(1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Consolidated Statements of Income. (2)These volumes exclude electricity provided by DWR.

The Utility’s electric operating revenues increased by approximately $1,257 million, or approximately 13%, in 2008 compared to 2007 mainly due to the following factors:

●	Electricity procurement costs passed through to customers increased by approximately $976 million, primarily due to an increase in the volume of power purchased by the Utility following the DWR’s termination of a power purchase contract in December 2007 and during the extended scheduled outage at Diablo Canyon in 2008. (See “Cost of Electricity” below.)

●	Electric operating revenues to fund public purpose and energy efficiency programs increased by approximately $266 million, primarily due to an increase in expenses for these programs. (See “Operating and Maintenance” below.)

●	Base revenue requirements increased by approximately $103 million, as a result of attrition adjustments as authorized in the 2007 GRC.

●	Electric transmission revenues increased by approximately $56 million, primarily due to an increase in rates as authorized in the current TO rate case.

●	Electric operating revenues increased by approximately $35 million, the portion of the incentive award approved by the CPUC in December 2008 that is attributable to the Utility’s 2006 and 2007 electricity energy efficiency programs.

●	Other electric operating revenues increased by approximately $119 million, primarily due to increases in revenue requirements to recover costs related to the Diablo Canyon steam generator replacement project and revenue requirements to fund the SmartMeterTM advanced metering project. (See “Capital Expenditures” below.)

These increases were partially offset by a decrease of approximately $276 million representing the amount of revenue collected during the comparable periods in 2007 for payment of principal and interest on the rate reduction bonds (“RRBs”) that matured in December 2007 and approximately $22 million, representing a reduction in the amount of revenue collected for payment of the energy recovery bonds (“ERBs”) due to their declining balance.

The Utility’s electric operating revenues increased by approximately $729 million, or approximately 8%, in 2007 compared to 2006 mainly due to the following factors:

●	Electricity procurement costs, which are passed through to customers, increased by approximately $742 million. (See “Cost of Electricity” below.)

●	The 2007 GRC increased 2007 base revenue requirements by approximately $231 million.

●	Revenues from public purpose programs, including the California Solar Initiative program, increased by approximately $141 million. (See Note 3 of the Notes to the Consolidated Financial Statements.)

●	Electric transmission revenues increased by approximately $74 million, including an increase in revenues as authorized in the TO rate case.

These increases were partially offset by the following:

●	Transmission revenues decreased by approximately $200 million primarily due to a decrease in revenues received under the Utility’s reliability must run (“RMR”) agreements with the CAISO. During 2006, the CPUC adopted rules to implement state law requirements for California investor-owned utilities to meet resource adequacy requirements, including rules to address local transmission system reliability issues. As the utilities fulfill their responsibilities to meet these requirements, the number of RMR agreements with the CAISO and the associated revenues and costs will decline. (See “Cost of Electricity” below.)

●	Revenues in 2006 included approximately $136 million for recovery of scheduling coordinator costs the Utility incurred from April 1998 through December 2005, as ordered by the FERC. No similar amount was recognized in 2007.

●	Revenues in 2006 included approximately $65 million for recovery of net interest related to Disputed Claims for the period between the effective date of the Utility’s plan of reorganization under Chapter 11 in April 2004 and the first issuance of the ERBs in February 2005, and for certain energy supplier refund litigation costs upon completion of the CPUC’s 2005 Annual Electric True-up verification audit. No similar amount was recognized in 2007.

●	Other electric operating revenues decreased by approximately $58 million, reflecting a pension revenue requirement that was recovered in 2006 but not in 2007.

The Utility’s electric operating revenues for 2009 and 2010 are expected to increase as authorized by the CPUC in the 2007 GRC. The Utility’s electric operating revenues for future years are also expected to increase as authorized by the FERC in the TO rate cases. In addition, the Utility expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including capital expenditures for the new Utility-owned generation projects and the SmartMeterTM advanced metering project. Revenues would also increase to the extent the CPUC approves the Utility’s proposal 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 result in increased electric operating revenues. Future electric operating revenues are impacted by changes in the Utility’s electricity procurement costs as discussed under “Cost of Electricity” below. Finally, the Utility may recognize additional incentive revenues to the extent it achieves the CPUC’s energy efficiency goals.

Cost of Electricity

The Utility’s cost of electricity includes the cost of purchased power and the cost of fuel used by its generation facilities or 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 11 and 12 of the Notes to the Consolidated Financial Statements for further information.) The 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 Consolidated Statements of Income. The Utility’s cost of purchased power and the cost of fuel used in Utility-owned generation are passed through to customers.

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet its load and sell the excess electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. The Utility's net proceeds from the sale of surplus electricity are recorded as a reduction to the 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:

	2008			2007			2006
(in millions)
Cost of purchased power	$	4,516		$	3,443		$	3,114
Proceeds from surplus sales allocated to the Utility		(255	)		(155	)		(343	)
Fuel used in own generation		164			149			151
Total cost of electricity	$	4,425		$	3,437		$	2,922
Average cost of purchased power per kWh	$	0.088		$	0.089		$	0.084
Total purchased power (in millions of kWh)		51,100			38,828			36,913

The Utility’s total cost of electricity increased by approximately $988 million, or 29%, in 2008 compared to 2007. This increase was primarily driven by increases in the total volume of purchased power of 12,272 million kilowatt-hours (“kWh”), or 32%. Following the DWR’s termination of its power purchase agreement with Calpine Corporation in December 2007, the volume of power provided by the DWR to the Utility’s customers decreased by 8,784 million kWh. As a result, the Utility was required to increase its purchases of power from third parties to meet customer load. In addition, the Utility increased the volume of power it purchased in 2008 from third parties during the scheduled extended outage at Diablo Canyon Unit 2 to replace the four steam generators. The extended outage lasted from February through mid-April 2008, in comparison to the planned refueling outage of Diablo Canyon Unit 1 that occurred entirely in May 2007. (See “Capital Expenditures” below.) Increases in market prices during the first half of 2008 were entirely offset by a decrease in market prices during the second half of 2008 and hedging activity.

The Utility’s total cost of electricity increased by approximately $515 million, or 18%, in 2007 compared to 2006. This increase was primarily driven by a 6% increase in the average cost of purchased power. The average cost of purchased power increased $0.005 per kWh from 2006 to 2007 primarily due to higher energy payments made to qualifying facilities after their five-year fixed price contracts expired during the summer of 2006. In addition, the Utility increased the volume of its third party power purchases primarily due to a reduction in the availability of lower-cost hydroelectric power resulting from less than average precipitation during 2007 as compared to 2006. These increases were partially offset by a decrease in charges imposed by the CAISO.

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. (See Note 17 of the Notes to the Consolidated Financial Statements.) The Utility will incur higher costs to purchase power during the extended refueling outage that began at Diablo Canyon Unit 1 in January 2009 to replace the steam generators. (See “Capital Expenditures” below.) In addition, the output from the Utility’s hydroelectric generation facilities is dependent on levels of precipitation and could impact the volume of purchased power. Volatility in natural gas prices will also impact the Utility’s cost of electricity in 2009 and future years.

The Utility’s future cost of electricity also may be affected by federal or state legislation or rules which may be adopted to regulate the emissions of greenhouse gases 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 greenhouse gas emissions reduction law is implemented. (See “Risk Factors” below).

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout California 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 Utility’s natural gas customers consist of two categories: residential and smaller commercial customers known as “core” customers, and industrial and larger commercial customers known as “non-core” customers. The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from either the Utility or alternate energy service providers. The Utility does not procure natural gas for non-core customers. When the Utility provides both transportation and natural gas supply, the Utility refers to the combined service as bundled natural gas service. In 2008, core customers represented over 99% of the Utility’s total customers and approximately 37% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total customers and approximately 63% of its total natural gas deliveries.

The Utility’s natural gas operating revenues include bundled natural gas revenues and transportation service-only revenues. Although the Utility’s bundled natural gas revenues are collected through balancing accounts, most of the Utility’s transportation service-only revenues are based on actual volumes sold and therefore are subject to volumetric risk. (Most of the Utility’s intrastate natural gas transmission capacity has not been sold under long-term contracts that provide for recovery of all fixed costs through the collection of fixed reservation charges.) As a result, the Utility’s natural gas operating revenues may fluctuate based on the volume of gas transported. (See the “Natural Gas Transportation and Storage” section in “Risk Management Activities” below.)

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

	2008		2007		2006
(in millions)
Bundled natural gas revenues	$	3,557	$	3,417	$	3,472
Transportation service-only revenues		333		340		315
Total natural gas operating revenues	$	3,890	$	3,757	$	3,787
Average bundled revenue per Mcf(1) of natural gas sold	$	13.52	$	12.94	$	12.91
Total bundled natural gas sales (in millions of Mcf)		263		264		269

(1) One thousand cubic feet

The Utility’s natural gas operating revenues increased by approximately $133 million, or 4%, in 2008 compared to 2007. The increase in natural gas operating revenues primarily reflects an overall increase in the cost of natural gas of approximately $55 million (see “Cost of Natural Gas” below), an increase in base revenue requirements as a result of attrition adjustments authorized in the 2007 GRC of approximately $22 million, an increase in natural gas revenue requirements to fund the SmartMeterTM advanced metering project of approximately $25 million, and an increase of $24 million in natural gas revenues to fund energy efficiency public purpose program. The increase in natural gas operating revenues also includes $7 million, the portion of the incentive award approved by the CPUC in December 2008 that is attributable to the Utility’s 2006 and 2007 natural gas energy efficiency programs.

The Utility’s natural gas operating revenues decreased by approximately $30 million, or less than one percent, in 2007 compared to 2006. This was primarily due to a decrease in the cost of natural gas, which is passed through to customers. This decrease was partially offset by the increased base revenue requirements authorized in the 2007 GRC and an increase in revenue requirements relating to the SmartMeterTM project.

Future natural gas operating revenues will be impacted by changes in the cost of natural gas, the Utility’s gas transportation rates, natural gas throughput volume, and other factors. For 2008 through 2010, the Gas Accord IV settlement agreement provides for an overall modest increase in the revenue requirements and rates for the Utility’s gas transmission and storage services. In addition, the Utility’s natural gas operating revenues for distribution are expected to increase through 2010 as a result of revenue requirement increases authorized by the CPUC in the 2007 GRC. Finally, the Utility may recognize incentive revenues to the extent it achieves the CPUC’s energy efficiency goals.

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas and transportation costs on interstate pipelines and intrastate pipelines, but excludes the transportation costs for non-core customers, which are included in Operating and Maintenance expense in the Consolidated Statements of Income. The Utility’s cost of gas also includes realized gains and losses on price risk management activities. (See Note 11 and 12 of the Notes to the Consolidated Financial Statements for further information.) The Utility’s cost of gas is passed through to customers.

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

	2008		2007		2006
(in millions)
Cost of natural gas sold	$	1,955	$	1,859	$	1,958
Cost of natural gas transportation		135		176		139
Total cost of natural gas	$	2,090	$	2,035	$	2,097
Average cost per Mcf of natural gas sold	$	7.43	$	7.04	$	7.28
Total natural gas sold (in millions of Mcf)		263		264		269

The Utility’s total cost of natural gas increased by approximately $55 million, or 3%, in 2008 compared to 2007, primarily due to increases in the average market price of natural gas purchased. The increase was partially offset by an approximately $23 million refund the Utility received as part of a settlement with TransCanada’s Gas Transmission Northwest Corporation for 2007 gas transmission capacity rates.

The Utility's total cost of natural gas decreased by approximately $62 million, or 3%, in 2007 compared to 2006, primarily due to a decrease in the average market price of natural gas purchased of approximately $0.24 per Mcf, or 3%. Average market prices were significantly higher in the beginning of 2006 as damages to production facilities caused by severe weather reduced natural gas supply. In addition, the price of natural gas declined due to a relatively mild hurricane season in 2007 as compared to industry forecasts, resulting in no material supply disruptions, and a relatively large amount of natural gas in storage across the nation.

The Utility’s future cost of natural gas will be impacted by the market price of natural gas, and changes in customer demand. In addition, the Utility’s future cost of gas also may be affected by federal or state legislation or rules to regulate the emissions of greenhouse gases 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 accounts and service expenses, public purpose program expenses, and administrative and general expenses.

The Utility’s operating and maintenance expenses increased by approximately $325 million, or 8%, in 2008 compared to 2007. Expenses increased mainly due to the following factors:

●	Public purpose program and customer energy efficiency incentive program expenses increased by approximately $290 million primarily due to increased customer participation and increased marketing of new and existing programs, including the California Solar Initiative program and the Self-Generation Incentive Program. Of these changes, approximately $266 million were recovered in electric operating revenues and $24 million were recovered in natural gas operating revenues. Expenses related to public purpose programs and energy efficiency programs are generally fully recoverable and differences between costs and revenues in a particular period are due to timing differences.

●	Employee benefit costs increased by approximately $59 million, primarily reflecting unrealized losses in the long-term disability plan trust due to the decline in the market value of trust investments as financial markets deteriorated in the second half of 2008.


●	Costs increased by approximately $38 million for the repair and restoration of electric distribution systems and to respond to customer inquiries following the January 2008 winter storm. Of the approximately $38 million in costs, the CPUC has authorized the Utility to recover approximately $8 million from customers. There was no similar storm in the same period in 2007.

●	Labor costs increased by approximately $39 million to conduct expanded natural gas leak surveys in parts of the Utility’s service territory and to make related repairs in an effort to improve operating and maintenance processes in the Utility’s natural gas system.

●	Maintenance costs increased by approximately $10 million due to the longer duration of the planned outage of Diablo Canyon Unit 2 in 2008 compared to the Diablo Canyon Unit 1 outage in 2007.


These increases were partially offset by the following factors:

●	Cost reductions of approximately $60 million, reflecting reductions in labor, postage, consulting, advertising, and other costs.

●	Costs related to injuries and damages decreased by approximately $16 million, as compared to 2007 when the Utility increased its reserves for such matters.

●	Costs related to software maintenance contracts decreased by $10 million.

●	Costs decreased by approximately $12 million as compared to 2007 when the CPUC ordered the Utility to make customer refunds related to billing practices.

●	Costs decreased by approximately $13 million as compared to 2007 when the Utility increased the liability related to compensation for employees’ missed meals.

During 2007, the Utility’s operating and maintenance expenses increased by approximately $175 million, or 5%, compared to 2006, mainly due to the following factors:

●	Payments for customer assistance and public purpose programs, such as the California Solar Initiative program, increased by approximately $99 million primarily due to increased customer participation in these programs.

●	The Utility’s distribution expenses increased by approximately $40 million primarily due to service costs related to the creation of new dispatch and scheduling stations and vegetation management in the Utility’s service territory.

●	Billing and collection costs increased by approximately $33 million.

●	Labor costs increased by approximately $33 million primarily due to higher employee headcount and increased base salaries and incentive compensation.

●	Costs of outside consulting services and contracts primarily related to information systems increased by approximately $22 million.

●	Approximately $22 million was accrued for missed meal payments to certain Utility employees covered under collective bargaining agreements.

●	Workers’ compensation expense increased by approximately $20 million due to an increase in the Utility’s accrual for its workers’ compensation obligation (caused by a decrease to the applicable discount rate used to calculate the obligation) and higher than expected workers’ compensation claims.

●	Property taxes increased by approximately $12 million due to electric plant growth, tax rate increases, and increases in assessed values in 2007.

●	In 2006, the Utility reduced its accrual for long-term disability benefits by approximately $11 million reflecting changes in sick leave eligibility rules, but there was no similar adjustment in 2007.

These increases were offset by the following factors:

●	Pension expense decreased by approximately $57 million consistent with the annual pension contribution, as approved by the CPUC in June 2006.

●	Severance costs in 2007 were approximately $30 million lower than in 2006.

●	In 2006, the Utility increased its environmental remediation accrual by approximately $30 million due to changes in the California Regional Water Quality Control Board’s imposed remediation levels, but there was no similar adjustment in 2007.

Operating and maintenance expenses are influenced by wage inflation; benefits; property taxes; the timing and length of Diablo Canyon refueling outages; storms, wild land fires, and other events causing outages and damages in the Utility’s service territory; environmental remediation costs; legal costs; material costs; and various other administrative and general expenses. In addition, the Utility expects to incur higher labor costs under its recently renegotiated collective bargaining agreements. The Utility anticipates that it will incur higher costs in the future to operate and maintain its aging infrastructure and to improve operating and maintenance processes used in its natural gas system. (See “Risk Factors” below.) In particular, the Utility intends to accelerate the work associated with system-wide gas leak surveys and targets completing this work in little more than a year. In general, the Utility completes a survey of its entire gas distribution system every five years by surveying 20% of its system each year. The Utility forecasts it will spend up to $100 million more in 2009 to perform the gas leak surveys and associated remedial work on an accelerated schedule. The Utility also expects that it will incur higher expenses in future periods to obtain or comply with permitting requirements, including costs associated with renewed 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, amortization, and decommissioning expenses decreased by approximately $119 million, or 7% in 2008 compared to 2007, mainly due to decreases in amortization expense of approximately $261 million related to the RRB regulatory asset. The RRB regulatory asset was fully recovered through rates when the RRBs matured in December 2007; therefore no amortization has been recorded in 2008. These decreases were partially offset by increases to depreciation expense of approximately $142 million primarily due to capital additions and depreciation rate changes as authorized in the 2007 GRC and the current TO rate case.

The Utility’s depreciation, amortization, and decommissioning expenses increased by approximately $61 million, or 4%, in 2007 compared to 2006, mainly due to an approximately $121 million increase in depreciation expense as a result of depreciation rate changes and capital additions in 2007 authorized by the 2007 GRC decision. This was partially offset by the following factors:

●	The Utility recorded lower decommissioning expense of approximately $53 million as a result of the 2007 GRC decision to refund over-collections of decommissioning expense to customers.

●	Other depreciation, amortization, and decommissioning expenses, including amortization of the ERB regulatory asset, decreased by $7 million.

The Utility’s depreciation, amortization, and decommissioning expenses in subsequent years are expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the 2007 GRC decision and future TO rate cases.

Interest Income

The Utility’s interest income decreased by approximately $59 million, or 39%, in 2008 as compared to 2007 when the Utility received approximately $16 million in interest income on a federal tax refund. In addition, there was a decrease of $37 million in interest income, primarily due to lower interest rates earned on funds held in escrow related to disputed claims and a lower escrow balance reflecting settlements of disputed claims. (See Note 15 of the Notes to the Consolidated Financial Statements.) There was an additional decrease of approximately $6 million in other interest income.

The Utility’s interest income decreased by approximately $25 million, or 14%, in 2007 compared to 2006. In 2006, the FERC approved the Utility’s recovery of scheduling coordinator costs it had previously incurred, including interest of approximately $47 million. No similar amount was recognized in 2007. This decrease was partially offset by the receipt of approximately $16 million in 2007 related to the settlement of refund claims made against electricity suppliers for overcharges incurred during the 2000-2001 California energy crisis. (See Note 15 of the Notes to the Consolidated Financial Statements.) In addition, other interest income, including interest income associated with certain balancing accounts, increased by approximately $6 million.

The Utility’s interest income in 2009 and future periods will be primarily affected by changes in the balance held in escrow related to disputed claims and changes in interest rate levels.

Interest Expense

The Utility’s interest expense decreased by approximately $34 million, or 5%, in 2008 as compared to 2007. Interest expense decreased primarily due to the following factors:

●	Interest expense decreased by approximately $29 million primarily due to lower FERC interest rates accrued on the liability for disputed claims.
●	Interest expense decreased by approximately $26 million due to the reduction in the outstanding balance of ERBs and the maturity of the RRBs in December 2007.


●	Interest expense on pollution control bonds decreased by approximately $20 million due to the repurchase of auction rate pollution control bonds in March and April 2008. The Utility partially refunded these bonds in September and October 2008. Additionally, interest expense decreased due to lower interest rates on outstanding variable rate pollution control bonds.

●	Interest expense decreased by approximately $24 million primarily due to lower interest rates affecting various balancing accounts.

●	Other interest expense decreased by approximately $14 million primarily due to a lower balance of borrowings outstanding under the Utility’s $2 billion revolving credit facility and lower commercial paper interest rates.

These decreases were partially offset by additional interest expense of approximately $79 million in 2008 primarily related to $1.8 billion in senior notes that were issued in March, October, and November 2008.

In 2007, the Utility’s interest expense increased by approximately $22 million, or 3%, compared to 2006, including approximately $19 million of higher interest expense related to disputed claims as a result of an increase in the FERC-mandated interest rate (see Note 15 of the Notes to the Consolidated Financial Statements). In addition, interest expense related to $1.2 billion in long-term debt issued in 2007 and variable rate pollution control bond loan agreements increased by approximately $40 million. These increases were partially offset by a reduction of approximately $34 million in the interest expense related to the declining balance of the ERBs and RRBs. In addition, other interest expense, including lower interest expense on balances in certain regulatory balancing accounts, decreased approximately $3 million.

The Utility’s interest expense in 2009 and future periods will be impacted by changes in interest rates, as well as by 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 for further discussion).

Other Income (Expense), Net

The Utility’s other income (expense), net decreased by approximately $24 million, or 63%, in 2008 compared to 2007. This decrease is primarily due to an increase in costs of approximately $24 million that was spent in 2008 to oppose the statewide initiative related to renewable energy (Proposition 7) and the City of San Francisco’s municipalization efforts.

Income Tax Expense

The Utility’s income tax expense decreased by approximately $83 million, or 15%, in 2008 compared to 2007. The effective tax rates were 28.9% and 35.8% for 2008 and 2007, respectively. The decrease in the effective tax rate for 2008 was primarily due to a settlement of federal tax audits for the tax years 2001 through 2004 and approval by the Internal Revenue Service (“IRS”) of the Utility’s change in accounting method for the capitalization of indirect service costs for tax years 2001 through 2004. (See “Tax Matters” below and Note 10 of the Notes to the Consolidated Financial Statements for a discussion of “Income Taxes”.)

The Utility’s income tax expense decreased by approximately $31 million, or 5%, in 2007 compared to 2006, primarily due to a decrease of approximately $29 million as a result of fixed asset related tax deductions, due to an increase in tax-deductible decommissioning expense in 2007 compared to 2006. The effective tax rates were 35.8% and 38.0% for 2007 and 2006, respectively.

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 is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating revenues and expenses in 2008 compared to 2007 and 2007 compared to 2006.

Other Expense, Net

PG&E Corporation's other expense increased by approximately $23 million, or 255%, in 2008 compared to 2007, primarily due to an increase in investment losses in the rabbi trusts related to the non-qualified deferred compensation plans.

Income Tax Benefit

PG&E Corporation’s income tax benefit increased by approximately $31 million, or 97%, in 2008 compared to 2007, primarily due to a settlement of federal tax audits for the tax years 2001 through 2004.

Discontinued Operations

In the fourth quarter of 2008, PG&E Corporation reached a settlement of federal tax audits of tax years 2001 through 2004 and recognized after-tax income of approximately $257 million. Approximately $154 million of this amount relates to losses incurred and synthetic fuel tax credits claimed by PG&E Corporation’s former subsidiary NEGT. As a result, PG&E Corporation recorded $154 million in income from discontinued operations in 2008. (See Note 6 of the Notes to the Consolidated Financial Statements for further discussion.)

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 long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures, and relies on short-term debt to fund temporary financing needs.

The CPUC has authorized the Utility to incur $2 billion of short-term debt for working capital fluctuations and energy procurement-related purposes, and an additional $500 million for certain CPUC-defined extraordinary events. The recent disruption in the capital markets has made it challenging for companies to access the markets for commercial paper and new credit facilities. Notwithstanding this volatility, the Utility has continued to have access to the commercial paper market, albeit at higher prices and with shorter duration at times.

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

The following table summarizes PG&E Corporation’s and the Utility’s cash positions:

	December 31,
(in millions)	2008		2007
PG&E Corporation	$	167	$	204
Utility		52		141
Total consolidated cash and cash equivalents		219		345
Utility restricted cash		1,290		1,297
Total consolidated cash, including restricted cash	$	1,509	$	1,642

Restricted cash primarily consists of cash held in escrow pending the resolution of the remaining disputed claims filed in the Utility’s reorganization proceeding under Chapter 11. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in money market funds.

Credit Facilities and Short-Term Borrowings

The Utility has a $2 billion revolving credit facility and PG&E Corporation has a $200 million revolving credit facility. Each of PG&E Corporation’s and the Utility’s revolving credit facilities include commitments from a well-diversified syndicate of lenders. Neither credit facility permits the lenders to refuse funding a draw solely due to the occurrence of a “material adverse effect” as defined in the facilities. No single lender’s commitment represents more than 11% of total borrowing capacity under either facility. As of December 31, 2008, the commitment from Lehman Brothers Bank, FSB (“Lehman Bank”) represented approximately $13 million, or 7%, of the total borrowing capacity under PG&E Corporation’s $200 million revolving credit facility and approximately $60 million, or 3%, of the Utility’s $2.0 billion revolving credit facility. Lehman Bank has failed to fund its portion of borrowings under the Utility’s revolving credit facility since September 2008 and neither the Utility nor PG&E Corporation expects that Lehman Bank will fund any future borrowings or letter of credit draws.

The following table summarizes PG&E Corporation and the Utility’s short-term borrowings and outstanding credit facilities at December 31, 2008:

(in millions)	At December 31, 2008
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	$	200	(1)	$	-	$	-	$	-	$	200
Utility	Revolving credit facility	February 2012		2,000	(2)		287		-		287		1,426
Total credit facilities			$	2,200		$	287	$	-	$	287	$	1,626

(1) Includes a $50 million sublimit for letters of credit and $100 million sublimit for “swingline” loans, defined as loans which are made available on a same-day basis and are repayable in full within 30 days.
(2) Includes a $950 million sublimit for letters of credit and $100 million sublimit for swingline loans.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary covenants for credit facilities of their type, including covenants limiting liens to those permitted under the senior notes’ indenture, mergers, sales of all or substantially all of the Utility’s assets, and other fundamental changes. In addition, both PG&E Corporation and the Utility are required to maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% and PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securities of the Utility. At December 31, 2008, PG&E Corporation and the Utility met all of these requirements.

2008 Financings

Access to the capital markets is essential to the continuation of the Utility’s capital expenditure program. Notwithstanding the recent disruption in the capital markets, the Utility was able to issue $1.2 billion of senior unsecured notes in October and November 2008. The proceeds were used primarily to finance capital expenditures and to partially repay outstanding commercial paper balances in preparation for refinancing $600 million of long-term debt that will mature in March 2009. In addition, the Utility used the proceeds it received from the September and October 2008 refunding of certain pollution control bonds to repay outstanding commercial paper.

The following table summarizes the Utility’s long-term debt issuances in 2008:

(in millions)	Issue Date	Amount
Senior notes
5.625%, due 2017	March 3	$	200
6.35%, due 2038	March 3		400
8.25%, due 2018	October 21		600
6.25%, due 2013	November 18		400
8.25%, due 2018	November 18		200
Total senior notes			1,800
Pollution control bonds
Series 2008 F, 3.75%, due 2026	September 22		50
Series 2008 G, 3.75%, due 2018	September 22		45
Series 2008 A and B, variable rates, due 2026	October 29		149
Series 2008 C and D, variable rates, due 2016	October 29		160
Total pollution control bonds			404
Total long-term debt issuances in 2008		$	2,204

During 2008, PG&E Corporation issued 6,905,462 shares of common stock upon exercise of employee stock options, for the account of 401(k) participants, and under its Dividend Reinvestment and Stock Purchase Plan, generating approximately $225 million of cash. In 2008 PG&E Corporation contributed $270 million of cash to the Utility 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 and the Utility’s ability to access 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 disputed claims and the amount of interest on these claims that the Utility will be required to pay. (See Note 15 of the Notes to the Consolidated Financial Statements.)

Assuming continued access to the capital markets, the Utility currently plans to issue additional long-term debt of $3.5 billion to $4.5 billion through 2011. PG&E Corporation expects to issue additional common stock, debt, or other securities, depending on market conditions, to fund a portion of its equity contributions to the Utility and to fund PG&E Corporation’s capital expenditures. PG&E Corporation currently plans to contribute equity of $1.2 billion to $1.8 billion to the Utility through 2011. 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.

Credit Ratings

As of January 31, 2009, PG&E Corporation and the Utility’s credit ratings from Moody's and Standard & Poor’s (“S&P”) were as follows:

	Moody's	S&P
Utility
Corporate credit rating	A3	BBB+
Senior unsecured debt	A3	BBB+
Credit facility	A3	BBB+
Pollution control bonds backed by letters of credit	Not rated to Aa1/VMIG1	AA-/A-1+ to AAA/A-1+
Pollution control bonds backed by bond insurance	A3	A to AA
Pollution control bonds – nonbacked	A3	BBB+
Preferred stock	Baa2	BBB-
Commercial paper program	P-2	A-2

PG&E Energy Recovery Funding LLC
Energy recovery bonds	Aaa	AAA

PG&E Corporation
Corporate credit rating	Baa1	Not rated
Credit facility	Baa1	Not rated

Moody's and S&P are nationally recognized credit rating organizations. These ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. A credit rating is not a recommendation to buy, sell, or hold securities.

Dividends

The dividend policies of PG&E Corporation and the Utility are designed to meet the following three objectives:

●	Comparability: Pay a dividend competitive with the securities of comparable companies based on payout ratio (the proportion of earnings paid out as dividends) and, with respect to PG&E Corporation, yield (i.e., dividend divided by share price);

●	Flexibility: Allow sufficient cash to pay a dividend and to fund investments while avoiding having to issue new equity unless PG&E Corporation or the Utility's capital expenditure requirements are growing rapidly and PG&E Corporation or the Utility can issue equity at reasonable cost and terms; and

●	Sustainability: Avoid reduction or suspension of the dividend despite fluctuations in financial performance except in extreme and unforeseen circumstances.

The Boards of Directors of PG&E Corporation and the Utility have each adopted a target dividend payout ratio range of 50% to 70% of earnings. Dividends paid by PG&E Corporation and the Utility are expected to remain in the lower end of the target payout ratio range to ensure that equity funding is readily available to support each company's capital investment needs. Each Board of Directors retains authority to change the respective common stock dividend policy and dividend payout ratio at any time, especially if unexpected events occur that would change their view as to the prudent level of cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors.

In addition, the declaration of the Utility’s dividends is subject to the CPUC-imposed conditions that the Utility maintain on average its CPUC-authorized capital structure and that the Utility’s capital requirements, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, be given first priority.

During 2008, the Utility paid common stock dividends totaling $589 million, including $568 million of common stock dividends paid to PG&E Corporation and $21 million of common stock dividends paid to PG&E Holdings, LLC. At December 31, 2007, PG&E Holdings, LLC, a wholly owned subsidiary of the Utility, held 19,481,213 shares of the Utility common stock. Effective August 29, 2008, PG&E Holdings LLC, was dissolved, and the shares subsequently cancelled.

During 2008, PG&E Corporation paid common stock dividends of $1.53 per share totaling $573 million, including $28 million that was paid to Elm Power Corporation. (At December 31, 2007, Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, held 24,665,500 shares of PG&E Corporation common stock. Effective August 29, 2008, Elm Power Corporation was dissolved, and the shares subsequently cancelled.) On December 17, 2008, the Board of Directors of PG&E Corporation declared a dividend of $0.39 per share, totaling $141 million, which was paid on January 15, 2009 to shareholders of record on December 31, 2008. On February 18, 2009, the Board of Directors of PG&E Corporation declared a dividend of $0.42 per share, payable on April 15, 2009, to shareholders of record on March 31, 2009.

During 2008, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling $14 million. On December 17, 2008, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock totaling approximately $3 million that was paid on February 15, 2009, to preferred shareholders of record on January 30, 2009. On February 18, 2009, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock, payable on May 15, 2009, to shareholders of record on April 30, 2009.

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 2008, 2007, and 2006 were as follows:

(in millions)	2008			2007			2006
Net income	$	1,199		$	1,024		$	985
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,838			1,956			1,802
Allowance for equity funds used during construction		(70	)		(64	)		(47	)
Gain on sale of assets		(1	)		(1	)		(11	)
Deferred income taxes and tax credits, net		593			43			(287	)
Other changes in noncurrent assets and liabilities		(25	)		188			116
Effect of changes in operating assets and liabilities:
Accounts receivable		(83	)		(6	)		128
Inventories		(59	)		(41	)		34
Accounts payable		(137	)		(196	)		21
Income taxes receivable/payable		43			56			28
Regulatory balancing accounts, net		(394	)		(567	)		329
Other current assets		(223	)		170			(273	)
Other current liabilities		90			24			(235	)
Other		(5	)		(45	)		(13	)
Net cash provided by operating activities	$	2,766		$	2,541		$	2,577

During 2008, net cash provided by operating activities was approximately $2,766 million, reflecting net income of $1,199 million, adjusted for noncash depreciation, amortization, and decommissioning and allowance for equity funds used during construction of $1,838 million and $70 million, respectively (see “Results of Operations” above). Additionally, the following change in operating assets and liabilities positively impacted cash flows during the period:

●

Liabilities for deferred income taxes and tax credits increased by approximately $593 million in 2008, primarily due to an increase in balancing account revenues, which are not taxable until billed, as well as an increase in deductible tax depreciation as authorized by the 2008 Economic Stimulus Act.

The following changes in operating assets and liabilities negatively impacted cash flows during the period:

●	Regulatory balancing accounts, net under-collection increased by approximately $394 million in 2008, primarily due to an increase of approximately $356 million in under-collected electricity procurement costs and a $108 million decrease in over-collections due to refunds to customers for the over-collected prior year balance. The 2007 over-collection was caused by lower than forecasted RMR costs and the receipt of a settlement payment made in connection with an energy supplier refund claim. This increase in the Regulatory balancing accounts, net under-collection was partially offset by a refund of approximately $230 million that the Utility received from the California Energy Commission (“CEC”). The funds from the CEC will be refunded to customers in 2009.

●	Net collateral paid, primarily related to price risk management activities, increased by approximately $325 million in 2008 as a result of changes in the Utility’s exposure to counterparties’ credit risk, generally reflecting declining natural gas prices. 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.

During 2007, net cash provided by operating activities was approximately $2,541 million, reflecting net income of $1,024 million, adjusted for noncash depreciation, amortization, and decommissioning and allowance for equity funds used during construction of $1,956 million and $64 million, respectively (see “Results of Operations” above). The following changes in operating assets and liabilities positively impacted cash flows during the period:

●	Other noncurrent assets and liabilities increased by approximately $188 million primarily due to $159 million of under-spent funds related to the California Solar Incentive program.

●	Other current assets decreased by approximately $170 million primarily due to a decrease in the cash collateral deposited by counterparties as a result of changes in the Utility’s exposure to counterparties’ credit risk.

The following changes in operating assets and liabilities negatively impacted cash flows during the period:

●	Regulatory balancing accounts, net over-collection decreased by approximately $567 million in 2007 primarily due to CPUC-authorized rate reductions designed to reduce the over-collection.

●	Accounts payable decreased by approximately $196 million primarily due to differences in the timing of purchases and payments of operating expenses.

During 2006, net cash provided by operating activities was approximately $2,577 million, reflecting net income of $985 million, adjusted for noncash depreciation, amortization, and decommissioning and allowance for equity funds used during construction of $1,802 million and $47 million, respectively (see “Results of Operations” above). The following change in operating assets and liabilities positively impacted cash flows during the period:

●

Regulatory balancing accounts, net under-collection decreased by approximately $329 million in 2006, primarily due to lower than forecasted costs associated with certain power purchase agreements and a decrease related to customer energy efficiency incentives due to a CPUC decision in October 2005 to set rates to recover shareholder incentive revenue. These decreases were offset by a decrease in electricity procurement costs due to the receipt of cash relating to the Mirant settlement.

The following changes in operating assets and liabilities negatively impacted cash flows during the period:

●	Liabilities for deferred income taxes and tax credits decreased by approximately $287 million in 2006, primarily due to an increased California franchise tax deduction, lower taxable supplier settlement income received, and a deduction related to the payment of previously accrued litigation costs.

●	Other current assets increased by approximately $273 million primarily due to an increase in the cash collateral deposited by counterparties as a result of changes in the Utility’s exposure to counterparties’ credit risk, generally reflecting increasing natural gas prices.

●	Other current liabilities decreased by approximately $235 million primarily due to the settlement of claims related to the alleged exposure to chromium at the Utility’s natural gas compressor stations.

Future operating cash flow will be impacted by the timing of cash collateral payments and receipts related to price risk management activity, among other factors. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure, which is primarily dependent on electricity and gas price movement.

In addition, PG&E Corporation and the Utility’s future operating cash flow in 2009 is expected to be impacted by the receipt of tax refunds. (See “Tax Matters” below and Note 10 of the Notes to the Consolidated Financial Statements.)

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. In accordance with this mechanism, on August 21, 2008, the CPUC approved the Utility’s request to collect from customers the forecasted 2008 end-of-year under-collection of procurement costs, due mainly to rising natural gas costs and lower than forecasted hydroelectric generation. Effective October 1, 2008, customer rates were adjusted to allow the Utility to collect $645 million in procurement costs through December 2009. On December 30, 2008, the Utility requested that its electric rates be adjusted, effective January 1, 2009, to reflect the revised forecast of electricity prices which are expected to be lower than originally forecasted as a result of lower natural gas prices. The January 1, 2009 rate changes reflect a net decrease of $101 million in electric revenues versus revenues based on rates effective October 1, 2008. On January 23, 2009, the Utility filed a notice with the CPUC indicating that customer electric rates are expected to increase effective on March 1, 2009 by approximately $640 million as a result of the CPUC’s approval of a $528 million increase in the remittance rate paid to the DWR and the FERC’s approval of a $112 million increase in electric transmission rates.

In addition, the ongoing upheaval in the economy has negatively impacted investment returns on assets held in trust to satisfy the Utility’s obligations to decommission its nuclear generation facilities and to secure payment of employee benefits under pension and other post-retirement benefit plans. The Utility’s recorded liabilities and, in some cases, its funding obligations, may increase as a result of declining investment returns on trust assets and lower assumed rates of return. However, the Utility believes that it is probable that any increase in funding obligations would be recoverable through rates, and as a result is not expected to have a material impact on the Utility’s cash flows or results of operations.

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 type of construction activities, which can be influenced by the need to make electricity and natural gas reliability improvements, storms, and other factors.

The Utility’s cash flows from investing activities for 2008, 2007, and 2006 were as follows:

(in millions)	2008			2007			2006
Capital expenditures	$	(3,628	)	$	(2,768	)	$	(2,402	)
Net proceeds from sale of assets		26			21			17
Decrease in restricted cash		36			185			115
Proceeds from nuclear decommissioning trust sales		1,635			830			1,087
Purchases of nuclear decommissioning trust investments		(1,684	)		(933	)		(1,244	)
Other		(25	)		-			1
Net cash used in investing activities	$	(3,640	)	$	(2,665	)	$	(2,426	)

Net cash used in investing activities increased by approximately $975 million in 2008 compared to 2007 and by approximately $239 million in 2007 compared to 2006. These increases were primarily due to increases of approximately $860 million and $366 million in 2008 and 2007, respectively, of capital expenditures for installing the SmartMeter™ advanced metering infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

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

Financing Activities

The Utility’s cash flows from financing activities for 2008, 2007, and 2006 were as follows:

(in millions)	2008			2007			2006
Borrowings under accounts receivable facility and revolving credit facility	$	533		$	850		$	350
Repayments under accounts receivable facility and revolving credit facility		(783	)		(900	)		(310	)
Net issuance (repayments) of commercial paper, net of discount of $11 million in 2008, $1 million in 2007 and $2 million in 2006		6			(209	)		458
Proceeds from issuance of long-term debt, net of discount, premium, and issuance costs of $19 million in 2008 and $16 million in 2007		2,185			1,184			-
Long-term debt repurchased		(454	)		-			-
Rate reduction bonds matured		-			(290	)		(290	)
Energy recovery bonds matured		(354	)		(340	)		(316	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(568	)		(509	)		(460	)
Equity contribution		270			400			-
Other		(36	)		23			38
Net cash provided by (used in) financing activities	$	785		$	195		$	(544	)

In 2008, net cash provided by financing activities increased by approximately $590 million compared to 2007. In 2007, net cash provided by financing activities increased by approximately $739 million compared to 2006. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depends 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 relies on short-term debt to fund temporary financing needs.

PG&E Corporation

With the exception of dividend payments, interest, and transactions between PG&E Corporation and the Utility, PG&E Corporation had no material cash flows on a stand-alone basis for the years ended December 31, 2008, 2007, and 2006.

CONTRACTUAL COMMITMENTS

The following table provides information about PG&E Corporation and the Utility’s contractual commitments at December 31, 2008.

	Payment due by period
(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Contractual Commitments: Utility
Long-term debt(1):
Fixed rate obligations	$	17,125	$	1,089	$	1,540	$	1,314	$	13,182
Variable rate obligations		954		7		332		615		-
Energy recovery bonds(2)		1,742		435		871		436		-
Purchase obligations:
Power purchase agreements(3):
Qualifying facilities		12,979		1,361		2,649		2,221		6,748
Renewable contracts		9,779		439		1,076		1,278		6,986
Irrigation district and water agencies		372		64		135		89		84
Other power purchase agreements		1,945		275		458		171		1,041
Natural gas supply and transportation		1,444		898		298		91		157
Nuclear fuel		950		95		200		160		495
Pension and other benefits(4)		580		300		280		-		-
Capital lease obligations(5)		454		50		100		100		204
Operating leases		123		21		35		33		34
Preferred dividends(6)		70		14		28		28		-
Other commitments		24		24		-		-		-
PG&E Corporation
Long-term debt(1):
Convertible subordinated notes		318		27		291		-		-


(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2008 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. Variable rate obligations consist of bonds, due in 2016-2026, backed by letters of credit which expire in 2011 and 2012. These bonds are subject to mandatory redemption unless the letters of credit are extended or replaced or if applicable to the series, the issuer consents to the continuation of these bonds without a credit facility. Accordingly, these bonds have been classified for repayment purposes in 2011 and 2012. (See Note 4 of the Notes to the Consolidated Financial Statements.)
(2) Includes interest payments over the terms of the bonds. (See Note 5 of the Notes to the Consolidated Financial Statements.)
(3) This table does not include DWR allocated contracts because the DWR is legally and financially responsible for these contracts and payments. (See Note 17 of the Notes to the Consolidated Financial Statements.)
(4) PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions, sufficient to meet minimum funding requirements. (See Note 14 of the Notes to the Consolidated Financial Statements.)
(5) See Note 17 of the Notes to the Consolidated Financial Statements.
(6) Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.

The contractual commitments table above excludes potential commitments associated with the conversion of existing overhead electric facilities to underground electric facilities. At December 31, 2008, the Utility was committed to spending approximately $228 million for these conversions. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties and telephone utilities involved. The Utility expects to spend approximately $40 million to $60 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

The contractual commitments table above also excludes potential payments associated with unrecognized tax benefits accounted for under Financial Accounting Standards Board (“FASB”) Interpretation No. 48. “Accounting for Uncertainty in Income Taxes,” (“FIN 48”). Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amount and period of future payments to major tax jurisdictions related to FIN 48 liabilities. Matters relating to tax years that remain subject to examination are discussed below and in Note 10 of the Notes to the Consolidated Financial Statements.

CAPITAL EXPENDITURES

The Utility’s investment in property, plant and equipment totaled $3.7 billion in 2008, $2.8 billion in 2007, and $2.4 billion in 2006. The Utility expects that capital expenditures will total approximately $3.6 billion in 2009 and forecasts that capital expenditures will average approximately $3.5 to $4.0 billion per year over the next three years. The Utility’s weighted average rate base in 2008 was $18.2 billion. Based on the estimated capital expenditures for 2009, the Utility projects a weighted average rate base of approximately $20.1 billion for 2009. Depending on conditions in the capital markets, the Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet already authorized growth. Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC and TO rate cases. In addition, from time to time, the Utility requests authorization to collect additional revenue requirements to recover capital expenditures related to specific projects, such as new power plants, gas or electric transmission projects, and the SmartMeterTM advanced metering infrastructure.

Proposed Electric Distribution Reliability Program (Cornerstone Improvement Program)

On December 19, 2008, the CPUC ruled that it will consider the Utility’s request for approval of a proposed six-year electric distribution reliability improvement program. The CPUC found that it is preferable to begin the scrutiny and detailed analyses to determine whether major capital expenditures are necessary to maintain or improve distribution reliability and, if necessary, to determine the extent and timing of such expenditures, sooner rather than later. The proposed program includes initiatives that are designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities. The Utility expects that the work performed in the six-year program also would provide additional reliability benefits. The Utility forecasts that it would incur capital expenditures totaling approximately $2.3 billion and operating and maintenance expenses totaling approximately $43 million over the six-year period. In its December 19, 2008 decision, the CPUC ruled that program costs incurred in 2009 and 2010, if any, would not be recoverable from customers. The Utility does not expect to incur significant costs in 2009 or 2010 before the CPUC issues a final decision on the Utility’s request

PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility’s request.

Proposed Electric Transmission Projects

The Utility has been exploring the feasibility of obtaining regulatory approval for a potential investment in an electric transmission project that would traverse the Pacific Northwest. On April 17, 2008, the FERC granted part of the Utility’s request for a declaratory order to collect transmission rates designed to provide an incentive to the Utility to continue leading the development of the proposed 1,000-mile, 500 kilovolt (“kV”) transmission line to run from British Columbia, Canada to Northern California that would provide access to potential new renewable generation resources, improve regional transmission reliability, and provide opportunities for other market participants to use the new facilities. The FERC’s order allows the Utility to recover all prudently incurred pre-commercial costs, such as costs for feasibility studies and surveys, and all prudently incurred development and construction costs if the proposed project is abandoned or cancelled for reasons beyond the Utility’s control. On December 1, 2008, the Western Electric Coordinating Council (“WECC”) formally completed the Regional Planning Project Review process for the project. On December 19, 2008, the Utility submitted to WECC a plan-service and technical studies showing that the desired line rating of 3,000 megawatts north to south is achievable; the south to north rating study is underway. The target operating date for the project is December 2015. The development and construction of this proposed transmission project remains subject to significant business, financial, regulatory, environmental, and political risks and challenges.

The Utility also has been exploring the development of a new 500-kV electric transmission project, the Central California Clean Energy Transmission line, to increase transmission capacity between northern and southern California, improve access to new renewable generation resources and meet reliability requirements in the Fresno area. The CAISO has been conducting stakeholder meetings to review the Utility’s proposal and the Utility has been conducting various studies to ensure that the project is designed and located to avoid or minimize potential impacts. Depending on the results of these stakeholder meetings and studies, the Utility will decide whether to request CPUC approval to construct the line.

The Utility cannot predict whether the many conditions and challenges to the development of these proposed electric transmission projects will be met.

Potential Natural Gas Pipeline Projects

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of the proposed 230-mile Pacific Connector Gas Pipeline that would connect the proposed Jordan Cove liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon with the Utility's transmission system near Malin, Oregon. The development of the Pacific Connector Gas Pipeline is dependent upon the development of the Jordan Cove LNG terminal by Fort Chicago Energy Partners, L.P. In addition, the development and construction of the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline are subject to obtaining permits, regulatory approvals, and commitments under long-term capacity contracts. It is expected that the FERC will issue a certificate authorizing construction and operation of the pipeline in 2009.

SmartMeter ™ Program

Since late 2006, the Utility has been installing an advanced metering infrastructure, known as the SmartMeter ™ program, for virtually all of the Utility's electric and gas customers. This infrastructure results in substantial cost savings associated with billing customers for energy usage, and enables the Utility to measure usage of electricity on a time-of-use basis and to charge time-differentiated rates. The main goal of time-differentiated rates is to encourage customers to reduce energy consumption during peak demand periods and to reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation throughout its service territory by the end of 2011.

The CPUC authorized the Utility to recover the $1.74 billion estimated SmartMeter ™ project cost, including an estimated capital cost of $1.4 billion. The $1.74 billion amount includes $1.68 billion for project costs and approximately $54.8 million for costs to market critical peak pricing programs such as SmartRate that are made possible by SmartMeter™ technology. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed $1.68 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. Through 2008, the Utility has spent an aggregate of $730 million, including capital costs of $589 million, to install the SmartMeterTM system.

On December 12, 2007, and supplemented on May 14, 2008, the Utility filed an application with the CPUC requesting approval to upgrade elements of the SmartMeter™ program at an estimated cost of approximately $572 million, including approximately $463 million of capital expenditures to be recovered through electric rates beginning in 2009. The Utility has proposed to install upgraded electric meters with associated devices that would offer an expanded range of service features for electric customers that would provide energy conservation and demand response options, such as the enablement of "smart" appliances that could use energy more wisely in response to near real-time energy data. These upgraded meters would also increase operational efficiencies for the Utility through, among other things, the ability to remotely connect and disconnect service to electric customers. In addition, the upgraded electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner.

On December 23, 2008, a proposed decision was issued by an administrative law judge, which if adopted by the CPUC, would allow the Utility to proceed with the SmartMeter Upgrade and authorize funding of $495.2 million, including $410 million in capital costs, to be recovered through an increased revenue requirement. PG&E Corporation and the Utility are unable to predict when the CPUC will issue a final decision.

On July 31, 2008, the CPUC ordered the Utility to implement “dynamic pricing” electric rates in 2010 and 2011 for certain customers who do not take affirmative action to opt out of the dynamic pricing rates. Dynamic pricing rates use price signals (e.g., critical peak pricing and real-time pricing) to encourage energy efficiency and reduce demand. The Utility is required to implement critical peak pricing rates for these customers starting in 2010 and early 2011. The Utility is also required to offer real-time pricing to all customers starting in May 2011, at the customer’s election. The Utility has been directed to file a request with the CPUC by February 28, 2009 to approve the Utility’s rate proposal for critical peak pricing and to authorize recovery of the Utility’s estimated costs of approximately $155 million (including estimated capital costs of approximately $107 million) to meet the required schedule for implementation. The Utility expects to file a request for approval of real-time pricing rates and the associated implementation costs by March 1, 2010 in connection with the Utility’s 2011 GRC proceeding.

Diablo Canyon Steam Generator Replacement Project

In November 2005, the CPUC authorized the Utility to replace the steam generators at the two nuclear operating units at Diablo Canyon (Units 1 and 2) and recover costs up to $706 million from customers without further reasonableness review. If costs exceed this threshold, the CPUC authorized the Utility to recover costs of up to $815 million, subject to reasonableness review of the full amount. As of December 31, 2008, the Utility has spent approximately $554 million, including progress payments under contracts for the eight steam generators that the Utility has ordered. The Utility anticipates the future expenditures will be approximately $146 million. The Utility installed four of the new steam generators in Unit 2 during the refueling outage that began in February 2008 and ended in April 2008. The extended refueling outage to replace the steam generators in Unit 1 began in January and is expected to end in early April 2009.

New Generation Facilities

During 2008, the Utility was engaged in the development of the following generation facilities to be owned and operated by the Utility:

Gateway Generating Station

In November 2006, the Utility acquired the equipment, permits and contracts related to a partially completed 530-megawatt (“MW”) power plant in Antioch, California, referred to as the Gateway Generating Station. The CPUC has authorized the Utility to recover estimated capital costs of approximately $385 million to complete the construction of the facility and as of December 31, 2008, the Utility has incurred approximately $350 million. Of this amount, the Utility incurred $221 million during 2008. The Gateway Generating Station reached full load commercial production on January 4, 2009, and is expected to reach final project completion at the end of the first quarter of 2009.

Colusa Generating Station

On June 12, 2008, the CPUC gave its final approval for the Utility to construct the Colusa Generating Station, a 657- MW combined cycle generating facility to be located in Colusa County, California. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008.

The CPUC authorized the Utility to recover an initial capital cost for the Colusa Generating Station of approximately $673 million that can be adjusted to reflect any actual incentive payments made to, or liquidated damages received from, the contractors through notification to the CPUC but without a reasonableness review. The CPUC authorized the Utility to seek recovery of additional capital costs attributable to operational enhancements, but otherwise limited cost recovery to the initial capital cost estimate. The CPUC also ruled that in the event the final capital costs are lower than the initial estimate, half of the savings must be returned to customers. If actual costs exceed the cost limits (except for additional capital costs attributable to operational enhancements), the Utility would be unable to recover such excess costs. The forecasted initial capital cost will be trued up in the Utility’s next GRC following the commencement of operations to reflect actual initial capital costs. Permitting or construction delays and project development or materials cost overruns could cause the project costs to exceed the CPUC-adopted cost limits. As of December 31, 2008, the Utility had incurred $216 million for the development and construction of the Colusa Generating Station. Of this amount, the Utility has incurred $204 million during 2008.

Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations in 2010.

Humboldt Bay Generating Station

On September 24, 2008, the CEC issued its final decision authorizing the construction of a 163-MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life. Demolition of existing structures on the site is complete and the contractor began preparing the site for construction in December 2008.

The CPUC authorized the Utility to recover an initial capital cost for the Humboldt Bay Generating Station of approximately $239 million for the construction that can be adjusted to reflect any actual incentive payments made to, or liquidated damages received from, the contractors through notification to the CPUC but without a reasonableness review. The Utility is authorized to seek recovery of additional capital costs that are attributable to operational enhancements, but the request will be subject to the CPUC’s review. The Utility also is permitted to seek recovery of additional capital costs subject to a reasonableness review. The forecasted initial capital cost will be trued up in the Utility’s next GRC following the commencement of operations to reflect actual initial capital costs. Permitting or construction delays and project development or materials cost overruns could cause the project costs to exceed the CPUC-adopted cost limits. As of December 31, 2008, the Utility had incurred $61.5 million for the development and construction of the Humboldt Bay Generating Station. Of this amount, the Utility incurred $55 million during 2008.

Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2010.

Proposed New Generation Facilities

Request for Long-Term Generation Resources

The Utility’s CPUC-approved long-term electricity procurement plan, covering 2007-2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new generation resources by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources. The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources only through purchase and sale agreements (“PSAs”) (i.e., a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements) and engineering, procurement, and construction arrangements proposed by third parties. The utilities are prohibited from submitting offers for utility-built generation in their respective requests for offers (“RFOs”) until questions can be resolved about how to compare utility-owned generation offers with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.

On July 21, 2008, the Utility received offers from third parties in response to the Utility’s April 1, 2008 RFO for 800 MW to 1,200 MW of dispatchable and operationally flexible new generation resources to be on-line no later than May 2015. The Utility’s RFO requested offers for both PSAs and power purchase. In the fourth quarter of 2008, the Utility developed its RFO shortlist of participants and is currently involved in negotiations with potential counterparties. The Utility anticipates executing contracts and requesting CPUC approval of the executed contracts in the first half of 2009.

Proposed Renewable Energy Development

California law establishes a renewable portfolio standard (“RPS”) that requires that each California retail seller of electricity, except for municipal utilities, increase its purchases of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity delivered from renewable resources equals at least 20% of its total retail sales by the end of 2010. The California Legislature also is considering legislation to increase the RPS to require 33% of a retail seller’s electric load to be met with renewable resources by 2020.

Following several RFOs and bilateral negotiations, the Utility entered into various agreements to purchase renewable generation to be produced by facilities proposed to be developed by third parties. The development of these renewable generation facilities are subject to many risks, including risks related to permitting, financing, technology, fuel supply, environmental, and the construction of sufficient transmission capacity. The Utility has been supporting the development of these renewable resources by working with regulatory and governmental agencies to ensure timely construction of transmission lines and permitting of proposed project sites.

In addition, to help meet the challenging RPS goal by 2010, the Utility intends to explore developing and/or owning renewable generation resources, subject to CPUC approval. In particular, on February 24, 2009, the Utility requested the CPUC to approve the Utility’s proposed development of renewable generation resources based on solar photovoltaic (“PV”) technology. The Utility’s proposal includes the development and construction of up to 250 MW of Utility-owned PV generating facilities, to be deployed over a period of five years, at an estimated capital cost of approximately $1.5 billion, and the execution of power purchase agreements for up to 250 MW of PV projects to be developed by independent power producers.

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; tax matters, Chapter 11 disputed claims, and environmental matters, which are discussed in Notes 10, 15, and 17 of the Notes to the Consolidated Financial Statements.

REGULATORY MATTERS

The Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, the FERC, and the Nuclear Regulatory Commission (“NRC”), the resolutions of which may affect the Utility's and PG&E Corporation's results of operations or financial condition.

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 (“Humboldt Bay Unit 3”). The DOE failed to develop a permanent storage site by January 31, 1998. The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility to store spent fuel through at least 2024. After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.

In October 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit. Although the appellant did not seek to obtain an order prohibiting the Utility from loading spent fuel, the petition stated that they may seek a stay of fuel loading at the facility. On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding. All briefs by all parties are scheduled to be filed by April 8, 2009.

The construction of the dry cask storage facility is complete and the initial movement of spent nuclear fuel to dry cask storage is expected to begin in June 2009. If the Utility is unable to begin loading spent nuclear fuel by October 2010 for Unit 1 or May 2011 for Unit 2 and if the Utility is otherwise unable to increase its on-site storage capacity, the Utility would have to curtail or halt operations until such time as additional safe storage for spent fuel is made available.

On August 7, 2008, the U.S. Court of Appeals for the Federal Circuit issued an appellate order in the litigation pending against the DOE in which the Utility and other nuclear power plant owners seek to recover costs they incurred to build on-site spent nuclear fuel storage facilities due to the DOE’s delay in constructing a national repository for nuclear waste. In October 2006, the U.S. Court of Federal Claims found that the DOE had breached its contract with the Utility but awarded the Utility approximately $43 million of the $92 million incurred by the Utility through 2004. In ruling on the Utility’s appeal, the U.S. Court of Appeals for the Federal Circuit reversed the lower court on issues relating to the calculation of damages and ordered the lower court to re-calculate the award. Although various motions by the DOE for reconsideration are still pending, the judge in the lower court conducted a status conference on January 15, 2009 and has scheduled another conference for July 9, 2009. The Utility expects the final award will be approximately $91 million for costs incurred through 2004 and that the Utility will recover all of its costs incurred after 2004 to build on-site storage facilities. Amounts recovered from the DOE will be credited to customers through rates.

PG&E Corporation and the Utility are unable to predict the outcome of any rehearing petition.

Energy Efficiency Programs and Incentive Ratemaking

In 2007, the CPUC established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. To earn incentives the utilities must (1) achieve at least 85% of the CPUC’s overall energy savings goal over the three-year program cycle and (2) achieve at least 80% of the CPUC’s individual kilowatt-hour (kWh), kilowatt (kW), and gas therm savings goals over the three-year program cycle. If the utilities achieve between 85% and 99% of the CPUC’s overall savings goal, 9% of the verified net benefits (i.e., energy resource savings minus total energy efficiency program costs) will accrue to shareholders and 91% of the verified net benefits will accrue to customers. If the utilities achieve 100% or more of the CPUC’s overall savings goal, then 12% of the total verified net benefits will accrue to shareholders and 88% will accrue to customers. If the utilities achieve less than 65% of any one of the individual metric savings goals (i.e., kWh, kW, or gas therm), then the utilities must reimburse customers based on the greater of (1) 5 cents per kWh, 45 cents per therm, and $25 per kW for each kWh, therm, or kW unit below the 65% threshold, or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee. The maximum amount of revenue that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers, over the 2006-2008 program cycle is $180 million.

Under the existing incentive ratemaking mechanism, the utilities are required to submit two interim claims; the first claim is based on estimated performance achieved during the first and second years of the three-year period, and the second claim is based on estimated performance achieved over the entire three-year period. Estimated performance will be calculated based on the number and cost of energy efficiency measures installed by the utilities and estimates and assumptions about the energy savings per energy efficiency measure.

On December 18, 2008, based on the Utility’s first interim claim, the CPUC awarded the Utility $41.5 million in shareholder incentive revenues for the Utility’s energy efficiency program performance in 2006-2007. The awarded amount represents 35% of $119 million in estimated shareholder incentive revenues for the 2006-2007 program years. The CPUC ruled that 65% of the incentives calculated for the utilities’ 2006-2007 interim claims will be “held back” until completion of final measurement studies and a final verification report for the entire three-year program cycle. As long as the final measured energy savings are at least 65% of each of the CPUC’s individual savings goals over the 2006-2008 program cycle, the utilities will not be required to pay back any incentives received on an interim basis. The CPUC also ruled that the utilities will not be entitled to any additional incentives for the 2006-2008 program period beyond the incentives already received if the utility’s performance falls within a “deadband”; i.e., if a utility achieves (1) less than 80% of the CPUC’s goal for any individual savings metric or (2) less than 85% of the CPUC’s overall energy savings goal but greater than 65% of the CPUC’s goal for each individual savings metric. On February 2, 2009 The Utility Reform Network and the CPUC’s Division of Ratepayer Advocates filed an application for rehearing of the CPUC’s December 18, 2008 award.

On January 29, 2009, the CPUC instituted a new proceeding to modify the existing incentive ratemaking mechanism, to adopt a new framework to review the utilities’ 2008 energy efficiency performance, and to conduct a final review of the utilities’ performance over the 2006-2008 program period. The CPUC also plans to develop a long-term incentive mechanism for program periods beginning in 2009 and beyond.

The utilities are required to submit their 2008 performance reports to the CPUC by February 28, 2009. The CPUC has stated it intends to adopt a new framework to examine these reports so as to allow any interim awards (or obligations) attributable to 2008 performance to be made (or imposed) no later than December 2009, and to allow any final awards (or obligations) attributable to performance over the 2006-2008 period to be made (or imposed) no later than December 2010.

Whether the Utility will receive all or a portion of the remaining $77 million in incentives for the 2006-2007 program years, whether the Utility will receive any additional incentives or incur a reimbursement obligation in 2009 based on the second interim claim, and whether the final true-up in 2010 will result in a positive or negative adjustment, depends on the new framework and rules to be adopted by the CPUC.

The Utility intends to file an amended application on March 2, 2009 to seek CPUC approval of the Utility’s 2009-2011 energy efficiency programs and funding authorization of approximately $1.8 billion over the three-year cycle, an approximate increase of $860 million over the 2006-2008 budget. The CPUC has authorized bridge funding of approximately $33 million per month to allow the Utility to continue existing energy efficiency programs into 2009 until the CPUC issues a final order on the 2009-2011 application.

Application to Recover Hydroelectric Generation Facility Divestiture Costs

On April 14, 2008, the Utility filed an application with the CPUC requesting authorization to recover approximately $47 million, including $12.2 million of interest, of the costs it incurred in connection with the Utility’s efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken at the direction of the CPUC in preparation for the proposed divestiture of the facilities to further the development of a competitive generation market in California. The Utility continues to own its hydroelectric generation assets. On February 18, 2009, a proposed decision was issued by the administrative law judge, which if adopted by the CPUC, would allow the Utility to recover these costs. It is expected that the CPUC will issue a final decision in 2009.

Electric Transmission Owner Rate Cases

On October 22, 2008, the FERC approved an all-party settlement in the Utility’s TO rate case that was filed in July 2007. The settlement sets an annual wholesale base transmission revenue requirement of $706 million and a retail base transmission revenue requirement of $718 million, effective March 1, 2008. The Utility has been reserving the difference between expected revenues based on rates requested by the Utility in its TO rate application and expected revenues based on rates proposed in the settlement. As a result, the settlement will not impact the Utility’s results of operations or financial condition. The Utility will refund any over–collected amounts to customers, with interest, through an adjustment to rates in 2010.

Also, on September 30, 2008, the FERC accepted the Utility’s TO rate case that was filed on July 30, 2008 requesting an increase in retail base revenue requirement to $849 million, and an increase in the Utility’s wholesale base revenue requirement to $838 million. As it has in the past, the FERC suspended the rate increase associated with the requested increase in revenue requirements for five months, until March 1, 2009. The increase in rates will be subject to refund pending final FERC approval of the requested increase in revenue requirements. The Utility, members of the FERC’s staff, and interveners, have been engaged in settlement discussions. Any settlement that is reached would be subject to the FERC’s approval. If the parties are not able to reach a settlement, the FERC would hold hearings before issuing a decision on the Utility’s request.

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, 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.

As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs are recoverable through the ratemaking mechanism described below, fluctuations in electricity prices will not affect earnings but may impact cash flows. The Utility’s natural gas procurement costs for its core customers are recoverable through the Core Procurement Incentive Mechanism (“CPIM”) and other ratemaking mechanisms, as described below. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism. However, 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. Movement in interest rates can also cause earnings and cash flow to fluctuate.

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.

The Utility estimates the fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from brokers and electronic exchanges, supplemented by online price information from news services. When market data is not available, the Utility uses models to estimate fair value.

The Utility conducts business with wholesale customers and 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. Credit-related losses attributable to receivables and electric and gas procurement activities from wholesale customers and counterparties are expected to be recoverable from customers through rates and are not expected to have a material impact on net income.

Price Risk

Electricity Procurement

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities. When customer demand exceeds the amount of electricity that can be economically produced from the Utility’s own generation facilities plus net energy purchase contracts (including DWR contracts allocated to the Utility’s customers), the Utility will be in a “short” position. In order to satisfy the short position, the Utility purchases electricity from suppliers prior to the hour- and day-ahead CAISO scheduling timeframes, or in the real-time market. When the Utility’s supply of electricity from its own generation resources plus net energy purchase contracts exceeds customer demand, the Utility is in a “long” position. When the Utility is in a long position, the Utility sells the excess supply in the real-time market. The CAISO currently administers a real-time wholesale market for the sale of electric energy. This market is used by the CAISO to fine tune the balance of supply and demand in real time.

Price risk is associated with the uncertainty of prices when buying or selling to reduce open positions (short or long positions). This price risk is mitigated by electricity price caps. The FERC has adopted a “soft” cap on energy prices of $400 per MWh that applies to the spot market (i.e., real-time, hour-ahead and day-ahead markets) throughout the WECC area. (A “soft” cap allows market participants to submit bids that exceed the bid cap if adequately justified, but does not allow such bids to set the market clearing price. A “hard” cap prohibits bids that exceed the cap, regardless of the seller’s costs.)

As part of the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) initiative, the CAISO plans to implement a change to the day-ahead, hour-ahead and real-time markets including new offer price "hard" caps of $500/MWh when MRTU begins, rising to $750/MWh after the twelfth month of MRTU, and finally to $1,000/MWh after the twenty-fourth month. The CAISO has also filed tariff amendments pending approval with the FERC stating that for settlements purposes, all prices shall not exceed $2,500/MWh and shall not be less than negative $2,500/MWh during the first twelve months of operation. After delaying the MRTU start date several times, the CAISO has stated that the start date will be April 1, 2009.

The amount of electricity the Utility needs to meet the demands of customers 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.

Lengthy, unexpected outages of the Utility's generation facilities or other facilities from which it purchases electricity also could cause the Utility to be in a short position. It is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010, if suitable storage facilities are not available for spent nuclear fuel, which would cause a significant increase in the Utility's short position (see “Spent Nuclear Fuel Storage Proceedings” above). If any of the above events were to occur, the Utility may find it necessary to procure electricity from third parties at then-current market prices.

In December 2007, the DWR terminated a contract with Calpine Corporation to purchase 1,000 MW of base load power needed by the Utility’s customers and replaced it with a 180 MW tolling arrangement. In addition, the DWR may try to terminate or renegotiate other long-term power purchase contracts it has entered into with other power suppliers. To the extent DWR does terminate or renegotiate other contracts, the Utility will be responsible for procuring additional electricity to meet its customers’ demand, potentially at then-current market prices.

The Utility expects to satisfy at least some of the forecasted short position through the CPUC-approved contracts it has entered into in accordance with its CPUC-approved long-term procurement plan covering 2007 through 2016. The Utility recovers the costs incurred under these contracts and other electricity procurement costs through retail electricity rates that are adjusted whenever the forecasted aggregate over-collections or under-collections of the Utility’s procurement costs for the current year exceed 5% of the Utility's prior year electricity procurement revenues. The Chapter 11 Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. As long as these cost recovery mechanisms remain in place, adverse market price changes are not expected to impact the Utility's net income. The Utility is at risk to the extent that the CPUC may in the future disallow portions or the full costs of procurement transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.

Electric Transmission Congestion Rights

Among other features, the CAISO’s MRTU initiative provides that electric transmission congestion costs and credits will be determined between any two locations and charged to the market participants, including load serving entities, taking energy that passes between those locations. The CAISO also will provide Congestion Revenue Rights (“CRRs”) to allow market participants, including load serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes both an allocation phase (in which load serving entities receive CRRs at no cost) and an auction phase (priced at market, and available to all market participants).

The Utility has been allocated and has acquired via auction certain CRRs as of December 31, 2008, and anticipates acquiring additional CRRs through the allocation and auction phases prior to the MRTU effective date, to be used when MRTU becomes effective. During 2008, the Utility participated in an auction to acquire additional firm electricity transmission rights (“FTRs”) in order to hedge its physical and financial risk until the MRTU becomes effective. The CAISO has delayed the start date of MRTU several times, but is now targeting April 1, 2009.

Natural Gas Procurement (Electric Portfolio)

A portion of the Utility's electric portfolio is exposed to natural gas price risk. The Utility manages this risk in accordance with its risk management strategies included in electricity procurement plans approved by the CPUC. The CPUC did not approve the Utility’s proposed electric portfolio gas hedging plan that was included in the Utility’s long-term procurement plan. Instead, the CPUC deferred consideration of the proposal to another proceeding. The CPUC ordered the Utility to continue operating under the previously approved gas hedging plan. The expenses associated with the hedging plan are expected to be recovered through rates.

Natural Gas Procurement (Core Customers)

The Utility generally enters into physical and financial natural gas commodity contracts from one to twelve months in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased in the monthly and, to a lesser extent, daily spot market to meet such seasonal demand. The Utility's cost of natural gas purchased for its core customers includes costs for the commodity, Canadian and interstate transportation, and intrastate gas transmission and storage.

Under the CPIM, the Utility's purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive in their rates 80% of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this cost recovery mechanism remains in place, changes in the price of natural gas are not expected to materially impact net income.

For the CPIM period ending October 31, 2008, the CPUC will audit the results of the Utility’s CPIM performance. Subject to the audit results, a shareholder award may be recorded during 2009. For the CPIM period ending October 31, 2007, the Utility earned a shareholder award of $10.1 million, which was recorded in the second quarter of 2008. The CPUC will audit the results of the Utility’s CPIM performance ending October 31, 2008. Subject to the audit results, a shareholder award may be recorded during 2009.

Nuclear Fuel

The Utility purchases nuclear fuel for Diablo Canyon through contracts with terms ranging from 1 to 16 years. These long-term nuclear fuel agreements are with large, well-established international producers in order to diversify its commitments and provide security of supply. Nuclear fuel costs are recovered from customers through rates and, therefore, changes in nuclear fuel prices are not expected to materially impact net income.

Natural Gas Transportation and Storage

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 approximately $16 million at December 31, 2008. The Utility's high, low, and average values-at-risk during the twelve months ended December 31, 2008 were approximately $34 million, $16 million, and $25 million, respectively.

Convertible Subordinated Notes

At December 31, 2008, PG&E Corporation had outstanding approximately $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,059 shares of PG&E Corporation common stock, at a conversion price of $15.09 per share. The conversion price is subject to adjustment for significant changes in the number of outstanding shares of PG&E Corporation’s common stock. In addition, 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 price. During 2008, PG&E Corporation paid approximately $28 million of "pass-through dividends" to the holders of Convertible Subordinated Notes. On January 15, 2009, PG&E Corporation paid approximately $7 million of “pass-through dividends.”

On January 13, 2009, PG&E Corporation, upon request by an investor, converted $28 million of Convertible Subordinated Notes into 1,855,865 shares at the conversion price of $15.09 per share. Total outstanding Convertible Subordinated Notes after the conversion is approximately $252 million.

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), the dividend participation rights of the Convertible Subordinated Notes are considered to be embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Consolidated Financial Statements. The payment of pass-through dividends is recognized as an operating cash flow in PG&E Corporation’s Consolidated Statements of Cash Flows. Changes in the fair value are recognized in PG&E Corporation’s Consolidated Statements of Income as a non-operating expense or income (in Other income (expense), net). At December 31, 2008 and December 31, 2007, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $42 million and $62 million, respectively, of which $28 million and $25 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $14 million and $37 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabilities - Other) in the accompanying Consolidated Balance Sheets. The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”), resulting in a $6 million increase in the liability. (See Note 12 of the Notes to the Consolidated Financial Statements for further discussion of the implementation of SFAS No. 157.)

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 December 31, 2008, if interest rates changed by 1% for all current variable rate debt issued by PG&E Corporation and the Utility, the change would affect net income for the twelve months ended December 31, 2008 by approximately $0.1 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

The Utility manages credit risk associated with its wholesale customers and 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 and a detailed credit analysis is performed at least annually. The Utility ties many energy contracts to master agreements that require security (referred to as “credit collateral”) in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The following table summarizes the Utility's net credit risk exposure to its wholesale customers and counterparties, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at December 31, 2008 and December 31, 2007:

(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%
December 31, 2008	$	240	$	84	$	156		2	$	107
December 31, 2007	$	311	$	91	$	220		2	$	111

(1) Gross credit exposure equals mark-to-market value on 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 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 Consolidated Financial Statements in accordance with GAAP 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 outlined below.

Regulatory Assets and Liabilities

The Utility accounts for the financial effects of regulation in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility's operations.

Under SFAS No. 71, incurred costs that would otherwise be charged to expense may be capitalized and recorded as regulatory assets if it is probable that the incurred costs will be recovered in future rates. The regulatory assets are amortized over future periods consistent with the inclusion of costs in authorized customer rates. If costs that a regulated enterprise expects to incur in the future are being recovered through current rates, SFAS No. 71 requires that the regulated enterprise record those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future must be recorded as regulatory liabilities. Regulatory assets and liabilities are recorded when it is probable, as defined in SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”), that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. The Utility also maintains regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that can be recovered through rates.

If the Utility determined that it could not apply SFAS No. 71 to its operations or, if under SFAS No. 71, it could not conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be charged to income in the period in which they were incurred. If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At December 31, 2008, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $7.2 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.4 billion.

Environmental Remediation Liabilities

Given the complexities of the legal and regulatory environment in which the environmental laws operate, the process of estimating environmental remediation liabilities is subjective. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable, as defined in SFAS No. 5, and the cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At December 31, 2008, the Utility's accrual for undiscounted and gross environmental liabilities was approximately $568 million. The accrual for undiscounted and gross environmental liabilities is representative of future events that are probable. In determining maximum undiscounted future costs, events that are reasonably possible but not probable are included in the estimation. The Utility's undiscounted future costs could increase to as much as $944 million if other potentially responsible parties are not able to contribute to the settlement of these costs or the extent of contamination or necessary remediation is greater than anticipated.

Asset Retirement Obligations

The Utility accounts for its long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - An Interpretation of SFAS No. 143” (“FIN 47”). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47 and costs recovered through the ratemaking process.

The fair value of asset retirement obligations (“ARO”) is dependent upon the following components:

●	Decommissioning costs - The estimated costs for labor, equipment, material, and other disposal costs;

●	Inflation adjustment - The estimated cash flows are adjusted for inflation estimates;

●	Discount rate - The fair value of the obligation is based on a credit-adjusted risk free rate that reflects the risk associated with the obligation; and

●	Third-party mark-up adjustments - Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset in accordance with SFAS No. 143.

●	Estimated date of decommissioning - The fair value of the obligation will change based on the expected date of decommissioning.

Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, a premature shutdown of the nuclear facilities at Diablo Canyon would increase the likelihood of an earlier start to decommissioning and cause an increase in the obligation. (See Note 13 of the Notes to the Consolidated Financial Statements and “Capital Expenditures” and “Results of Operations” above.) Additionally, if the inflation adjustment increased 25 basis points, this would increase the balance for ARO by approximately 0.81%. Similarly, an increase in the discount rate by 25 basis points would decrease ARO by 0.57%. At December 31, 2008, the Utility's estimated cost of retiring these assets is approximately $1.7 billion.

Accounting for Income Taxes

PG&E Corporation and the Utility account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” and FIN 48, which requires judgment regarding the potential tax effects of various transactions and ongoing operations to determine obligations owed to tax authorities. (See Note 10 of the Notes to the Consolidated Financial Statements.) Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates of the timing and probability of recognition of income and deductions. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in tax laws, PG&E Corporation's financial condition in future periods, and the final review of filed tax returns by taxing authorities.

Pension and Other Postretirement Plans

Certain employees and retirees of PG&E Corporation and its subsidiaries participate in qualified and non-qualified non-contributory defined benefit pension plans. Certain retired employees and their eligible dependents of PG&E Corporation and its subsidiaries also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as “other postretirement benefits”). Amounts that PG&E Corporation and the Utility recognize as costs and obligations to provide pension benefits under SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS No. 87”) and other benefits under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (“SFAS No. 106”) are based on a variety of factors. These factors include the provisions of the plans, employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions utilized, PG&E Corporation's and the Utility's estimate of these costs and obligations is a critical accounting estimate.

Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases, and the expected return on plan assets. Actuarial assumptions used in determining other postretirement benefit obligations include the discount rate, the expected return on plan assets, and the assumed health care cost trend rate. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe the assumptions used are appropriate, significant differences in actual experience, plan changes or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses.

In accordance with accounting rules, changes in benefit obligations associated with these assumptions may not be recognized as costs on the income statement. Differences between actuarial assumptions and actual plan results are deferred in Accumulated other comprehensive income (loss) and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market value of the related plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. As such, benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. PG&E Corporation's and the Utility's recorded pension expense totaled $169 million in 2008, $117 million in 2007, and $185 million in 2006 in accordance with the provisions of SFAS No. 87. PG&E Corporation and the Utility's recorded expense for other postretirement benefits totaled $44 million in 2008, $44 million in 2007, and $49 million in 2006 in accordance with the provisions of SFAS No. 106.

As of December 31, 2006, PG&E Corporation and the Utility adopted SFAS No. 158, which requires the funded status of an entity’s plans to be recognized on the balance sheet with an offsetting entry to Accumulated other comprehensive income (loss), resulting in no impact to the statement of income.

Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. Since 1993, the CPUC has authorized the Utility to recover the costs associated with its other postretirement benefits based on the lesser of the SFAS No. 106 expense or the annual tax-deductible contributions to the appropriate trusts.

PG&E Corporation's and the Utility's funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. Based upon current assumptions and available information, the Utility has not identified any minimum funding requirements related to its pension plans.

In July 2006, the CPUC approved the Utility’s request to resume rate recovery for the Utility’s contributions to the qualified defined benefit pension plan for the years 2006 through 2009, with the goal of fully-funded status by 2010. In March 2007, the CPUC extended the terms of the decision for one additional year, through 2010. PG&E Corporation and the Utility made total pension contributions of approximately $139 million in 2007 and $182 million in 2008, and expect to make total contributions of approximately $176 million annually for the years 2009 and 2010. PG&E Corporation and the Utility made total contributions of approximately $38 million in 2007 and $48 million in 2008 related to their other postretirement benefit plans and expect to make contributions of approximately $58 million annually for the years 2009 and 2010.

Pension and other postretirement benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and other postretirement benefit payments. Consistent with the trusts' investment policies, assets are invested in U.S. equities, non-U.S. equities, absolute return securities, and fixed income securities. Investment securities are exposed to various risks, including interest rate risk, credit risk, and overall market volatility. As a result of these risks, it is reasonably possible that the market values of investment securities could increase or decrease in the near term. Increases or decreases in market values could materially affect the current value of the trusts and, as a result, the future level of pension and other postretirement benefit expense.

Fixed income returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were estimated based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility’s defined benefit pension plan, the assumed return of 7.3% compares to a ten-year actual return of 4.6%.

The rate used to discount pension and other postretirement benefit plan liabilities was based on a yield curve developed from market data of approximately 300 Aa-grade non-callable bonds at December 31, 2008. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

(in millions)	Increase (decrease) in Assumption			Increase in 2008 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2008
Discount rate		(0.5	)%	$	15	$	667
Rate of return on plan assets		(0.5	)%		47		-
Rate of increase in compensation		0.5	%		17		162

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

(in millions)	Increase (decrease) in Assumption			Increase in 2008 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2008
Health care cost trend rate		0.5	%	$	6	$	33
Discount rate		(0.5	)%		6		75

NEW ACCOUNTING POLICIES

Fair Value Measurements

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157. SFAS No. 157 establishes a fair value hierarchy that prioritizes inputs to valuation techniques used to measure the fair value of an asset or liability. The objective of a fair value measurement is to determine the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. (See Notes 2 and 12 of the Notes to the Consolidated Financial Statements for further discussion on SFAS No. 157.)

Level 3 Instruments at Fair Value

As Level 3 measurements are based on unobservable inputs, significant judgment may be used in the valuation of these instruments. Accordingly, the following table sets forth the fair values of instruments classified as Level 3 within the fair value hierarchy, along with a description of the valuation technique for each type of instrument:

	Value as of
(in millions)	December 31, 2008			January 1, 2008
Money market investments (held by PG&E Corporation)	$	12		$	-
Nuclear decommissioning trusts		5			8
Price risk management instruments		(156	)		115
Long term disability trust		78			87
Dividend participation rights		(42	)		(68	)
Other		(2	)		(4	)
Total Level 3 Instruments	$	(105	)	$	138

Level 3 fair value measurements represent approximately 5% of the total net value of all fair value measurements of PG&E Corporation. During the twelve months ended December 31, 2008, there were no material increases or decreases in Level 3 assets or liabilities resulting from a transfer of assets or liabilities from, or into, Level 1 or Level 2. The majority of these instruments are accounted for in accordance with SFAS No. 71, as amended, as they are expected to be recovered or refunded through regulated rates. Therefore, changes in the aggregate fair value of these assets and liabilities (including realized and unrealized gains and losses) are recorded within regulatory accounts in the accompanying Consolidated Balance Sheets with the exception of the dividend participation rights associated with PG&E Corporation’s Convertible Subordinated Notes. The changes in the fair value of the dividend participation rights are reflected in Other income (expense), net in PG&E Corporation’s Consolidated Statements of Income. Changes in the fair value of the Level 3 instruments did not have a material effect on liquidity and capital resources as of December 31, 2008.

Money Market Investments

PG&E Corporation invests in AAA-rated money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued based on observable inputs such as expected yield and credit quality and are thus classified as Level 1 instruments. Approximately $164 million held in money market funds are recorded as Cash and cash equivalents in PG&E Corporation’s Consolidated Balance Sheets.

As of December 31, 2008, PG&E Corporation classified approximately $12 million invested in one money market fund as a Level 3 instrument because the fund manager imposed restrictions on fund participants’ redemption requests. PG&E Corporation’s investment in this money market fund, previously recorded as Cash and cash equivalents, is recorded as Prepaid expenses and other in PG&E Corporation’s Consolidated Balance Sheets.

Nuclear Decommissioning Trusts and Long Term-Disability Trust

The nuclear decommissioning trusts and the long-term disability trust primarily hold equities, debt securities, mutual funds, and life insurance policies. These instruments are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. The nuclear decommissioning trusts and the long-term disability trust also invest in long-term commingled funds, which are funds that consist of assets from several accounts that are intermingled. These commingled funds have liquidity restrictions and lack an active market for individual shares of the funds; therefore the trusts’ investments in these funds are classified as Level 3. The Level 3 nuclear decommissioning trust assets decreased from approximately $8 million at January 1, 2008 to approximately $5 million at December 31, 2008. The decrease of approximately $3 million for the twelve months ended December 31, 2008 was primarily due to unrealized losses of these commingled fund investments. The Level 3 long-term disability trust assets decreased from approximately $87 million at January 1, 2008 to approximately $78 million at December 31, 2008. This decrease of approximately $9 million for the twelve months ended December 31, 2008 was primarily due to net purchases and unrealized losses on these commingled fund investments.

Price Risk Management Instruments

The price risk management instrument category is comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. PG&E Corporation and the Utility apply consistent valuation methodology to similar instruments. Since the Utility’s contracts are used within the regulatory framework, regulatory accounts are recorded to offset the associated gains and losses of these derivatives, which will be reflected in future rates. The Level 3 price risk management instruments decreased from an asset of approximately $115 million as of January 1, 2008 to a liability of approximately $156 million as of December 31, 2008. This decrease of approximately $271 million was primarily due to a reduction in commodity prices.

	Value (in millions)
Type of Instrument	December 31, 2008			January 1, 2008
Options (exchange-traded and OTC)	$	28		$	50
Congestion revenue rights, Firm transmission rights, and Demand response contracts		99			61
Swaps and forwards		(366	)		(2	)
Netting and collateral		83			6
Total	$	(156	)	$	115

All options (exchange-traded and OTC) are valued using the Black’s Option Pricing Model and classified as Level 3 measurements primarily due to volatility inputs. The Utility receives implied volatility for options traded on exchanges which may be adjusted to incorporate the specific terms of the Utility’s contracts, such as strike price or location.

CRRs allow market participants, including load serving entities, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market to be established when MRTU becomes effective. FTRs allow market participants, including load serving entities to hedge both the physical and financial risk associated with CAISO-imposed congestion charges until the MRTU becomes effective. 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 aggregators’ customers at times of peak energy demand or in response to a CAISO alert or other emergency. As the markets for CRRs, FTRs, and demand response contracts have minimal activity, observable inputs may not be available in pricing these instruments. Therefore, the pricing models used to value these instruments often incorporate significant estimates and assumptions that market participants would use in pricing the instrument. Accordingly, they are classified as Level 3 measurements. When available, observable market data is used to calibrate pricing models.

The remaining Level 3 price risk management instruments are OTC derivative instruments that are valued using pricing models based on the net present value of estimated future cash flows based on broker quotations. The Utility receives multiple non-binding broker quotes for certain locations which are generally averaged for valuation purposes. In certain circumstances, broker quotes may be interpolated or extrapolated to fit the terms of a contract, such as frequency of settlement or tenor. These instruments are classified within Level 3 of the fair value hierarchy.

Dividend Participation Rights

The dividend participation rights of the Convertible Subordinated Notes are embedded derivative instruments in accordance with SFAS No. 133 and, therefore, are bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Consolidated Balance Sheets. The dividend participation rights are valued based on the net present value of estimated future cash flows using internal estimates of common stock dividends. These rights are recorded as Current Liabilities-Other and Noncurrent Liabilities-Other in PG&E Corporation’s Consolidated Balance Sheets. (See Note 4 of the Notes to the Consolidated Financial Statements for further discussion of these instruments.)

Nonperformance Risk

In accordance with SFAS No. 157, PG&E Corporation and the Utility incorporate the risk of nonperformance into the valuation of their fair value measurements. Nonperformance risk adjustments on the Utility’s price risk management instruments are based on current market inputs when available, such as credit default swaps spreads. When such information is not available, internal models may be used. The nonperformance risk adjustment for the net price risk management instruments contributed less than 5% of the value on December 31, 2008. As the Utility’s contracts are used within the regulatory framework, the nonperformance risk adjustments are recorded to regulatory accounts and do not impact earnings.

See Note 12 of the Notes to the Consolidated Financial Statements for further discussion on fair value measurements.

Amendment of FASB Interpretation No. 39

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of FASB Staff Position on FASB Interpretation 39, “Amendment of FASB Interpretation No. 39” (“FIN 39-1”). Under FIN 39-1, a reporting entity is required to offset the cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement when reporting those amounts on a net basis. The provisions of FIN 39-1 are applied retrospectively. See Note 11 of the Notes to the Consolidated Financial Statements for further discussion and financial statement impact of the implementation of FIN 39-1.

Fair Value Option

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value with changes in fair value recognized in earnings. PG&E Corporation and the Utility have not elected the fair value option for any assets or liabilities as of and during the three and twelve months ended December 31, 2008; therefore, the adoption of SFAS No. 159 did not impact the Condensed Consolidated Financial Statements.

Disclosure by Public Entities (Enterprises) about Transfers of Financial Asset and Interests in Variable Interest Entities

On December 31, 2008, PG&E Corporation and the Utility adopted the provisions of FASB Staff Position (“FSP”) FAS 140-4 and FIN 46R-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (“FSP FAS 140-4 and FIN 46R-8”). This FSP amends FASB No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities” to require public companies to provide additional qualitative disclosures about transfers of financial assets. This guidance also amended FIN 46R to require public enterprises to provide additional disclosures about their involvement with variable interest entities ("VIEs") when they are the primary beneficiary of the VIE, hold a significant variable interest in the VIE, or are sponsors of and hold a variable interest in the VIE.

Although PG&E Corporation and Utility were not impacted by the amendment to FASB No. 140 as of December 31, 2008, they were impacted by the amendment to FIN 46R, primarily through the Utility’s power purchase agreements which may be considered significant variable interests. Accordingly, when the Utility has a significant variable interest in a VIE, FSP FAS 140-4 and FIN 46R-8 require additional disclosures about the entity, the extent of the Utility’s involvement with the entity, and the Utility’s methodology for evaluating these entities under FIN 46R. See “Consolidation of Variable Interest Entities” within Note 2 to the Consolidated Financial Statements for expanded disclosures required by FSP FAS 140-4 and FIN 46R-8.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133. An entity is required to provide qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures on fair value amounts of, and gains, and losses on derivative instruments, and disclosures relating to credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective prospectively for fiscal years beginning after November 15, 2008. PG&E Corporation and the Utility will include the expanded disclosure required by SFAS No. 161 in their combined quarterly report on Form 10-Q for the quarter ended March 31, 2009.

Disclosures about Employers’ Postretirement Benefit Plan Asset - an amendment to FASB Statement No. 132(R)

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP 132(R)-1”). FSP 132(R)-1 amends and expands the disclosure requirements of SFAS No. 132. An entity is required to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. Additionally, quantitative disclosures are required showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets which are measured using significant unobservable inputs. FSP 132(R)-1 is effective prospectively for fiscal years ending after December 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP 132(R)-1.

Issuer's Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement - an amendment to FASB Statement No. 107 and FASB Statement No. 133

In September 2008, the FASB issued Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”). EITF 08-5 clarifies the unit of account in determining the fair value of a liability under SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” or SFAS No. 133 “Accounting for Derivatives and Hedging Activities”. Specifically, it requires an entity to incorporate any third-party credit enhancements that are issued with and are inseparable from a debt instrument into the fair value of that debt instrument. EITF 08-5 is effective prospectively for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. PG&E Corporation and the Utility are currently evaluating the impact of EITF 08-5.

Equity Method Investment Accounting Consideration - an amendment to Accounting Principles Board No. 18

In November 2008, the FASB issued EITF 08-6, “Equity Method Accounting Considerations” (“EITF 08-6”). EITF 08-6 clarifies the application of equity method accounting under Accounting Principles Board 18, “The Equity Method of Accounting for Investments in Common Stock”. Specifically, it requires companies to initially record equity method investments based on the cost accumulation model, precludes separate other-than-temporary impairment tests on an equity method investee’s indefinite-lived assets from the investee’s test, requires companies to account for an investee's issuance of shares as if the equity method investor had sold a proportionate share of its investment, and requires that an equity method investor continue to apply the guidance in paragraph 19(l) of Opinion 18 upon a change in the investor’s accounting from the equity method to the cost method. EITF 08-6 is effective prospectively for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. PG&E Corporation and the Utility are currently evaluating the impact of EITF 08-6.

TAX MATTERS

During the fourth quarter of 2008, PG&E Corporation and the IRS finalized the settlement of the IRS’ audits of PG&E Corporation’s consolidated tax returns for tax years 2001 through 2004. As a result of the settlement, PG&E Corporation recognized after-tax income of approximately $257 million, including interest, in the fourth quarter of 2008. Approximately $154 million of this amount related to NEGT, PG&E Corporation’s former subsidiary, and was recorded as income from discontinued operations. Approximately $60 million of the $257 million in net income relates to the Utility. PG&E Corporation expects to receive a tax refund from the IRS of approximately $310 million, plus interest, as a result of the settlement, of which approximately $170 million will be allocated to the Utility.

Also, on January 30, 2009, PG&E Corporation reached a tentative agreement with the IRS to resolve refund claims related to the 1998 and 1999 tax years that, if approved by the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”), would result in a cash refund of approximately $200 million, plus interest, to be allocated completely to the Utility. The Joint Committee’s decision is currently expected in the second quarter of 2009, and if approved, PG&E Corporation expects to receive the refund by 2009 year end. See Note 10 of the Notes to the Consolidated Financial Statements for discussion of tax matters.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local environmental laws and permits. (See “Risk Factors” below.) 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 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. See “Critical Accounting Policies” above and Note 17 of the Notes to the Consolidated Financial Statements for a discussion of estimated environmental remediation liabilities.

In addition, 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. Depending on the form of the final federal or state regulations that may ultimately be adopted, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final federal or state regulations require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. See Note 17 of the Notes to the Consolidated Financial Statements for more information.

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. See Note 17 of the Notes to the Consolidated Financial Statements for a discussion of the accrued liability for legal matters.

RISK FACTORS

Risks Related to PG&E Corporation

As a holding company, PG&E Corporation depends on cash distributions and reimbursements from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.

PG&E Corporation is a holding company with no revenue generating operations of its own. PG&E Corporation’s ability to pay interest on its $280 million of convertible subordinated notes, and to pay dividends on its common stock, as well as satisfy its other financial obligations, primarily depends on the earnings and cash flows of the Utility and the ability of the Utility to distribute cash to PG&E Corporation (in the form of dividends and share repurchases) and reimburse PG&E Corporation for the Utility’s share of applicable expenses. Before it can distribute cash to PG&E Corporation, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and meet its obligations to employees and creditors. If the Utility is not able to make distributions to PG&E Corporation or to reimburse PG&E Corporation, PG&E Corporation’s ability to meet its own obligations could be impaired and its ability to pay dividends could be restricted.

PG&E Corporation could be required to contribute capital to the Utility or be denied distributions from the Utility to the extent required by the CPUC’s determination of the Utility’s financial condition.

The CPUC imposed certain conditions when it approved the original formation of a holding company for the Utility, including an obligation by PG&E Corporation’s Board of Directors to give "first priority" to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC later issued decisions adopting an expansive interpretation of PG&E Corporation’s obligations under this condition, including the requirement that PG&E Corporation "infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve.” The CPUC’s interpretation of PG&E Corporation’s obligation under the first priority condition could require PG&E Corporation to infuse the Utility with significant capital in the future, or could prevent distributions from the Utility to PG&E Corporation, either of which could materially restrict PG&E Corporation’s ability to pay or increase its common stock dividend, meet other obligations, or execute its business strategy.

Adverse resolution of pending litigation against PG&E Corporation involving PG&E Corporation’s alleged violation of the CPUC’s so-called “first priority condition” holding company conditions could have a material adverse effect on PG&E Corporation’s financial condition, results of operations and cash flow.

In 2002, the California Attorney General and the City and County of San Francisco filed complaints against PG&E Corporation alleging that PG&E Corporation failed to provide adequate financial support to the Utility in 2000 and 2001 during the California energy crisis and wrongfully transferred funds from the Utility to PG&E Corporation during the period 1997 through 2000 (primarily in the form of dividends and stock repurchases), and from PG&E Corporation to other affiliates of PG&E Corporation, in violation of the first priority and other holding company conditions. The complaints claim these alleged violations constituted unfair or fraudulent business acts or practices in violation of Section 17200 of the California Business and Professions Code. The plaintiffs seek restitution of amounts alleged to have been wrongly transferred, estimated by plaintiffs to be approximately $5 billion, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of not less than $500 million, and costs of suit, among other remedies. Adverse resolution of this pending litigation could have a material, adverse effect on PG&E Corporation’s financial condition, results of operations and cash flows.

Risks Related to PG&E Corporation and the Utility

It is uncertain whether PG&E Corporation or the Utility will be able to successfully access the capital markets or finance planned capital expenditures on favorable terms or rates.

The Utility’s ability to fund its operations, pay principal and interest on its debt, fund capital expenditures and provide collateral to support its natural gas and electricity procurement hedging contracts depends on the levels of its operating cash flow and access to the capital markets, in particular its ability to sell commercial paper and long-term unsecured debt. In addition, PG&E Corporation’s ability to make planned investments in natural gas pipeline projects depends on the ability of the Utility to pay dividends to PG&E Corporation and PG&E Corporation’s independent access to the capital markets. PG&E Corporation may also be required to access the capital markets when the Utility is successful in selling long-term debt so that it may make the equity contributions required to maintain the Utility’s applicable equity ratio.

If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation. PG&E Corporation also would need to consider its alternatives, such as contributing capital to the Utility, to enable the Utility to fulfill its obligation to serve. If PG&E Corporation is required to contribute equity to the Utility, it would be required to secure these funds from the capital markets.

PG&E Corporation’s and the Utility’s ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in their credit ratings, changes in the federal or state regulatory environment affecting energy companies, the overall health of the energy industry, volatility in electricity or natural gas prices, and general economic and market conditions.

The capital and credit markets have been experiencing extreme volatility and disruption for more than 12 months. The recent financial distress experienced at major financial institutions has caused significant disruption in the capital markets, particularly in the commercial paper markets where short-term interest rates have increased significantly, available maturities have shortened and access has generally contracted. Although the U.S. government has enacted legislation and created programs to help stabilize credit markets and financial institutions and restore liquidity, it is uncertain whether these programs individually or collectively will have beneficial effects in the credit markets or will reduce volatility or uncertainty in the financial markets.

The volume of utility bond issuances has decreased as a result of greater difficulty in issuing such bonds and the increase in the interest rate spread over Treasury bills for all such bonds. It may be more difficult or undesirable to issue new long-term debt. To the extent such conditions persist, the more significant the implications become for the Utility, including the potential that adequate capital is not available to fund the Utility’s operations and planned capital expenditures. If the Utility is unable, in part or in whole, to fund its operations and planned capital expenditures there could be a material adverse effect on PG&E Corporation and the Utility’s results of operations, cash flows and financial condition.

Market performance or changes in other assumptions could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension, other post-retirement benefits plans, and nuclear decommissioning trusts.

PG&E Corporation and the Utility provide defined benefit pension plans and other post-retirement benefits for certain employees and retirees. The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities. Up to approximately 60% of the plan assets and trust assets have generally been invested in equity securities, which are subject to market fluctuation. A decline in the market value may increase the funding requirements for these plans and trusts.

The costs of providing pension and other post-retirement benefits is also affected by other factors, including the assumed rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, levels of assumed interest rates, future government regulation and prior contributions to the plans. Similarly, funding requirements for the nuclear decommissioning trusts are affected by changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements, changes in assumptions as to decommissioning dates, technology and costs of labor, materials and equipment change and assumed rate of return on plan assets. For example, changes in interest rates affect the liabilities under the plans as interest rates decrease, the liabilities increase, potentially increasing the funding requirements.

Primarily as a result of the 2008 performance of the equities market, at December 31, 2008, the funding status of the plans and nuclear decommissioning trusts are in an underfunded status. If the Utility is required to make significant unplanned contributions to fund the pension and post-retirement plans and nuclear decommissioning trusts and is unable to recover such contributions in rates, the contributions would negatively affect PG&E Corporation and the Utility’s financial condition, cash flows and results of operations.

Other Utility obligations, such as its workers’ compensation obligations, are not separately earmarked for recovery through rates. Therefore, increases in the Utility’s workers’ compensation liabilities and other unfunded liabilities caused by a decrease in the applicable discount rate negatively impact net income.

The Utility’s revenues, operating results and financial condition may fluctuate with the economy and the economy’s corresponding impact on the Utility’s customers.

The Utility is impacted by the economic cycle of the customers it serves. The declining economy in the Utility’s service territory and the declines in the values of residential real estate have resulted in lower customer demand and lower customer growth at the Utility, and an increase in unpaid customer accounts receivable. Increasing unemployment could further reduce demand as residential customers voluntarily reduce their consumption of electricity in response to decreases in their disposable income. A sustained downturn or sluggishness in the economy is further reflected in the Utility’s sales to industrial and commercial customers. Although the Utility generally recovers its costs through rates, regardless of sales volume, rate pressures increase when the costs are borne by a smaller customer base increasing the potential that costs would be disallowed by regulators.

The completion of capital investment projects is subject to substantial risks and the rate at which the Utility invests and recovers capital will directly affect net income.

The Utility’s ability to develop new generation facilities and to invest in its electric and gas systems is subject to many risks, including risks related to securing adequate and reasonably priced financing, obtaining and complying with the terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Third-party contractors on which the Utility depends to develop these projects also face many of these risks, although their actions and responsiveness in the event of negative developments may be less within and in fact beyond the Utility’s control. Changes in tax laws or policies, such as those relating to production and investment tax credits for renewable energy projects, may also affect when or whether the Utility develops a potential project. In addition, reduced forecasted demand for electricity and natural gas as a result of the slowing economy may also increase the risk that projects are deferred, abandoned or cancelled.

In addition, the Utility may incur costs that it will not be permitted to recover from customers. The Utility’s amount and timing of capital expenditures can be affected by changes in the economy that impact customer demand and the rate of new customer connections. If capital spending in a particular time period is greater than assumed when rates were set, earnings could be negatively affected by an increase in depreciation, taxes and financing interest and the absence of authorized revenue requirements to recover a return on equity on the amount of capital expenses which exceeds assumed amounts. If capital spending in a particular time period is lower than assumed when rates were set, the Utility’s rate base would be lower depriving the Utility of the opportunity to earn a return on equity on the delayed expenditures.

PG&E Corporation’s investment in new natural gas pipelines projects is subject to similar risks, and, in the case of the proposed Pacific Connector, is subject to third parties’ developing a proposed liquefied natural gas storage terminal. In addition, pipeline project development is conditioned on obtaining certain levels of capacity commitments from shippers. Many of these conditions must be satisfied by PG&E Corporation’s investment partners.

PG&E Corporation’s and the Utility’s financial statements reflect various estimates, assumptions and values, and changes to these estimates, assumptions, and values, as well as the application of and changes in accounting rules, standards, policies, guidance, or interpretations could materially affect PG&E Corporation’s and the Utility’s financial condition or results of operations.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the disclosure of contingencies. (See the discussion under Note 1 of the Notes to the Consolidated Financial Statements and the section entitled “Critical Accounting Policies” in the MD&A.) If the information on which the estimates and assumptions are based prove to be incorrect or incomplete, if future events do not occur as anticipated, or if applicable accounting guidance, policies or interpretation change, management’s estimates and assumptions will change as appropriate. A change in management’s estimates or assumptions or the recognition of actual losses that differ from the amount of estimated losses, could have a material impact on PG&E Corporation and the Utility’s financial condition and results of operations. For example, if management can no longer assume that potentially responsible parties will pay a material share of the costs of environmental remediation or if PG&E Corporation or the Utility incur losses in connection with environmental remediation, litigation or other legal, administrative or regulatory proceedings that materially exceed the provision it estimated for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flow would be materially adversely affected.

PG&E Corporation’s and the Utility’s financial condition depends upon the Utility's ability to recover its costs in a timely manner from the Utility's customers through regulated rates and otherwise execute its business strategy.

The Utility is a regulated entity subject to CPUC and FERC jurisdiction in almost all aspects of its business, including the rates, terms and conditions of its services, procurement of electricity and natural gas for its customers, issuance of securities, dispositions of utility assets and facilities, and aspects of the siting and operation of its electricity and natural gas operating assets. Executing the Utility’s business strategy depends on periodic regulatory approvals related to these and other matters.

The Utility’s financial condition particularly depends on its ability to recover in rates, in a timely manner, the costs of electricity and natural gas purchased for its customers, its operating expenses, and an adequate return of and on the capital invested in its utility assets, including the costs of long-term debt and equity issued to finance their acquisition. Unanticipated changes in operating expenses or capital expenditures can cause material differences between forecasted costs used to determine rates and actual costs incurred which, in turn, affect the Utility’s ability to earn its authorized rate of return. The Utility’s revenue requirements for its basic electric and natural gas distribution operations and its electric generation operations have been set by the CPUC through 2010. The Utility has been implementing various measures to improve operating efficiency and achieve sustainable cost-savings to offset increases in labor costs, to improve the safety and reliability of the electric and natural gas systems, to expand and maintain the electric and natural gas systems, technology infrastructure and support, and other increases in operating and maintenance costs. Since the Utility’s next GRC will not be effective until January 1, 2011, the Utility plans to continue its cost-savings efforts. If the Utility is unable to identify, implement and sustain new cost-saving initiatives, PG&E Corporation's and the Utility’s financial condition, results of operations and cash flows would be adversely affected.

The CPUC also has authorized the Utility to collect rates to recover the costs of various public policy programs that provide customer incentives and subsidies for energy efficiency programs and for the development and use of renewable and self-generation technologies. In addition, the CPUC has authorized ratemaking mechanisms that permit the utilities to earn incentives (or incur a reimbursement obligation) depending on the extent to which the utilities meet the CPUC’s energy savings and demand reduction goals over three-year program cycles. There is considerable uncertainty about how the costs and the savings attributable to these energy efficiency programs will be measured and verified. As customer rates rise to reflect these subsidies, customer incentives, or shareholder incentives, the risk may increase that the CPUC or another state authority will disallow recovery of some of the Utility’s costs based on a determination that the costs were not reasonably incurred or for some other reason, resulting in stranded investment capital.

In addition, changes in laws and regulations or changes in the political and regulatory environment may have an adverse effect on the Utility’s ability to timely recover its costs and earn its authorized rate of return. During the 2000-2001 energy crisis that followed the implementation of California’s electric industry restructuring, the Utility could not recover in rates the high prices it had to pay for wholesale electricity, which ultimately caused the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Even though the Chapter 11 Settlement Agreement and current regulatory mechanisms contemplate that the CPUC will give the Utility the opportunity to recover its reasonable and prudent future costs of electricity and natural gas in its rates, the CPUC may not find that all of the Utility’s costs are reasonable and prudent, or the CPUC may take actions or fail to take actions that would be to the Utility's detriment. In addition, the bankruptcy court having jurisdiction of the Chapter 11 Settlement Agreement or other courts may fail to implement or enforce the terms of the Chapter 11 Settlement Agreement and the Utility’s plan of reorganization in a manner that would produce the economic results that PG&E Corporation and the Utility intend or anticipate.

The Utility’s failure to recover any material amount of its costs through its rates in a timely manner would have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows.

The Utility faces uncertainties associated with the future level of bundled electric load for which it must procure electricity and secure generating capacity and, under certain circumstances, may not be able to recover all of its costs.

The Utility must procure electricity to meet customer demand, plus applicable reserve margins, not satisfied from the Utility's own generation facilities and existing electricity contracts. When customer demand exceeds the amount of electricity that can be economically produced from the Utility’s own generation facilities plus net energy purchase contracts (including DWR contracts allocated to the Utility’s customers), the Utility will be in a “short” position. When the Utility’s supply of electricity from its own generation resources plus net energy purchase contracts exceeds customer demand, the Utility is in a “long” position.

The amount of electricity the Utility needs to meet the demands of customers that is not satisfied from the Utility’s own generation facilities, existing purchase contracts or DWR contracts allocated to the Utility’s customers, could increase or decrease due to a variety of factors, including, without limitation, a change in the number of the Utility’s customers, periodic expirations or terminations of existing electricity purchase contracts, including DWR contracts, execution of new energy and capacity purchase contracts, fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract by the Utility, implementation of new energy efficiency and demand response programs, the reallocation of the DWR power purchase contracts among California investor-owned electric utilities, and the acquisition, retirement, or closure of generation facilities. The amount of electricity the Utility would need to purchase would immediately increase if there was an unexpected outage at Diablo Canyon or any of its other significant generation facilities, if the Utility had to shut down Diablo Canyon for any reason, or if any of the counterparties to the Utility’s electricity purchase contracts or the DWR allocated contracts did not perform due to bankruptcy or for some other reason. In addition, as the electricity supplier of last resort, the amount of electricity the Utility would need to purchase also would immediately increase if a material number of customers who purchase electricity from alternate energy providers (referred to as “direct access” customers) or customers of community choice aggregators (see below) decided to return to receiving bundled services from the Utility.

If the Utility’s short position unexpectedly increases, the Utility would need to purchase electricity in the wholesale market under contracts priced at the time of execution or, if made in the spot market, at the then-current market price of wholesale electricity. The inability of the Utility to purchase electricity in the wholesale market at prices or on terms the CPUC finds reasonable or in quantities sufficient to satisfy the Utility’s short position could have a material adverse effect on the financial condition, results of operations or cash flow of the Utility and PG&E Corporation.

Alternatively, the Utility would be in a long position if the number of Utility customers declined because of a general economic downturn in the Utility service territory, the restoration of customer direct access after the DWR’s liability for its electricity purchase contracts has ended, municipalization, or the formation and operation of community choice aggregators. California law permits California cities and counties to purchase and sell electricity for all their residents who do not affirmatively elect to continue to receive electricity from the Utility, once the city or county has registered as a community choice aggregator while the Utility continues to provide distribution, metering and billing services to the community choice aggregators’ customers and serves as the electricity provider of last resort for all customers.

In addition, the Utility could lose customers, or experience lesser demand, because of increased self-generation. The risk of loss of customers and decreased demand through self-generation is increasing as the CPUC has approved various programs to provide self-generation incentives and subsidies to customers to encourage development and use of renewable and distributed generating technologies, such as solar technology. The number of the Utility’s customers also could decline due to stricter greenhouse gas regulations or other state regulations that cause customers to leave the Utility’s service territory.

If the Utility were in a long position the Utility would be required to sell the excess electricity purchased from third parties under electricity purchase contracts, possibly at a loss. In addition, excess electricity generated by the Utility’s own generation facilities may also have to be sold, possibly at a loss, and costs the Utility may have incurred to develop or acquire new generation resources may become stranded.

If the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially adversely affected.

The Utility faces significant uncertainty in connection with the implementation of the CAISO’s Market Redesign and Technology Upgrade program to restructure California’s wholesale electricity market and the potential restructuring of the CPUC’s resource adequacy program.

In response to the electricity market manipulation that occurred during the 2000-2001 energy crisis and the underlying need for improved congestion management, the CAISO has undertaken an initiative called Market Redesign and Technology Upgrade, referred to as MRTU, to implement a new day-ahead wholesale electricity market and to improve electricity grid management reliability, operational efficiencies and related technology infrastructure. MRTU will add significant market complexity and will require major changes to the Utility’s systems and software interfacing with the CAISO. MRTU is scheduled to become effective in 2009. Although the CPUC has authorized the Utility to record its related incremental capital costs and expenses, the Utility’s ability to recover these recorded amounts from customers will be subject to a future CPUC proceeding where the reasonableness of amounts recorded will be reviewed.

Among other features, the MRTU initiative provides that electric transmission congestion costs and credits will be determined between any two locations and charged to the market participants, including load-serving entities (“LSEs”) like the Utility, that take energy that passes between those locations. The CAISO also will provide CRRs to allow market participants, including LSEs, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The CAISO will release CRRs through an annual and monthly process, each of which includes both an allocation phase (in which LSEs receive CRRs at no cost) and an auction phase (priced at market, and available to all market participants). The Utility has been allocated and has acquired via auction certain CRRs as of December 31, 2008, and anticipates acquiring additional CRRs through the allocation and auction phases prior to the MRTU effective date to be used when MRTU commences.

If the Utility incurs significant costs to implement MRTU, including the costs associated with CRRs, that are not timely recovered from customers; if the new market mechanisms created by MRTU result in any price/market flaws that are not promptly and effectively corrected by the market mechanisms, the CAISO, or the FERC; if the Utility’s CRRs are not sufficient to hedge the financial risk associated with its CAISO-imposed congestion costs under MRTU; if either the CAISO’s or the Utility’s MRTU-related systems and software do not perform as intended or if the CPUC adopts comprehensive changes to its resource adequacy program that materially affect the Utility’s obligations under that program, the current cost of capacity, or the means by which the Utility procures that capacity, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially adversely affected.

The Utility may fail to realize the benefits of its advanced metering system, the advanced metering system may fail to perform as intended, or the Utility may incur unrecoverable costs to deploy the advanced metering system and associated dynamic pricing, resulting in higher costs and/or reduced cost savings.

During 2006, the Utility began to implement the SmartMeterTM advanced metering infrastructure project for residential and small commercial customers. This project, which is expected to be completed by the end of 2011, involves the installation of approximately 10 million advanced electricity and gas meters throughout the Utility’s service territory. Advanced meters will allow customer usage data to be transmitted through a communication network to a central collection point, where the data will be stored and used for billing and other commercial purposes.

The CPUC authorized the Utility to recover $1.74 billion in estimated project costs, including an estimated capital cost of $1.4 billion and approximately $54.8 million for costs related to marketing a new demand response rate based on critical peak pricing. If additional costs exceed $100 million, the additional costs will be subject to the CPUC’s reasonableness review. On December 12, 2007, and supplemented on May 14, 2008, the Utility filed an application with the CPUC requesting approval to upgrade elements of the SmartMeter™ program at an estimated cost of approximately $572 million, including approximately $463 million of capital expenditures to be recovered through electric rates beginning in 2009.

The CPUC also has ordered the Utility to implement “dynamic pricing” for its electricity customers to encourage efficient energy consumption and cost-effective demand response by more closely aligning retail rates with the wholesale market. The Utility is required to have advanced metering and billing systems in place for larger customers by May 2010 to support default rates that are based on critical peak prices and time of use. The Utility is also required to start implementing default rates based on critical peak prices and time of use for small and medium non-residential customers by February 2011. The Utility estimates it will incur approximately $155 million (including estimated capital costs of approximately $107 million) in incremental costs by the end of 2010 to implement dynamic pricing to meet the CPUC’s required schedule.

If the Utility fails to recognize the expected benefits of its advanced metering infrastructure, if the Utility incurs additional advanced metering costs that the CPUC does not find reasonable or are unrecoverable, if the Utility incurs costs to implement dynamic pricing that are not recoverable, or if the Utility cannot integrate the new advanced metering system with its billing and other computer information systems, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially adversely affected.

If the Utility cannot timely meet the applicable resource adequacy or renewable energy requirements, the Utility may be subject to penalties.

The Utility must achieve electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements. The CPUC can impose a penalty if the Utility fails to acquire sufficient capacity to meet these resource adequacy requirements for a particular year. The penalty for failure to procure sufficient system resource adequacy capacity (i.e., resources that are deliverable anywhere in the CAISO-controlled electricity grid) is equal to three times the cost of the new capacity the Utility should have secured. The CPUC has set this penalty at $120 per kW-year. The CPUC also adopted “local” resource adequacy requirements for specific regions in which locally-situated electricity capacity may be needed due to transmission constraints. The CPUC set the penalty for failure to meet local resource adequacy requirements at $40 per kW-year. In addition to penalties, the CAISO can require LSEs that fail to meet their resource adequacy requirements to pay the CAISO’s cost of buying electricity capacity to fulfill the LSEs’ resource adequacy target levels.

In addition, the RPS established under state law requires the Utility to increase its purchases of renewable energy each year, so that the amount of electricity delivered from eligible renewable resources equals at least 20% of its total retail sales by the end of 2010. The California Legislature is considering proposals to increase the RPS mandate to at least 33% by 2020. The CPUC has established penalties of $50 per MWh, up to $25 million per year, for an unexcused failure to comply with the current RPS requirements. The CPUC can excuse noncompliance if a retail seller is able to demonstrate good cause, such as insufficient transmission capacity or the failure of the renewable energy provider to timely develop a renewable resource. Following several RFOs and bilateral negotiations, the Utility entered into various agreements to purchase renewable generation to be produced by facilities proposed to be developed by third parties. The development of these renewable generation facilities are subject to many risks, including risks related to permitting, financing, technology, fuel supply, environmental, and the construction of sufficient transmission capacity. The Utility has been supporting the development of these renewable resources by working with regulatory and governmental agencies to ensure timely construction of transmission lines and permitting of proposed project sites.

If the Utility fails to meet resource adequacy requirements, the Utility may be subject to penalties imposed by the CPUC and the CAISO. In addition, if the Utility fails to meet the RPS requirements, the Utility may be subject to penalties imposed by the CPUC for an unexcused failure to comply with the RPS requirements.

The Utility faces the risk of unrecoverable costs if its customers obtain distribution and transportation services from other providers as a result of municipalization, technological change, or other forms of bypass.

The Utility’s customers could bypass its distribution and transportation system by obtaining service from other sources. This may result in stranded investment capital, loss of customer growth, and additional barriers to cost recovery. Forms of bypass of the Utility’s electricity distribution system include construction of duplicate distribution facilities to serve specific existing or new customers and condemnation of the Utility’s distribution facilities by local governments or municipal districts. Also, the Utility’s natural gas transportation facilities could risk being bypassed by interstate pipeline companies that construct facilities in the Utility’s markets or by customers who build pipeline connections that bypass the Utility’s natural gas transportation and distribution system, or by customers who use and transport LNG.

As customers and local public officials continue to explore their energy options, these bypass risks may be increasing and may increase further if the Utility’s rates exceed the cost of other available alternatives.

If the number of the Utility’s customers declines due to municipalization, or other forms of bypass, and the Utility’s rates are not adjusted in a timely manner to allow it to fully recover its investment in electricity and natural gas facilities and electricity procurement costs, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially adversely affected.

Electricity and natural gas markets are highly volatile and regulatory responsiveness to that volatility could be insufficient. Changing commodity prices may increase short-term cash requirements.

Commodity markets for electricity and natural gas are highly volatile and subject to substantial price fluctuations. A variety of factors that are largely outside of the Utility’s control may contribute to commodity price volatility, including:

●	weather;

●	supply and demand;

●	the availability of competitively priced alternative energy sources;

●	the level of production of natural gas;

●	the availability of nuclear fuel;


●	the availability of LNG supplies;

●	the price of fuels that are used to produce electricity, including natural gas, crude oil, coal and nuclear materials;


●	the transparency, efficiency, integrity and liquidity of regional energy markets affecting California;

●	electricity transmission or natural gas transportation capacity constraints;

●	federal, state, and local energy and environmental regulation and legislation; and

●	natural disasters, war, terrorism, and other catastrophic events.

The Utility’s exposure to natural gas price volatility will increase as the DWR electricity purchase contracts allocated to the Utility begin to expire or as the DWR contracts are terminated or assigned to the Utility. The final DWR contract is scheduled to expire in 2015. Although the Utility attempts to execute CPUC-approved hedging programs to reduce the natural gas price risk, these hedging programs may not be successful or the costs of the Utility’s hedging programs may not be fully recoverable.

Further, if wholesale electricity or natural gas prices significantly increase, public pressure, other regulatory influences, governmental influences, or other factors could constrain the CPUC from authorizing timely recovery of the Utility’s costs from customers. If the Utility cannot recover a material amount of its costs in its rates in a timely manner, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows would be materially adversely affected.

Economic downturn and the resulting drop in demand for energy commodities has reduced the prices of electricity and natural gas and required the Utility to deposit or return collateral in connection with its commodity hedging contracts. To the extent such commodity prices remain volatile, the Utility’s liquidity and financing needs may fluctuate due to the collateral requirements associated with its commodity hedging contracts. If the Utility is required to finance higher liquidity levels, the increased interest costs may negatively impact net income.

The Utility’s financial condition and results of operations could be materially adversely affected if it cannot successfully manage the risks inherent in operating the Utility's facilities.

The Utility owns and operates extensive electricity and natural gas facilities that are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines. The operation of the Utility’s facilities and the facilities of third parties on which it relies involves numerous risks, the realization of which can affect demand for electricity or natural gas, result in unplanned outages, reduce generating output, cause damage to the Utility's assets or operations or those of third parties on which it relies, or subject the Utility to third party claims or liability for damage or injury. These risks include:

●	operating limitations that may be imposed by environmental laws or regulations, including those relating to greenhouse gases, or other regulatory requirements;

●	imposition of stricter operational performance standards by agencies with regulatory oversight of the Utility's facilities;

●	environmental accidents, including the release of hazardous or toxic substances into the air or water, urban wildfires and other events caused by operation of the Utility’s facilities or equipment failure;

●	fuel supply interruptions;

●	equipment failure;

●	failure of the Utility’s computer information systems, including those relating to operations or financial information such as customer billing;

●	labor disputes, workforce shortage, and availability of qualified personnel;

●	weather, storms, earthquakes, wild land and other fires, floods or other natural disasters, war, pandemic and other catastrophic events;


●	explosions, accidents, dam failure, mechanical breakdowns, and terrorist activities; and

●	other events or hazards.

The Utility has undertaken a thorough review of its operating practices and procedures used in its natural gas system, including its gas leak survey practices. The Utility has determined that improvements need to be made to operating practices and procedures, including increasing the accuracy of gas maintenance records and compliance with operating procedures. In addition, the Utility intends to accelerate the work associated with system-wide gas leak surveys and targets completing this work in a little more than a year. The Utility forecasts that it will spend up to $100 million more in 2009 to perform the gas leak surveys and associated remedial work on the accelerated schedule. The CPUC’s Consumer Protection and Safety Division is conducting an informal investigation of the Utility’s natural gas distribution maintenance practices and the Utility has provided information about the Utility’s review and the remedial steps the Utility has taken. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially adversely affected if the Utility were to incur material costs or other material liabilities in connection with these operational issues that were not recoverable through rates or otherwise offset by operating efficiencies or other revenues.

In addition, the Utility’s insurance may not be sufficient or effective to provide recovery under all circumstances or against all hazards or liabilities to which the Utility is or may become subject. An uninsured loss could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows. Future insurance coverage may not be available at rates and on terms as favorable as the rates and terms of the Utility’s current insurance coverage.

The Utility may experience a labor shortage if it is unable to attract and retain qualified personnel to replace employees who retire or leave for other reasons or the Utility’s operations may be affected by labor disruptions as a substantial number of employees are covered by collective bargaining agreements that are subject to re-negotiation as their terms expire.

The Utility’s workforce is aging and many employees will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may not be successful. The Utility may be faced with a shortage of experienced and qualified personnel that could negatively impact the Utility’s operations as well as its financial condition and results of operations.

At December 31, 2008, there were 14,649 Utility employees covered by collective bargaining agreements with three unions. The terms of these agreements impact the Utility’s labor costs. While these contracts are re-negotiated, it is possible that labor disruptions could occur. In addition, it is possible that some of the remaining non-represented Utility employees will join one of these unions in the future.

The Utility’s future operations may be impacted by climate change that may have a material impact on the Utility’s financial condition and results of operations.

There is substantial uncertainty about the potential impacts of climate change on the Utility’s electricity and natural gas operations and whether climate change is responsible for increased frequency and severity of hot weather, including potentially decreased hydroelectric generation resulting from reduced runoff from snow pack and increased sea level along the Northern California coastal area. If climate change reduces the Utility’s hydroelectric generation capacity, there will be a need for additional generation capacity even if there is no change in average load. The impact of events caused by climate change could range widely, with highly localized to worldwide effects, and under certain conditions could result in a full or partial disruption of the ability of the Utility or one or more entities on which it relies to generate, transmit, transport or distribute electricity or natural gas. Even the less extreme events could result in lower revenues or increased expenses, or both; increased expenses may not be fully recovered through rates or other means in a timely manner or at all, and decreased revenues may negatively impact otherwise anticipated rates of return.

The Utility’s operations are subject to extensive environmental laws, and changes in, or liabilities under these laws could adversely affect its financial condition and results of operations.

The Utility’s operations are subject to extensive federal, state, and local environmental laws and permits. Complying with these environmental laws has, in the past, required significant expenditures for environmental compliance, monitoring and pollution control equipment, as well as for related fees and permits. Compliance in the future may require significant expenditures relating to reduction of greenhouse gases, regulation of water intake or discharge at certain facilities, and mitigation measures associated with electric and magnetic fields. Generally, the Utility has recovered the costs of complying with environmental laws and regulation in the Utility’s rates, subject to reasonableness review.

New California legislation imposes a state-wide limit on the emission of greenhouse gases that must be achieved by 2020 and prohibits LSEs, including investor-owned utilities, from entering into long-term financial commitments for generation resources unless the new generation resources conform to a greenhouse gas emission performance standard. The California Air Resources Board has proposed to implement a regional cap-and-trade program for greenhouse gas emissions focusing on the electricity and large industrial facility sectors beginning in 2012, and expanding to transportation and natural gas in 2015. Depending on how the baseline for greenhouse gas emissions level is set and how the cap-and-trade market system develops, the Utility could incur significant additional costs to ensure that it complies with the new rules as a generation owner. In addition, the price to procure electricity from other generation providers will be affected by the costs of compliance with the new rules. Although these costs are expected to be passed through to customers, there can be no assurance that the CPUC will permit full recovery of these costs especially if costs increase due to market manipulation.

In addition, the Utility already has significant liabilities (currently known, unknown, actual, and potential) related to environmental contamination at current and former Utility facilities, including natural gas compressor stations and former manufactured gas plants, as well as at third-party owned sites. The CPUC has established a special ratemaking mechanism under which the Utility is authorized to recover 90% of environmental costs associated with the clean-up of sites that contain hazardous substances (subject to some exceptions) without a reasonableness review. There is no guarantee that the CPUC will not discontinue or change this ratemaking mechanism in the future.

The Utility’s environmental compliance and remediation costs could increase, and the timing of its future capital expenditures may accelerate, if standards become stricter, regulation increases, other potentially responsible parties cannot or do not contribute to cleanup costs, conditions change or additional contamination is discovered. If the Utility must pay materially more than the amount that it currently has accrued on its Consolidated Balance Sheets to satisfy its environmental remediation obligations and cannot recover those or other costs of complying with environmental laws in its rates in a timely manner, or at all, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flow would be materially adversely affected.

The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its insurance or other source, adversely affecting its financial condition, results of operations and cash flow.

Operating and decommissioning the Utility’s nuclear power plants expose it to potentially significant liabilities and capital expenditures, including not only the risk of death, injury and property damage from a nuclear accident, but matters arising from the storage, handling and disposal of radioactive materials, including spent nuclear fuel; stringent safety and security requirements; public and political opposition to nuclear power operations; and uncertainties related to the regulatory, technological and financial aspects of decommissioning nuclear plants when their licenses expire. The Utility maintains insurance and decommissioning trusts to reduce the Utility’s financial exposure to these risks. However, the costs or damages the Utility may incur in connection with the operation and decommissioning of nuclear power plants could exceed the amount of the Utility’s insurance coverage and other amounts set aside for these potential liabilities. In addition, as an operator of two operating nuclear reactor units, the Utility may be required under federal law to pay up to $235 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility, but at any other nuclear power plant in the United States.

The NRC has broad authority under federal law to impose licensing and safety-related requirements upon owners and operators of nuclear power plants. If they do not comply, the NRC can impose fines or force a shutdown of the nuclear plant, or both, depending upon the NRC’s assessment of the severity of the situation. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon and additional significant capital expenditures could be required in the future. In addition, as required by NRC regulations, only certain key management personnel and other designated individuals may receive information from the NRC or other government agency relating to Diablo Canyon that is deemed to be classified by the governmental agency. In connection with this requirement, the Board of Directors of PG&E Corporation has adopted a resolution acknowledging that neither PG&E Corporation nor any director or officer of PG&E Corporation will (1) have access to such classified information or special nuclear material in the custody of the Utility, or (2) participate in any decision or matter pertaining to the protection of classified information and/or special nuclear material in the custody of the Utility. If one or both units at Diablo Canyon were shut down pursuant to an NRC order, or to comply with NRC licensing, safety or security requirements, or due to other safety or operational issues, the Utility’s operating and maintenance costs would increase. Further, such events may cause the Utility to be in a short position and the Utility would need to purchase electricity from more expensive sources. In addition, the Utility’s nuclear power operations are subject to the availability of adequate nuclear fuel supplies on terms that the CPUC will find reasonable.

The NRC operating licenses for Diablo Canyon require sufficient storage capacity for the radioactive spent fuel it produces. Because the U.S. Department of Energy has failed to develop a permanent national repository for the nation’s spent nuclear fuel and high-level radioactive waste produced by the nation’s nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon in on-site storage pools. The Utility also obtained a permit to construct an on-site dry cask storage facility to store spent fuel through at least 2024. An appeal related to the NRC’s permit is pending. (See the discussion above under “Regulatory Matters” and Note 13 of the Notes to the Consolidated Financial Statements.) The construction of the dry cask storage facility is complete and the initial movement of spent nuclear fuel to dry cask storage will begin in June 2009. If the Utility is unable to begin loading spent fuel by October 2010 for Unit 1 or May 2011 for Unit 2 and the Utility is otherwise unable to increase its on-site storage capacity, the Utility would have to curtail or halt operations of the unit until such time as additional safe storage for spent fuel is made available.

Furthermore, certain aspects of the Utility’s nuclear operations are subject to other federal, state, and local regulatory requirements that are overseen by other federal, state, or local agencies. For example, as discussed above under “Environmental Matters,” there is substantial uncertainty concerning the final form of federal and state regulations to implement Section 316(b) of the Clean Water Act. Depending on the nature of the final regulations that may ultimately be adopted by the EPA, the Water Board, or the California Legislature, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the federal or state final regulations require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon.

If the CPUC prohibits the Utility from recovering a material amount of its capital expenditures, nuclear fuel costs, operating and maintenance costs, or additional procurement costs due to a determination that the costs were not reasonably or prudently incurred, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flow would be materially adversely affected.

The Utility is subject to penalties for failure to comply with federal, state or local statutes and regulations. Changes in the political and regulatory environment could cause federal and state statutes, regulations, rules, and orders to become more stringent and difficult to comply with, and required permits, authorizations and licenses may be more difficult to obtain, increasing the Utility’s expenses or making it more difficult for the Utility to execute its business strategy.

The Utility must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of the CPUC, the FERC, the NRC, and other regulatory agencies relating to the aspects of its electricity and natural gas utility operations that fall within the jurisdictional authority of such agencies. These include customer billing, customer service, affiliate transactions, vegetation management, and safety and inspection practices. The Utility is subject to fines and penalties for failure to comply with applicable statutes, regulations, rules, tariffs and orders.

For example, under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards. In the fourth quarter of 2009, the Utility will undergo its first regularly-scheduled triennial audit for compliance with these standards.

In addition, there is risk that these statutes, regulations, rules, tariffs, and orders may become more stringent and difficult to comply with in the future, or that their interpretation and application may change over time and that the Utility will be determined to have not complied with such new interpretations. If this occurs, the Utility could be exposed to increased costs to comply with the more stringent requirements or new interpretations and to potential liability for customer refunds, penalties, or other amounts. If it is determined that the Utility did not comply with applicable statutes, regulations, rules, tariffs, or orders, and the Utility is ordered to pay a material amount in customer refunds, penalties, or other amounts, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flow would be materially adversely affected.

The Utility also must comply with the terms of various permits, authorizations, and licenses. These permits, authorizations, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses often have a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In connection with a license renewal, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility.

If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, or licenses, or if the Utility cannot recover any increased costs of complying with additional license requirements or any other associated costs in its rates in a timely manner, PG&E Corporation’s and the Utility’s financial condition and results of operations could be materially adversely affected.

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2008			2007			2006
Operating Revenues
Electric	$	10,738		$	9,480		$	8,752
Natural gas		3,890			3,757			3,787
Total operating revenues		14,628			13,237			12,539
Operating Expenses
Cost of electricity		4,425			3,437			2,922
Cost of natural gas		2,090			2,035			2,097
Operating and maintenance		4,201			3,881			3,703
Depreciation, amortization, and decommissioning		1,651			1,770			1,709
Total operating expenses		12,367			11,123			10,431
Operating Income		2,261			2,114			2,108
Interest income		94			164			188
Interest expense		(728	)		(762	)		(738	)
Other income (expense), net		(18	)		29			(13	)
Income Before Income Taxes		1,609			1,545			1,545
Income tax provision		425			539			554
Income From Continuing Operations		1,184			1,006			991
Discontinued Operations
NEGT income tax benefit		154			-			-
Net Income	$	1,338		$	1,006		$	991
Weighted Average Common Shares Outstanding, Basic		357			351			346
Weighted Average Common Shares Outstanding, Diluted		358			353			349
Earnings Per Common Share from Continuing Operations, Basic	$	3.23		$	2.79		$	2.78
Net Earnings Per Common Share, Basic	$	3.64		$	2.79		$	2.78
Earnings Per Common Share from Continuing Operations, Diluted	$	3.22		$	2.78		$	2.76
Net Earnings Per Common Share, Diluted	$	3.63		$	2.78		$	2.76
Dividends Declared Per Common Share	$	1.56		$	1.44		$	1.32

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	219		$	345
Restricted cash		1,290			1,297
Accounts receivable:
Customers (net of allowance for doubtful accounts of $76 million in 2008 and $58 million in 2007)		1,751			1,599
Accrued unbilled revenue		685			750
Regulatory balancing accounts		1,197			771
Inventories:
Gas stored underground and fuel oil		232			205
Materials and supplies		191			166
Income taxes receivable		120			61
Prepaid expenses and other		718			255
Total current assets		6,403			5,449
Property, Plant, and Equipment
Electric		27,638			25,599
Gas		10,155			9,620
Construction work in progress		2,023			1,348
Other		17			17
Total property, plant, and equipment		39,833			36,584
Accumulated depreciation		(13,572	)		(12,928	)
Net property, plant, and equipment		26,261			23,656
Other Noncurrent Assets
Regulatory assets		5,996			4,459
Nuclear decommissioning funds		1,718			1,979
Other		482			1,089
Total other noncurrent assets		8,196			7,527
TOTAL ASSETS	$	40,860		$	36,632

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2008			2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	287		$	519
Long-term debt, classified as current		600			-
Energy recovery bonds, classified as current		370			354
Accounts payable:
Trade creditors		1,096			1,067
Disputed claims and customer refunds		1,580			1,629
Regulatory balancing accounts		730			673
Other		343			394
Interest payable		802			697
Deferred income taxes		251			-
Other		1,567			1,374
Total current liabilities		7,626			6,707
Noncurrent Liabilities
Long-term debt		9,321			8,171
Energy recovery bonds		1,213			1,582
Regulatory liabilities		3,657			4,448
Pension and other postretirement benefits		2,088			-
Asset retirement obligations		1,684			1,579
Income taxes payable		35			234
Deferred income taxes		3,397			3,053
Deferred tax credits		94			99
Other		2,116			1,954
Total noncurrent liabilities		23,605			21,120
Commitments and Contingencies
Preferred Stock of Subsidiaries		252			252
Preferred Stock
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		-			-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 361,059,116 common and 1,287,569 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007		5,984			6,110
Common stock held by subsidiary, at cost, 24,665,500 shares in 2007		-			(718	)
Reinvested earnings		3,614			3,151
Accumulated other comprehensive income (loss)		(221	)		10
Total common shareholders' equity		9,377			8,553
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	40,860		$	36,632

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2008			2007			2006
Cash Flows From Operating Activities
Net income	$	1,338		$	1,006		$	991
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,863			1,959			1,803
Allowance for equity funds used during construction		(70	)		(64	)		(47	)
Gain on sale of assets		(1	)		(1	)		(11	)
Deferred income taxes and tax credits, net		590			55			(285	)
Other changes in noncurrent assets and liabilities		(126	)		192			151
Effect of changes in operating assets and liabilities:
Accounts receivable		(87	)		(6	)		130
Inventories		(59	)		(41	)		32
Accounts payable		(140	)		(178	)		17
Income taxes receivable/payable		(59	)		56			124
Regulatory balancing accounts, net		(394	)		(567	)		329
Other current assets		(221	)		172			(273	)
Other current liabilities		120			8			(233	)
Other		(5	)		(45	)		(14	)
Net cash provided by operating activities		2,749			2,546			2,714
Cash Flows From Investing Activities
Capital expenditures		(3,628	)		(2,769	)		(2,402	)
Net proceeds from sale of assets		26			21			17
Decrease in restricted cash		36			185			115
Proceeds from nuclear decommissioning trust sales		1,635			830			1,087
Purchases of nuclear decommissioning trust investments		(1,684	)		(933	)		(1,244	)
Other		(37	)		-			-
Net cash used in investing activities		(3,652	)		(2,666	)		(2,427	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and revolving credit facility		533			850			350
Repayments under accounts receivable facility and revolving credit facility		(783	)		(900	)		(310	)
Net issuance (repayments) of commercial paper, net of discount of $11 million in 2008, $1 million in 2007 and $2 million in 2006		6			(209	)		458
Proceeds from issuance of long-term debt, net of discount, premium and issuance costs of $19 million in 2008 and $16 million in 2007		2,185			1,184			-
Long-term debt repurchased		(454	)		-			-
Rate reduction bonds matured		-			(290	)		(290	)
Energy recovery bonds matured		(354	)		(340	)		(316	)
Common stock issued		225			175			131
Common stock repurchased		-			-			(114	)
Common stock dividends paid		(546	)		(496	)		(456	)
Other		(35	)		35			3
Net cash provided by (used in) financing activities		777			9			(544	)
Net change in cash and cash equivalents		(126	)		(111	)		(257	)
Cash and cash equivalents at January 1		345			456			713
Cash and cash equivalents at December 31	$	219		$	345		$	456
Supplemental disclosures of cash flow information
Cash paid (received) for:
Interest (net of amounts capitalized)	$	523		$	514		$	503
Income taxes, net		(112	)		537			736

Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	143	$	129	$	117
Capital expenditures financed through accounts payable		348		279		215
Stock issued in lieu of dividend		20		5		-
Assumption of capital lease obligation		-		-		408
Transfer of Gateway Generating Station asset		-		-		69

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(in millions, except share amounts)

	Common Stock Shares			Common Stock Amount			Common Stock Held by Subsidiary			Unearned Compensation			Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Share-holders' Equity			Comprehensive Income
Balance at December 31, 2005		368,268,502		$	5,827		$	(718	)	$	(22	)	$	2,139		$	(8	)	$	7,218
Net income		-			-			-			-			991			-			991		$	991
Comprehensive income																						$	991
Common stock issued		5,399,707			110			-			-			-			-			110
Accelerated share repurchase settlement of stock repurchased in 2005		-			(114	)		-			-			-			-			(114	)
Common stock warrants exercised		51,890			-			-			-			-			-			-
Common restricted stock, unearned compensation reversed in accordance with SFAS No. 123R		-			(22	)		-			22			-			-			-
Common restricted stock issued		566,255			21			-			-			-			-			21
Common restricted stock cancelled		(105,295	)		(1	)		-			-			-			-			(1	)
Common restricted stock amortization		-			20			-			-			-			-			20
Common stock dividends declared and paid		-			-			-			-			(342	)		-			(342	)
Common stock dividends declared but not yet paid		-			-			-			-			(117	)		-			(117	)
Tax benefit from employee stock plans		-			35			-			-			-			-			35
Adoption of SFAS No. 158 (net of income tax benefit of $8 million)		-			-			-			-			-			(11	)		(11	)
Other		-			1			-			-			-			-			1
Balance at December 31, 2006		374,181,059			5,877			(718	)		-			2,671			(19	)		7,811

Net income	-	-	-		-	1,006		-	1,006		$	1,006
Employee benefit plan adjustment in accordance with SFAS No. 158 (net of income tax expense of $17 million)	-	-	-		-	-		29	29			29
Comprehensive income											$	1,035
Common stock issued, net	5,465,217	175	-		-	-		-	175
Stock-based compensation amortization	-	31	-		-	-		-	31
Common stock dividends declared and paid	-	-	-		-	(379	)	-	(379	)
Common stock dividends declared but not yet paid	-	-	-		-	(129	)	-	(129	)
Tax benefit from employee stock plans	-	27	-		-	-		-	27
Adoption of FIN 48	-	-	-		-	(18	)	-	(18	)
Balance at December 31, 2007	379,646,276	6,110	(718	)	-	3,151		10	8,553

Net income	-			-			-		-		1,338			-			1,338		$	1,338
Employee benefit plan adjustment in accordance with SFAS No. 158 (net of income tax benefit of $156 million)														(231	)		(231	)		(231	)
Comprehensive income																			$	1,107
Common stock issued, net	7,365,909			247			-		-		-			-			247
Common stock cancelled	(24,665,500	)		(403	)		718		-		(315	)		-			-
Stock-based compensation amortization	-			24			-		-		-			-			24
Common stock dividends declared and paid	-			-			-		-		(417	)		-			(417	)
Common stock dividends declared but not yet paid	-			-			-		-		(143	)		-			(143	)
Tax benefit from employee stock plans	-			6			-		-		-			-			6
Balance at December 31, 2008	362,346,685		$	5,984		$	-	$	-	$	3,614		$	(221	)	$	9,377

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2008			2007			2006
Operating Revenues
Electric	$	10,738		$	9,481		$	8,752
Natural gas		3,890			3,757			3,787
Total operating revenues		14,628			13,238			12,539
Operating Expenses
Cost of electricity		4,425			3,437			2,922
Cost of natural gas		2,090			2,035			2,097
Operating and maintenance		4,197			3,872			3,697
Depreciation, amortization and decommissioning		1,650			1,769			1,708
Total operating expenses		12,362			11,113			10,424
Operating Income		2,266			2,125			2,115
Interest income		91			150			175
Interest expense		(698	)		(732	)		(710	)
Other income, net		28			52			7
Income Before Income Taxes		1,687			1,595			1,587
Income tax provision		488			571			602
Net Income		1,199			1,024			985
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	1,185		$	1,010		$	971

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas & Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance At December 31,
	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	52		$	141
Restricted cash		1,290			1,297
Accounts receivable:
Customers (net of allowance for doubtful accounts of $76 million in 2008 and $58 million in 2007)		1,751			1,599
Accrued unbilled revenue		685			750
Related parties		2			6
Regulatory balancing accounts		1,197			771
Inventories:
Gas stored underground and fuel oil		232			205
Materials and supplies		191			166
Income taxes receivable		25			15
Prepaid expenses and other		705			252
Total current assets		6,130			5,202
Property, Plant, and Equipment
Electric		27,638			25,599
Gas		10,155			9,620
Construction work in progress		2,023			1,348
Total property, plant, and equipment		39,816			36,567
Accumulated depreciation		(13,557	)		(12,913	)
Net property, plant, and equipment		26,259			23,654
Other Noncurrent Assets
Regulatory assets		5,996			4,459
Nuclear decommissioning funds		1,718			1,979
Related parties receivable		27			23
Other		407			993
Total other noncurrent assets		8,148			7,454
TOTAL ASSETS	$	40,537		$	36,310

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas & Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2008			2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	287		$	519
Long-term debt, classified as current		600			-
Energy recovery bonds, classified as current		370			354
Accounts payable:
Trade creditors		1,096			1,067
Disputed claims and customer refunds		1,580			1,629
Related parties		25			28
Regulatory balancing accounts		730			673
Other		325			370
Interest payable		802			697
Income tax payable		53			-
Deferred income taxes		257			4
Other		1,371			1,200
Total current liabilities		7,496			6,541
Noncurrent Liabilities
Long-term debt		9,041			7,891
Energy recovery bonds		1,213			1,582
Regulatory liabilities		3,657			4,448
Pension and other postretirement benefits		2,040			-
Asset retirement obligations		1,684			1,579
Income taxes payable		12			103
Deferred income taxes		3,449			3,104
Deferred tax credits		94			99
Other		2,064			1,838
Total noncurrent liabilities		23,254			20,644
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 2008 and issued 282,916,485 shares in 2007		1,322			1,415
Common stock held by subsidiary, at cost, 19,481,213 shares in 2007		-			(475	)
Additional paid-in capital		2,331			2,220
Reinvested earnings		6,092			5,694
Accumulated other comprehensive income (loss)		(216	)		13
Total shareholders' equity		9,787			9,125
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	40,537		$	36,310

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2008			2007			2006
Cash Flows From Operating Activities
Net income	$	1,199		$	1,024		$	985
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,838			1,956			1,802
Allowance for equity funds used during construction		(70	)		(64	)		(47	)
Gain on sale of assets		(1	)		(1	)		(11	)
Deferred income taxes and tax credits, net		593			43			(287	)
Other changes in noncurrent assets and liabilities		(25	)		188			116
Effect of changes in operating assets and liabilities:
Accounts receivable		(83	)		(6	)		128
Inventories		(59	)		(41	)		34
Accounts payable		(137	)		(196	)		21
Income taxes receivable/payable		43			56			28
Regulatory balancing accounts, net		(394	)		(567	)		329
Other current assets		(223	)		170			(273	)
Other current liabilities		90			24			(235	)
Other		(5	)		(45	)		(13	)
Net cash provided by operating activities		2,766			2,541			2,577
Cash Flows From Investing Activities
Capital expenditures		(3,628	)		(2,768	)		(2,402	)
Net proceeds from sale of assets		26			21			17
Decrease in restricted cash		36			185			115
Proceeds from nuclear decommissioning trust sales		1,635			830			1,087
Purchases of nuclear decommissioning trust investments		(1,684	)		(933	)		(1,244	)
Other		(25	)		-			1
Net cash used in investing activities		(3,640	)		(2,665	)		(2,426	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and revolving credit facility		533			850			350
Repayments under accounts receivable facility and revolving credit facility		(783	)		(900	)		(310	)
Net issuance (repayments) of commercial paper, net of discount of $11 million in 2008, $1 million in 2007 and $2 million in 2006		6			(209	)		458
Proceeds from issuance of long-term debt, net of discount, premium and issuance costs of $19 million in 2008 and $16 million in 2007		2,185			1,184			-
Long-term debt repurchased		(454	)		-			-
Rate reduction bonds matured		-			(290	)		(290	)
Energy recovery bonds matured		(354	)		(340	)		(316	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(568	)		(509	)		(460	)
Equity contribution		270			400			-
Other		(36	)		23			38
Net cash provided by (used in) financing activities		785			195			(544	)
Net change in cash and cash equivalents		(89	)		71			(393	)
Cash and cash equivalents at January 1		141			70			463
Cash and cash equivalents at December 31	$	52		$	141		$	70

Supplemental disclosures of cash flow information
Cash paid (received) for:
Interest (net of amounts capitalized)	$	496		$	474	$	476
Income taxes, net		(95	)		594		897
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	348		$	279	$	215
Assumption of capital lease obligation		-			-		408
Transfer of Gateway Generating Station asset		-			-		69

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(in millions)

	Preferred Stock Without Mandatory Redemption Provisions		Common Stock		Additional Paid-in Capital		Common Stock Held by Subsidiary			Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Share- holders' Equity			Comprehensive Income
Balance at December 31, 2005	$	258	$	1,398	$	1,776	$	(475	)	$	4,702		$	(9	)	$	7,650
Net income		-		-		-		-			985			-			985		$	985
Minimum pension liability adjustment (net of income tax expense of $2 million)		-		-		-		-			-			3			3			3
Comprehensive income																			$	988
Tax benefit from employee stock plans		-		-		46		-			-			-			46
Common stock dividend		-		-		-		-			(460	)		-			(460	)
Preferred stock dividend		-		-		-		-			(14	)		-			(14	)
Adoption of SFAS No. 158 (net of income tax benefit of $7 million)		-		-		-		-			-			(10	)		(10	)
Balance at December 31, 2006		258		1,398		1,822		(475	)		5,213			(16	)		8,200
Net income		-		-		-		-			1,024			-			1,024		$	1,024
Employee benefit plan adjustment in accordance with SFAS No. 158 (net of income tax expense of $17 million)		-		-		-		-			-			29			29			29
Comprehensive income																			$	1,053
Equity contribution		-		17		383		-			-			-			400
Tax benefit from employee stock plans		-		-		15		-			-			-			15
Common stock dividend		-		-		-		-			(509	)		-			(509	)
Preferred stock dividend		-		-		-		-			(14	)		-			(14	)
Adoption of FIN 48		-		-		-		-			(20	)		-			(20	)
Balance at December 31, 2007		258		1,415		2,220		(475	)		5,694			13			9,125

Net income		-		-			-			-		1,199			-			1,199		$	1,199
Employee benefit plan adjustment in accordance with SFAS No. 158 (net of income tax expense of $159 million)		-		-			-			-		-			(229	)		(229	)		(229	)
Comprehensive income																				$	970
Equity contribution		-		4			266			-		-			-			270
Tax benefit from employee stock plans		-		-			4			-		-			-			4
Common stock dividend		-		-			-			-		(568	)		-			(568	)
Common stock cancelled		-		(97	)		(159	)		475		(219	)		-			-
Preferred stock dividend		-		-			-			-		(14	)		-			(14	)
Balance at December 31, 2008	$	258	$	1,322		$	2,331		$	-	$	6,092		$	(216	)	$	9,787

See accompanying Notes to the Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility is primarily regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”).

This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 for which the Utility absorbs a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Consolidated Financial Statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions 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, discussed further below in these notes, 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 post-retirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the 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 and the Utility’s financial condition and results of operations during the period in which such change occurred.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting policies used by PG&E Corporation and the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the CPUC and the FERC.

Cash and Cash Equivalents

Invested cash and other short-term investments with original maturities of three months or less are considered cash equivalents. Cash equivalents are stated at cost, which approximates fair value. PG&E Corporation and the Utility primarily invest their cash in money market funds.

Restricted Cash

Restricted cash consists primarily of the Utility’s cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 15 of the Notes to the Consolidated Financial Statements.) Restricted cash also includes the Utility deposits of cash and cash equivalents made under certain third-party agreements.

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, delinquency rates, current economic conditions, and assessment of customer collectability. If circumstances require changes in the assumption, allowance estimates are adjusted accordingly.

Inventories

Inventories are carried at average cost and are valued at the lower of average cost or market. Inventories include materials, supplies, and natural gas stored underground. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed. Natural gas stored underground represents purchases that are injected into inventory and then expensed at average cost when withdrawn and distributed to customers or used in electric generation.

Property, Plant, and Equipment

Property, plant, and equipment are reported at their original cost. These original costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”).

The Utility’s balances as of December 31, 2008 are as follows:

(in millions)	Gross Plant as of December 31, 2008		Accumulated Depreciation as of December 31, 2008			Net Plant as of December 31, 2008
Electricity generating facilities	$	3,711	$	(1,134	)	$	2,577
Electricity distribution facilities		18,777		(6,722	)		12,055
Electricity transmission		5,150		(1,675	)		3,475
Natural gas distribution facilities		6,666		(2,544	)		4,122
Natural gas transportation		3,434		(1,482	)		1,952
Natural gas storage		55		-			55
CWIP		2,023		-			2,023
Total	$	39,816	$	(13,557	)	$	26,259

The Utility’s balances as of December 31, 2007 are as follows:

(in millions)	Gross Plant as of December 31, 2007		Accumulated Depreciation as of December 31, 2007			Net Plant as of December 31, 2007
Electricity generating facilities	$	3,004	$	(1,040	)	$	1,964
Electricity distribution facilities		17,712		(6,377	)		11,335
Electricity transmission		4,883		(1,633	)		3,250
Natural gas distribution facilities		6,302		(2,429	)		3,873
Natural gas transportation		3,271		(1,434	)		1,837
Natural gas storage		47		-			47
CWIP		1,348		-			1,348
Total	$	36,567	$	(12,913	)	$	23,654

AFUDC

AFUDC represents a method used to compensate the Utility for the estimated cost of debt and equity used to finance regulated plant additions and is recorded as part of the cost of construction projects. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. The Utility recorded AFUDC of approximately $70 million and $44 million during 2008, $64 million and $32 million during 2007, and $47 million and $20 million during 2006, related to equity and debt, respectively.

Depreciation

The Utility’s composite depreciation rate was 3.38% in 2008, 3.28% in 2007, and 3.09% in 2006.

	Estimated Useful Lives
Electricity generating facilities	4 to 37 years
Electricity distribution facilities	16 to 58 years
Electricity transmission	40 to 70 years
Natural gas distribution facilities	24 to 52 years
Natural gas transportation	25 to 45 years
Natural gas storage	25 to 48 years

The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC and depreciation expense is included in rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated future removal and remediation costs, net of any salvage value at retirement.

The Utility charges the original cost of retired plant less salvage value to accumulated depreciation upon retirement of plant in service in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71 “Accounting for the Effects of Certain Types of Regulation” as amended (“SFAS No. 71”). PG&E Corporation and the Utility expense repair and maintenance costs as incurred.

Nuclear Fuel

Property, plant, and equipment also include nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is expensed as used based on the amount of energy output.

Capitalized Software Costs

PG&E Corporation and the Utility account for internal software in accordance with the American Institute of Certified Public Accountants Statement of Position, “Accounting for the Costs of Computer Software Developed or Obtained for Internal Use” (“SOP 98-1”).

Under SOP 98-1, PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software projects to property, plant, and equipment. The Utility’s capitalized software costs totaled $522 million at December 31, 2008 and $533 million at December 31, 2007, net of accumulated amortization of approximately $280 million at December 31, 2008 and $207 million at December 31, 2007. PG&E Corporation’s capitalized software costs were less than $1 million at December 31, 2008. PG&E Corporation and the Utility amortize capitalized software costs ratably over the expected lives of the software ranging from 3 to 15 years, commencing upon operational use.

Regulation and SFAS No. 71

The Utility accounts for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. SFAS No. 71 applies to all of the Utility’s operations.

Intangible Assets

Intangible assets primarily consist of hydroelectric facility licenses and other agreements, with lives ranging from 19 to 40 years. The gross carrying amount of the hydroelectric facility licenses and other agreements was approximately $95 million at December 31, 2008 and $97 million at December 31, 2007. The accumulated amortization was approximately $35 million at December 31, 2008 and $32 million at December 31, 2007. In December 2008, the Utility obtained intangible assets related to the acquisition of development rights of the Tesla Generating Station. The value of these intangible assets, including permit and licenses, was approximately $23 million at December 31, 2008. These intangible assets have indefinite lives and will not be amortized, but an impairment test will be performed annually.

The Utility’s amortization expense related to intangible assets was approximately $4 million in 2008 and $3 million in both 2007 and 2006. The estimated annual amortization expense for 2009 through 2013 based on the December 31, 2008 intangible asset balance is approximately $4 million each year. Intangible assets are recorded to Other Noncurrent Assets - Other in the Consolidated Balance Sheets.

Consolidation of Variable Interest Entities

The Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), provides that an entity is a variable interest entity (“VIE”) if it does not have sufficient equity investment at risk, or if the holders of the entity’s equity instruments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the holder subject to the majority of the risk of loss from a VIEs activities must consolidate the VIE. However, if no holder has the majority of the risk of loss, then a holder entitled to receive a majority of the entity’s residual returns would consolidate the entity.

The majority of the Utility’s involvement with VIEs is through power purchase agreements. The Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a VIE owning one or more plants that sell substantially all of their output to the Utility. The Utility performs a quantitative assessment of power purchase agreements under FIN 46R, which includes performing an analysis considering the term of the contract compared to the remaining useful life of the plant, as well as performing an analysis of the absorption of the expected risks and rewards of the project including production risk, commodity price risk, credit risk, and tax attributes.

At December 31, 2008 there was one significant VIE. In 2007, the Utility entered into a 25-year agreement to purchase as-available electric generation output from an approximately 554-megawatt (“MW”) solar trough facility in which the Utility has a significant variable interest. Activities of this facility consist of renewable energy production from a single facility for sale to third parties. The VIE is a subsidiary of a privately held company and its activities are financed primarily through equity from investors and proceeds from non-recourse project-specific debt financing. The Utility is not considered the primary beneficiary for this VIE, as it will not absorb the majority of the entity’s expected losses or residual returns. Accordingly, the Utility has not consolidated this VIE in its consolidated financial statements. This project is expected to become operational in 2011 and no payments for energy have been made to this facility as of December 31, 2008.

The Utility is generally not subject to risk of loss from power purchase agreements as the primary obligation, according to the terms of the agreements, is to purchase as-available energy that is produced by the facility. Future payments to this facility are made based on the energy produced and are expected to be recoverable through customer rates. Additionally, no financial or other support was provided by the Utility to this VIE as of December 31, 2008.

Asset Retirement Obligations

PG&E Corporation and the Utility account for ARO in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143” (“FIN 47”). SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process. FIN 47 clarifies that if a legal obligation to perform an asset retirement obligation exists but performance is conditional upon a future event, and the obligation can be reasonably estimated, then a liability should be recognized in accordance with SFAS No. 143.

The Utility has ARO for its nuclear generation and certain fossil fuel generation facilities. The Utility has also identified ARO related to asbestos contamination in buildings, potential site restoration at certain hydroelectric facilities, fuel storage tanks, and contractual obligations to restore leased property to pre-lease condition. Additionally, the Utility has recorded ARO related to the California Gas Transmission pipeline, gas distribution, electric distribution, and electric transmission system assets.

A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2006	$	1,466
Revision in estimated cash flows		48
Accretion		95
Liabilities settled		(30	)
ARO liability at December 31, 2007		1,579
Revision in estimated cash flows		50
Accretion		106
Liabilities settled		(51	)
ARO liability at December 31, 2008	$	1,684

The Utility has identified additional ARO for which a reasonable estimate of fair value could not be made. The Utility has not recognized a liability related to these additional obligations, which include obligations to restore land to its pre-use condition under the terms of certain land rights agreements, removal and proper disposal of lead-based paint contained in some Utility facilities, removal of certain communications equipment from leased property and retirement activities associated with substation and certain hydroelectric facilities. The Utility was not able to reasonably estimate the ARO associated with these assets because the settlement date of the obligation was indeterminate and information sufficient to reasonably estimate the settlement date or range of settlement dates does not exist. Land rights, communications equipment leases, and substation facilities will be maintained for the foreseeable future, and the Utility cannot reasonably estimate the settlement date or range of settlement dates for the obligations associated with these assets. The Utility does not have information available that specifies which facilities contain lead-based paint and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligation. The Utility will maintain and continue to operate its hydroelectric facilities until operation of a facility becomes uneconomic. The operation of the majority of the Utility’s hydroelectric facilities is currently, and for the foreseeable future, economic and the settlement date cannot be determined at this time.

Impairment of Long-Lived Assets

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), PG&E Corporation and the Utility evaluate the carrying amounts of long-lived assets for impairment, based on projections of undiscounted future cash flows, whenever events occur or circumstances change that may affect the recoverability or the estimated life of long-lived assets. In the event this evaluation indicates that such cash flows are not expected to fully recover the assets, the assets are written down to their estimated fair value. No significant impairments were recorded in 2008, 2007, and 2006.

Gains and Losses on Debt Extinguishments

Gains and losses on debt extinguishments associated with regulated operations that are subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original amortization period of the debt reacquired, consistent with recovery of costs through regulated rates. Unamortized loss on debt extinguishments, net of gain, was approximately $251 million and $269 million at December 31, 2008 and 2007, respectively. The Utility’s amortization expense related to this loss was approximately $26 million in 2008 and 2007, and $27 million in 2006. Deferred gains and losses on debt extinguishments are recorded to Other Noncurrent Assets – Regulatory assets in the Consolidated Balance Sheets.

Gains and losses on debt extinguishments associated with unregulated operations are fully recognized at the time such debt is reacquired and are reported as a component of interest expense.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that result from transactions and other economic events, other than transactions with shareholders. The following table sets forth the after-tax changes in each component of accumulated other comprehensive income (loss):

	Minimum Pension Liability Adjustment			Adoption of SFAS No. 158			Employee Benefit Plan Adjustment in Accordance with SFAS No. 158			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2005	$	(8	)	$	-		$	-		$	(8	)
Period change in:
Adoption of SFAS No. 158 (net of income tax benefit of $8 million)		8			(19	)		-			(11	)
Balance at December 31, 2006	$	-		$	(19	)	$	-		$	(19	)
Period change in pension benefits and other benefits:
Unrecognized prior service cost (net of income tax expense of $18 million)		-			-			26			26
Unrecognized net gain (net of income tax expense of $195 million)		-			-			289			289
Unrecognized net transition obligation (net of income tax expense of $11 million)		-			-			16			16
Transfer to regulatory account (net of income tax benefit of $207 million) (1)		-			-			(302	)		(302	)
Balance at December 31, 2007	$	-		$	(19	)	$	29		$	10
Period change in pension benefits and other benefits:
Unrecognized prior service cost (net of income tax expense of $27 million)		-			-			37			37
Unrecognized net loss (net of income tax benefit of $1,088 million)		-			-			(1,583	)		(1,583	)
Unrecognized net transition obligation (net of income tax expense of $11 million)		-			-			15			15
Transfer to regulatory account (net of income tax expense of $894 million) (1)		-			-			1,300			1,300
Balance at December 31, 2008	$	-		$	(19	)	$	(202	)	$	(221	)


(1) The Utility recorded approximately $2,259 million in 2008 and $109 million in 2007, pre-tax, as a reduction to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71. The adjustment resulted in a regulatory asset balance at December 31, 2008. The Utility recorded approximately $44 million in 2007, pre-tax, as an addition to the existing pension regulatory liability in accordance with SFAS No. 71. See Note 14 of the Notes to the Consolidated Financial Statements for further information on pre-tax transfer amounts to the regulatory account.

There was no material difference between PG&E Corporation’s and the Utility’s accumulated other comprehensive income (loss) for the periods presented above.

Revenue Recognition

The Utility’s operating revenues are comprised of revenue from electric and natural gas distribution and transmission services and electric generation services. Amounts recorded for these services are billed to the Utility’s customers at the CPUC-approved and FERC-approved rates, which provide an authorized rate of return, and recovery of operation and maintenance and capital-related carrying costs. The Utility’s revenues are recognized as electricity and natural gas are delivered, and include amounts for services rendered but not yet billed at the end of each year.

As further discussed in Note 17 of the Notes to the Consolidated Financial Statements, in January 2001, the California Department of Water Resources (“DWR”) began purchasing electricity to meet the portion of demand of the California investor-owned electric utilities that was not being satisfied from their own generation facilities and existing electricity contracts. Under California law, the DWR is deemed to sell the electricity directly to the Utility’s retail customers, not to the Utility. The Utility acts as a pass-through entity for electricity purchased by the DWR on behalf of its customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts the amounts passed through to the DWR from its electricity revenues. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers at the CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility’s electricity revenues and from the cost of electricity in its Consolidated Statements of Income.

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Income tax expense (benefit) includes current and deferred income taxes resulting from operations during the year. Investment tax credits are amortized over the life of the related property. See Note 10 of the Notes to the Consolidated Financial Statements for further discussion of income taxes.

PG&E Corporation files a consolidated U.S. federal income tax return that includes domestic subsidiaries in which its ownership is 80% or more. In addition, PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

Nuclear Decommissioning Trusts

The Utility accounts for its investments held in the Nuclear Decommissioning Trusts in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS No. 115”), as well as FASB Staff Position Nos. 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (“SFAS Nos. 115-1 and 124-1”). Under SFAS No. 115, the Utility records realized gains and losses as additions and reductions to trust asset balances. In accordance with SFAS Nos. 115-1 and 124-1, the Utility recognizes an impairment of an investment if the fair value of that investment is less than its cost and if the impairment is concluded to be other-than-temporary. (See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.)

Accounting for Derivatives and Hedging Activities

The Utility engages in price risk management activities to manage its exposure to fluctuations in commodity prices. Price risk management activities involve entering into contracts to procure electricity, natural gas, nuclear fuel, and firm transmission rights for electricity.

The Utility uses a variety 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. Derivative instruments are recorded in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets at fair value, unless they qualify for the normal purchase and sales exception. The normal purchase and sales exception requires, among other things, physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business. Changes in the fair value of derivative instruments are recorded in earnings, or to the extent they are recoverable through regulated rates, are deferred and recorded in regulatory accounts. Derivative instruments may be designated as cash flow hedges when they are entered into to hedge variable price risk associated with the purchase of commodities. For cash flow hedges, fair value changes are deferred in accumulated other comprehensive income and recognized in earnings as the hedged transactions occur, unless they are recovered in rates, in which case, they are recorded in regulatory accounts.

In order for a derivative instrument to be designated as a cash flow hedge, the relationship between the derivative instrument and the hedged item or transaction must be highly effective in hedging the exposure to variability in expected future cash flows. The effectiveness test is performed at the inception of the hedge and each reporting period thereafter, throughout the period that the hedge is designated as such. Unrealized gains and losses related to the effective and ineffective portions of the change in the fair value of the derivative instrument, to the extent they are recoverable through rates, are deferred and recorded in regulatory accounts.

Cash flow hedge accounting is discontinued prospectively if it is determined that the derivative instrument no longer qualifies as an effective hedge, or when the forecasted transaction is no longer probable of occurring. If cash flow hedge accounting is discontinued, the derivative instrument continues to be reflected at fair value, with any subsequent changes in fair value recognized immediately in earnings. Gains and losses previously recorded in accumulated other comprehensive income (loss) will remain there until the hedged item is recognized in earnings when it matures or is exercised, unless the forecasted transaction is probable of not occurring, in which case the gains and losses from the derivative instrument will be immediately recognized in earnings. Any gains and losses that would have been recognized in earnings or deferred in accumulated other comprehensive income (loss), to the extent they are recoverable through rates, are deferred and recorded in regulatory accounts.

The fair value of derivative instruments is estimated using various methods including the use of unadjusted prices in active markets to determine the net present value of estimated future cash flows, the mid-point of quoted bid and asked forward prices, including quotes from brokers, and electronic exchanges, supplemented by online price information from news services, and the Black’s Option Pricing Model. When market data is not available, proprietary models are used to estimate fair value.

The Utility has derivative instruments for the physical delivery of commodities transacted in the normal course of business, as well as non-financial assets that are not exchange-traded. These derivative instruments are eligible for the normal purchase and sales and non-exchange traded contract exceptions under SFAS No. 133, and are not reflected in the Utility’s Consolidated Balance Sheets at fair value. They are recorded and recognized in income under the accrual method of accounting. Therefore, expenses are recognized as incurred.

The Utility has certain commodity contracts for the purchase of nuclear fuel and core gas transportation and storage contracts that are not derivative instruments and are not reflected in the Utility’s Consolidated Balance Sheets at fair value. Expenses are recognized as incurred.

See Note 11 of the Notes to the Consolidated Financial Statements.

ADOPTION OF NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”), which establishes a fair value hierarchy that prioritizes inputs to valuation techniques used to measure fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. (See Note 12 of the Notes to the Consolidated Financial Statements for further discussion on SFAS No. 157.)

Amendment of FASB Interpretation No. 39

Fair Value Option

Disclosure by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities

On December 31, 2008, PG&E Corporation and the Utility adopted the provisions of FASB Staff Position (“FSP”) FAS 140-4 and FIN 46R-8, "Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities" (“FSP FAS 140-4 and FIN 46R-8”). This FSP amends FASB No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities” to require public companies to provide additional qualitative disclosures about transfers of financial assets. This guidance also amended FIN 46R to require public enterprises to provide additional disclosures about their involvement with VIEs when they are the primary beneficiary of the VIE, hold a significant variable interest in the VIE, or are sponsors of and hold a variable interest in the VIE.

Although PG&E Corporation and the Utility were not impacted by the amendment to FASB No. 140 as of December 31, 2008, they were impacted by the amendment to FIN 46R, primarily through the Utility’s power purchase agreements which may be considered significant variable interests. Accordingly, when the Utility has a significant variable interest in a VIE, FSP FAS 140-4 and FIN 46R-8 require additional disclosures about the entity, the extent of the Utility’s involvement with the entity, and the Utility’s methodology for evaluating these entities under FIN 46R. See “Consolidation of Variable Interest Entities” within Note 2 to the Consolidated Financial Statements for expanded disclosures required by FSP FAS 140-4 and FIN 46R-8.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133. An entity is required to provide qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures on fair value amounts of, and gains, and losses on derivative instruments, and disclosures relating to credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective prospectively for fiscal years beginning after November 15, 2008. PG&E Corporation and the Utility will include the expanded disclosure required by SFAS No. 161 in their combined quarterly report on Form 10-Q for the quarter ended March 31, 2009.

Disclosures about Employers’ Postretirement Benefit Plan Asset - an amendment to FASB Statement No. 132(R)

In December 2008, the FASB issued FSP FAS 132(R)-1,”Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP 132(R)-1”). FSP 132(R)-1 amends and expands the disclosure requirements of SFAS No. 132. An entity is required to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. Additionally, quantitative disclosures are required showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets which are measured using significant unobservable inputs. FSP 132(R)-1 is effective prospectively for fiscal years ending after December 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP 132(R)-1.

Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement - an amendment to FASB Statement No. 107 and FASB Statement No. 133

Equity Method Investment Accounting Consideration - an amendment to Accounting Principles Board No. 18

In November 2008, the FASB issued Emerging Issues Task Force 08-6, “Equity Method Accounting Considerations” (“EITF 08-6”). EITF 08-6 clarifies the application of equity method accounting under Accounting Principles Board 18, “The Equity Method of Accounting for Investments in Common Stock”. Specifically, it requires companies to initially record equity method investments based on the cost accumulation model, precludes separate other-than-temporary impairment tests on an equity method investee’s indefinite-lived assets from the investee’s test, requires companies to account for an investee’s issuance of shares as if the equity method investor had sold a proportionate share of its investment, and requires that an equity method investor continue to apply the guidance in paragraph 19(l) of Opinion 18 upon a change in the investor’s accounting from the equity method to the cost method. EITF 08-6 is effective prospectively for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. PG&E Corporation and the Utility are currently evaluating the impact of EITF 08-6.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

The Utility accounts for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility’s operations.

To the extent portions of the Utility’s operations cease to be subject to SFAS No. 71, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Regulatory Assets

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,
(in millions)	2008		2007
Regulatory asset for pension benefits	$	1,624	$	-
Regulatory asset for energy recovery bonds		1,487		1,833
Regulatory assets for deferred income tax		847		732
Utility retained generation regulatory assets		799		947
Environmental compliance costs		385		328
Price risk management		362		20
Unamortized loss, net of gain, on reacquired debt		225		269
Regulatory assets associated with plan of reorganization		99		122
Contract termination costs		82		96
Scheduling coordinator costs		39		90
Other		47		22
Total regulatory assets	$	5,996	$	4,459

Regulatory asset for pension benefits represents the cumulative differences between amounts recognized in accordance with GAAP and amounts recognized for ratemaking purposes, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive income in the Consolidated Balance Sheets in accordance with SFAS No. 158 “Employers’ Accounting Defined Benefit Pension and Other Post Retirement Plans” (“SFAS No. 158”). (See Notes 2 and 14 of the Notes to the Consolidated Financial Statements.) These balances will be charged against expense to the extent that future expenses exceed amounts recoverable for regulatory purposes.

The regulatory asset for energy recovery bonds (“ERBs”), issued by PG&E Energy Recovery Funding LLC (see Note 5 of the Notes to the Consolidated Financial Statements), represents the refinancing of the settlement regulatory asset established under the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s Chapter 11 proceeding (“Chapter 11 Settlement Agreement”). (See Note 15 of the Notes to the Consolidated Financial Statements.) The Utility expects to fully recover this asset by the end of 2012.

The regulatory assets for deferred income tax represent deferred income tax benefits previously passed through to customers and are offset by deferred income tax liabilities. Tax benefits to customers have been passed through, as the CPUC requires utilities under its jurisdiction to follow the “flow-through” method of passing certain tax benefits to customers. The “flow-through” method ignores 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.

In connection with the Chapter 11 Settlement Agreement in 2004, the Utility recognized a one-time non-cash gain of $1.2 billion related to the recovery of the Utility’s retained generation regulatory assets. The Utility expects to recover the individual components of these regulatory assets over their respective lives, with a weighted average life of approximately 17 years.

Environmental compliance costs represent the portion of estimated environmental remediation liabilities 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.

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.

Unamortized loss, net of gain, on reacquired debt represents 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 18 years, and these costs will be fully recovered by 2026.

Regulatory assets associated with the Utility’s plan of reorganization include costs incurred in financing the Utility’s plan of reorganization under Chapter 11 and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization. The Utility expects to recover these costs over the remaining periods ranging from 5 to 30 years, and these costs should be fully recovered by 2034.

Contract termination costs represent amounts that the Utility incurred in terminating a 30-year power purchase agreement. This regulatory asset will be amortized and collected in rates on a straight-line basis through the end of September 2014, the power purchase agreement’s original termination date.

The regulatory asset related to scheduling coordinator costs represents costs that the Utility incurred beginning in 1998 in its capacity as a scheduling coordinator for its then existing wholesale transmission customers. The Utility expects to fully recover the scheduling coordinator costs by the end of the second quarter of 2010.

At December 31, 2008 and 2007 “Other” primarily consisted of regulatory assets relating to asset retirement obligation costs recorded in accordance with GAAP, which are probable of future recovery through the ratemaking process.

In general, the Utility does not earn a return on regulatory assets where 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.

Current Regulatory Assets

At December 31, 2008 and December 31, 2007, the Utility had current regulatory assets of approximately $355 million and $131 million, respectively, consisting primarily of the current component of price risk management regulatory assets and the current portion of long-term regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of less than one year. Current regulatory assets are included in Prepaid expenses and other in the Consolidated Balance Sheets.

Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2008		2007
Cost of removal obligation	$	2,735	$	2,568
Employee benefit plans		-		578
Public purpose programs		259		264
Recoveries in excess of asset retirement obligation		226		573
California Solar Initiative		183		159
Price risk management		81		124
Gateway Generating Station		67		67
Environmental remediation		52		66
Other		54		49
Total regulatory liabilities	$	3,657	$	4,448

Cost of removal liabilities represent revenues collected for asset removal costs that the Utility expects to incur in the future.

Employee benefit plan regulatory liability represents the cumulative differences between amounts recognized in accordance with GAAP and amounts recognized for ratemaking purposes, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive income in the Consolidated Balance Sheets in accordance with SFAS No. 158. (See Notes 2 and 14 of the Notes to the Consolidated Financial Statements.) These balances will be charged against expense to the extent that future expenses exceed amounts recoverable for regulatory purposes.

Public purpose program liabilities represent revenues designated for public purpose program costs that are expected to be incurred in the future.

Regulatory liability for recoveries in excess of asset retirement obligation represent timing differences between the recognition of an ARO in accordance with GAAP and the amounts recognized for ratemaking purposes. (See Note 13 of the Notes to the Consolidated Financial Statements.)

California Solar Initiative liabilities represent revenues collected from customers to pay for costs the Utility expects to incur in the future to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year.

The Gateway Generating Station (“Gateway”) regulatory liabilities represent future customer benefits associated with acquisition of Gateway as part of a settlement with Mirant Corporation. The associated liability will be amortized over 30 years beginning in January 2009 when Gateway was placed in service.

The insurance recoveries are refunded to customers as a reduction to rates until customers are fully reimbursed for the cost of hazardous substance remediation that has been collected in rates. (See Note 17 of the Notes to the Consolidated Financial Statements.)

“Other” is an aggregate of regulatory liabilities representing amounts collected for future costs.

Current Regulatory Liabilities

As of December 31, 2008 and 2007, the Utility had current regulatory liabilities of approximately $313 million and $280 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. Current regulatory liabilities are included in Current Liabilities – Other in the Consolidated Balance Sheets.

Regulatory Balancing Accounts

The Utility uses revenue regulatory balancing accounts to accumulate differences between revenues and the Utility’s authorized revenue requirements and cost regulatory balancing accounts to accumulate differences between incurred costs and revenues. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.

The Utility’s current regulatory balancing accounts accumulate balances until they are refunded to or received from 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 Consolidated Balance Sheets. The CPUC does not allow the Utility to offset regulatory balancing account assets against regulatory balancing account liabilities.

Current Regulatory Balancing Accounts

	Receivable (Payable)
	Balance at December 31,
(in millions)	2008			2007
Energy resource recovery	$	384		$	149
Modified transition cost		214			93
Transmission revenue		173			203
Utility generation		164			90
Energy Recovery Bonds		(231	)		(274	)
Public purpose programs		(264	)		(16	)
Reliability services		12			(96	)
Other		15			(51	)
Total regulatory balancing accounts, net	$	467		$	98

The Utility is generally authorized to recover 100% of its electric fuel and energy procurement costs. The Utility files annual forecasts of purchased power costs that it expects to incur during the following year and rates are set to recover such expected costs. The energy resource recovery account tracks actual electric costs and recoveries of fuel and energy procurement costs, excluding the DWR’s contract costs. The CPUC has established a mechanism to adjust the Utility’s 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. In accordance with this mechanism, on August 21, 2008, the CPUC approved the Utility’s request to collect from customers the forecasted 2008 end-of-year under-collection of procurement costs, due mainly to rising natural gas costs and lower than forecasted hydroelectric generation. Effective October 1, 2008, customer rates were adjusted to allow the Utility to collect $645 million in procurement costs through December 2009. On December 30, 2008, the Utility requested that its electric rates be adjusted, effective January 1, 2009, to reflect the revised forecast of electricity prices which are expected to be lower than originally forecasted as a result of lower natural gas prices. The January 1, 2009 rate changes reflect a net decrease of $101 million in electric revenues versus revenues based on rates effective October 1, 2008.

The modified transition cost balancing account is used to track the recovery of ongoing competition transition costs (“CTC”), primarily consisting of above-market costs associated with power purchase contracts that were being collected in CPUC-approved rates on or before December 20, 1995 (including costs incurred by the Utility with CPUC approval to restructure, renegotiate, or terminate the contracts). The recovery of ongoing CTC can continue for the term of the contract. The amount of above-market costs associated with the eligible power purchase contracts are determined each year in the ERRA forecast proceeding by comparing the ongoing CTC-eligible contract costs to a CPUC-approved market benchmark to determine whether there are stranded costs associated with these contracts.

The transmission revenue balancing account tracks certain electric transmission revenues for recovery from customers. The balance in this account represents the difference between transmission wheeling revenues received by the Utility from the ISO (on behalf of electric transmission wholesale customers) and refunds to customers plus interest.

The utility generation balancing account is used to record and recover the authorized revenue requirements associated with the Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses.

The balancing account for energy recovery bonds records certain benefits and costs associated with ERBs that are provided to, or received from, customers. In addition, this account ensures 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 were issued.

The balancing account for public purpose program revenues tracks the recovery of authorized public purpose program revenue requirement and the actual cost of such programs. The public purpose programs primarily consist of the electric energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs. The increase in the current balancing account liability balance at December 31, 2008 compared to the December 31, 2007 is due to a refund of approximately $230 million the Utility received from the California Energy Commission (“CEC”). The refund amount represents unspent renewables program funding collected in previous periods. The program was canceled in the beginning of 2008 and the CEC was instructed to return any unspent program funds to utilities to allow for customer refund. The refund will be returned to customers in 2009 through lower rates.

The balancing account for reliability services is a FERC-mandated balancing account to ensure that the Participating Transmission Owner neither under-recovers nor over-recovers from customers the Reliability Services costs it is assessed by the California Independent System Operator (“CAISO”).

At December 31, 2008, “Other” included the customer energy efficiency (“CEE”) incentive account, which records any incentive awards earned by the Utility for implementing CEE programs, and to reflect these earnings in rates. In December 2008, the Utility’s shareholders were awarded $41.5 million for the first interim award relating to 2006 and 2007 of the 2006-2008 energy efficiency programs, which will be collected in 2009 rates. At December 31, 2007, “Other” mainly consisted of the distribution revenue adjustment mechanism account, which records and recovers the authorized distribution revenue requirements and certain other distribution-related authorized costs.

NOTE 4: DEBT

Long-Term Debt

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

	December 31,
(in millions)	2008			2007
PG&E Corporation
Convertible subordinated notes, 9.50%, due 2010	$	280		$	280
Utility
Senior notes:
3.60% due 2009		600			600
4.20% due 2011		500			500
6.25% due 2013		400			-
4.80% due 2014		1,000			1,000
5.625% due 2017		700			500
8.25% due 2018		800			-
6.05% due 2034		3,000			3,000
5.80% due 2037		700			700
6.35% due 2038		400			-
Less: current portion		(600	)		-
Unamortized discount, net of premium		(22	)		(22	)

Total senior notes

7,478

6,278

Pollution control bonds:
Series 1996 C, E, F, 1997 B, variable rates(1), due 2026(2)		614		614
Series 1996 A, 5.35%, due 2016		200		200
Series 2004 A-D, 4.75%, due 2023		345		345
Series 2005 A-G, variable rates, due 2016 and 2026(3)		-		454
Series 2008 A-D, variable rates(4), due 2016 and 2026(5)		309		-
Series 2008 F and G, 3.75%(6), due 2018 and 2026		95		-
Total pollution control bonds		1,563		1,613
Total Utility long-term debt, net of current portion		9,041		7,891
Total consolidated long-term debt, net of current portion	$	9,321	$	8,171


(1) At December 31, 2008, interest rates on these bonds and the related loans ranged from 0.75% to 1.20%.
(2) Each series of these bonds is supported by a separate letter of credit which expires on February 24, 2012. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(3) During 2008, the credit rating of the insurer of these bonds was downgraded or put on review for possible downgrade by several credit agencies, resulting in increased interest rates. To reduce interest expense, the Utility repurchased $300 million of the 2005 bonds in March 2008 and the remaining $154 million in April 2008. In September and October 2008, all of these series, except for the Series 2005 E bonds, were refunded through the issuance of the Series 2008 A-D and F and G bonds. See footnotes 4 and 5.
(4) At December 31, 2008, interest rates on these bonds and the related loans ranged from 0.57% to 0.85%.
(5) Each series of these bonds is supported by a separate direct-pay letter of credit which expires on October 29, 2011. The Utility may choose to provide a substitute letter of credit for any series of these bonds, subject to a rating requirement.
(6) These bonds bear interest at 3.75% per year through September 19, 2010, are subject to mandatory tender on September 10, 2010, and may be remarketed in a fixed or variable rate mode.

PG&E Corporation

Convertible Subordinated Notes

At December 31, 2008, PG&E Corporation had outstanding approximately $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,059 shares of PG&E Corporation common stock, at a conversion price of $15.09 per share. The conversion price is subject to adjustment for significant changes in the number of outstanding shares of PG&E Corporation’s common stock. In addition, 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 price. During 2008, PG&E Corporation paid approximately $28 million of “pass-through dividends” to the holders of Convertible Subordinated Notes. On January 15, 2009, PG&E Corporation paid approximately $7 million of “pass-through dividends.”

In accordance with SFAS No. 133, the dividend participation rights of the Convertible Subordinated Notes are considered to be embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Consolidated Financial Statements. The payment of "pass-through dividends" is recognized as an operating cash flow in PG&E Corporation’s Consolidated Statements of Cash Flows. Changes in the fair value are recognized in PG&E Corporation’s Consolidated Statements of Income as a non-operating expense or income (in Other income (expense), net). At December 31, 2008 and December 31, 2007, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $42 million and $62 million, respectively, of which $28 million and $25 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $14 million and $37 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabilities - Other) in the accompanying Consolidated Balance Sheets. The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157, resulting in a $6 million increase in the liability. (See Note 12 of the Notes to the Consolidated Financial Statements for further discussion of the implementation of SFAS No. 157.)

Utility

Senior Notes

At December 31, 2008, the Utility had outstanding approximately $8.1 billion of senior notes with various interest rates and maturity dates, including the following issuances made during 2008. On March 3, 2008, the Utility issued $200 million principal amount of 5.625% Senior Notes due November 30, 2017 and $400 million principal amount of 6.35% Senior Notes due February 15, 2038.

On October 21, 2008 and November 18, 2008, the Utility issued $600 million and $200 million principal amount, respectively, of 8.25% Senior Notes due October 15, 2018.

On November 18, 2008, the Utility also issued $400 million principal amount of 6.25% Senior Notes due December 1, 2013.

The Utility’s senior notes are unsecured and rank equally with the Utility’s other senior unsecured and unsubordinated debt. Under the indenture for the senior notes, the Utility has agreed that it will not incur secured debt or engage in sales leaseback transactions (except for (1) debt secured by specified liens, and (2) aggregate other secured debt and sales and leaseback transactions not exceeding 10% of the Utility’s net tangible assets, as defined in the indenture) unless the Utility provides that the senior notes will be equally and ratably secured.

Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank (“CIEDB”) have issued various series of tax-exempt pollution control bonds for the benefit of the Utility. Under the pollution control bond loan agreements related to the Series 1996 A bonds, the Series 2004 A-D bonds and the Series 2008 F and G bonds, the Utility is obligated to pay on the due dates an amount equal to the principal, premium, if any, and interest on these bonds to the trustees for these bonds. With respect to the Series 1996 C, E, and F bonds, the Series 1997 B bonds and the Series 2008 A-D bonds, the Utility reimburses the letter of credit providers for their payments to the trustee for these bonds, or if a letter of credit provider fails to pay under its respective letter of credit, the Utility is obligated to pay the principal, premium, if any, and interest on those bonds. All payments on the Series 1996 C, E, and F bonds, the Series 1997 B bonds and the Series 2008 A-D bonds are made through draws on separate direct-pay letters of credit for each series issued by a financial institution.

All of the pollution control bonds financed or refinanced pollution control facilities at the Geysers geothermal power plant (“Geysers Project”) or at the Utility’s Diablo Canyon nuclear power plant ("Diablo Canyon") were issued as “exempt facility bonds” within the meaning of Section 142(a) of the Internal Revenue Code of 1954, as amended (“Code”). The Utility agrees not to take any action or fail to take any action if any such action or inaction would cause the interest on the bonds to be taxable or to be other than exempt facility bonds.

In 1999, the Utility sold the Geysers Project to Geysers Power Company, LLC pursuant to purchase and sale agreements that state that Geysers Power Company LLC will use the bond-financed facilities solely as pollution control facilities within the meaning of Section 103(b)(4)(F) of the Code. Although Geysers Power Company, LLC subsequently filed a petition for reorganization under Chapter 11, it assumed the purchase and sale agreements under its Chapter 11 plan of reorganization which became effective on January 31, 2008. The Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control bonds facilities within the meaning of Section 103(b)(4)(F) of the Code.

The Utility has obtained credit support from insurance companies for the Series 1996 A bonds and the Series 2004 A-D bonds, such that, if the Utility does not pay the principal and interest on any series of these insured bonds, the bond insurer for that series will pay the principal and interest. The Series 2005 E bonds, which are currently held by the Utility, are also insured.

In 2005, the Utility purchased financial guaranty insurance policies to insure the regularly scheduled payments on $454 million of pollution control bonds series 2005 A through G issued by the CIEDB. Interest rates on these bonds were set at auction every 7 or 35 days. In January 2008, the insurer’s credit rating was downgraded or put on review for possible downgrade by several credit agencies. This, in addition to credit issues that impacted the auction rate securities markets, resulted in increases in interest rates for these bonds. To reduce the interest rate expense, the Utility repurchased $300 million of the bonds in March 2008 and the remaining $154 million in April 2008. The Utility refunded $404 million of the bonds, as described below, and anticipates refunding the remaining $50 million of the bonds in 2009, subject to conditions in the tax-exempt bond market and the liquidity needs of the Utility.

On September 22, 2008, the CIEDB issued $50 million principal amount of pollution control bonds series F due on November 1, 2026 and $45 million principal amount of pollution control bonds series G due on December 1, 2018 for the benefit of the Utility. These series of bonds refunded the corresponding related series of 2005 bonds. Both series bear interest at 3.75% per year through September 19, 2010 and are subject to mandatory tender on September 20, 2010 at a price of 100% of the principal amount plus accrued interest. Thereafter, these series of bonds may be remarketed in a fixed or variable rate mode.

On October 29, 2008, the CIEDB issued approximately $149 million principal amount of pollution control bonds series A and B due on November 1, 2026 and $160 million principal amount of pollution control bonds series C and D due on December 1, 2016 for the benefit of the Utility. These series of bonds refunded the corresponding related series of 2005 bonds. The bonds bear interest at variable interest rates not to exceed 12% per year. As of December 31, 2008, the interest rate on the bonds ranged from 0.57% to 0.85% and resets weekly.

Repayment Schedule

At December 31, 2008, PG&E Corporation and the Utility’s combined aggregate principal repayment amounts of long-term debt are reflected in the table below:

(in millions, except interest rates)	2009			2010			2011			2012			2013			Thereafter			Total
Long-term debt:
PG&E Corporation
Average fixed interest rate		-			9.50	%		-			-			-			-			9.50	%
Fixed rate obligations		-		$	280			-			-			-			-		$	280
Utility
Average fixed interest rate		3.60	%		3.75	%		4.20	%		-			6.25	%		5.99	%		5.71	%
Fixed rate obligations	$	600		$	95		$	500			-		$	400		$	7,145		$	8,740
Variable interest rate as of December 31, 2008		-			-			0.75	%		0.92	%		-			-			0.87	%
Variable rate obligations		-			-		$	309	(1)	$	614	(2)		-			-		$	923
Total consolidated long-term debt	$	600		$	375		$	809		$	614		$	400		$	7,145		$	9,943


(1) These bonds, due in 2016-2026, are backed by a direct-pay letter of credit which expires on October 29, 2011. The bonds will be subject to a mandatory redemption unless the letter of credit is extended or replaced or the issuer consents to the continuation of these series without a credit facility. Accordingly, the bonds have been classified for repayment purposes in 2011.
(2) The $614 million pollution control bonds, due in 2026, are backed by letters of credit which expire on February 24, 2012. The bonds will be subject to a mandatory redemption unless the letters of credit are extended or replaced. Accordingly, the bonds have been classified for repayment purposes in 2012.

Credit Facilities and Short-Term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s short-term borrowings and outstanding credit facilities at December 31, 2008:

(in millions)			At December 31, 2008
Authorized Borrower	Facility	Termination Date	Facility Limit			Letters of Credit Out-standing		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	Revolving credit facility	February 2012	$	200	(1)	$	-	$	-	$	-	$	200
Utility	Revolving credit facility	February 2012		2,000	(2)		287		-		287		1,426
Total credit facilities			$	2,200		$	287	$	-	$	287	$	1,626


(1) Includes a $50 million sublimit for letters of credit and $100 million sublimit for “swingline” loans, defined as loans which are made available on a same-day basis and are repayable in full within 30 days.
(2) Includes a $950 million sublimit for letters of credit and $100 million sublimit for swingline loans.

PG&E Corporation

Revolving credit facility

PG&E Corporation has a $200 million revolving credit facility with a syndicate of lenders that expires on February 26, 2012. Borrowings under the revolving credit facility and letters of credit may be used for working capital and other corporate purposes. PG&E Corporation can, at any time, repay amounts outstanding in whole or in part. At PG&E Corporation’s request and at the sole discretion of each lender, the revolving credit facility may be extended for additional periods. PG&E Corporation has the right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $100 million provided certain conditions are met. The fees and interest rates PG&E Corporation pays under the revolving credit facility vary depending on the Utility’s unsecured debt ratings issued by Standard & Poor’s Ratings Service (“S&P”) and Moody’s Investors Service (“Moody’s”). As of December 31, 2008, the commitment from Lehman Brothers Bank, FSB (“Lehman Bank”) represented approximately $13 million, or 7%, of the total borrowing capacity under the revolving credit facility. PG&E Corporation does not expect that Lehman Bank will fund any borrowings or letter of credit draws under the revolving credit facility.

The revolving credit facility includes usual and customary covenants for credit facilities of this type, including covenants limiting liens, mergers, sales of all or substantially all of PG&E Corporation’s assets and other fundamental changes. In general, the covenants, representations and events of default mirror those in the Utility’s revolving credit facility, discussed below. In addition, the revolving credit facility also requires that PG&E Corporation maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% and that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securities of the Utility. At December 31, 2008, PG&E Corporation met both of these tests.

Utility

Revolving credit facility

The Utility has a $2 billion revolving credit facility with a syndicate of lenders that expires on February 26, 2012. Borrowings under the revolving credit facility and letters of credit are used primarily for liquidity and to provide credit enhancements to counterparties for natural gas and energy procurement transactions. The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility so that liquidity from the revolving credit facility is available to repay outstanding commercial paper. As of December 31, 2008, the commitment from Lehman Bank, represented approximately $60 million, or 3%, of the revolving credit facility. Lehman Bank has failed to fund its portion of borrowings under the revolving credit facility since September 2008 and the Utility does not expect that Lehman Bank will fund any future borrowings or letter of credit draws.

The revolving credit facility includes usual and customary covenants for credit facilities of this type, including covenants limiting liens to those permitted under the senior notes’ indenture, mergers, sales of all or substantially all of the Utility’s assets and other fundamental changes. In addition, the revolving credit facility also requires that the Utility maintain a debt to capitalization ratio of at most 65% as of the end of each fiscal quarter. At December 31, 2008, the Utility met this ratio test.

Commercial Paper Program

The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to cover fluctuations in cash flow requirements. Liquidity support for these borrowings is provided by available capacity under the Utility’s revolving credit facility, as described above. The commercial paper may have maturities up to 365 days and ranks equally with the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance. At December 31, 2008, the average yield was approximately 2.48%.

NOTE 5: ENERGY RECOVERY BONDS AND RATE REDUCTION BONDS

Energy Recovery Bonds

In conjunction with the Chapter 11 Settlement Agreement, the Utility was authorized to recover $2.2 billion, resulting in a regulatory asset. (See Note 3 of the Notes to the Consolidated Financial Statements.) To lower the cost borne by customers, ERBs were issued to finance the regulatory asset at an interest rate lower than the rate of return allowed on the regulatory asset. In 2005, PG&E Energy Recovery Funding, LLC (“PERF”), a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion supported by a dedicated rate component (“DRC”). 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 DRC. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility's electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of the bond principal, interest, and miscellaneous expenses associated with the bonds.

The first series of ERBs issued on February 10, 2005 included five classes aggregating approximately $1.9 billion principal amount with scheduled maturities ranging from September 25, 2006 to December 25, 2012. Interest rates on the remaining four outstanding classes range from 3.87% for the earliest maturing class, to 4.47% for the latest maturing class. The proceeds of the first series of ERBs were paid by PERF to the Utility and were used by the Utility to refinance the remaining unamortized after-tax balance of the settlement regulatory asset. The second series of ERBs, issued on November 9, 2005, included three classes aggregating approximately $844 million principal amount, with scheduled maturities ranging from June 25, 2009 to December 25, 2012. Interest rates on the three classes range from 4.85% for the earliest maturing class to 5.12% for the latest maturing class. The proceeds of the second series of ERBs were paid by PERF to the Utility to pre-fund the Utility's tax liability that will be due as the Utility collects the DRC charges from customers.

The total amount of ERB principal outstanding was $1.6 billion at December 31, 2008 and $1.9 billion at December 31, 2007. The scheduled principal repayments for ERBs are reflected in the table below:

(in millions)	2009				2010				2011				2012				Total
Utility
Average fixed interest rate			4.36	%			4.49	%			4.59	%			4.66	%			4.53	%
Energy recovery bonds		$	370			$	386			$	404			$	423			$	1,583

While PERF is a wholly owned consolidated 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.

Rate Reduction Bonds

In December 1997, PG&E Funding LLC, a limited liability corporation wholly owned by and consolidated with the Utility, issued $2.9 billion of rate reduction bonds (“RRBs”). The proceeds of the RRBs were used by PG&E Funding LLC to purchase from the Utility the right, known as “transition property,” to be paid a specified amount from a non-bypassable charge levied on residential and small commercial customers. The RRBs were paid in full when they matured on December 26, 2007 and there are no future principal or interest payments.

NOTE 6: DISCONTINUED OPERATIONS

National Energy & Gas Transmission, Inc. (“NEGT”) was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. NEGT filed a voluntary petition for relief under Chapter 11 on July 8, 2003. On October 29, 2004, NEGT’s plan of reorganization became effective (“effective date”), at which time NEGT emerged from Chapter 11 and PG&E Corporation’s equity ownership in NEGT was cancelled. PG&E Corporation ceased including NEGT and its subsidiaries in its consolidated income tax returns beginning October 29, 2004. PG&E Corporation will continue to report resolution of NEGT matters in discontinued operations.

On the effective date, PG&E Corporation recorded a net of tax gain on disposal of NEGT of $684 million. On October 28, 2008, PG&E Corporation resolved 2001-2004 audits with the Internal Revenue Service ("IRS") and recognized after-tax income of approximately $257 million in the fourth quarter of 2008, of which $154 million was related to NEGT and recorded as income from discontinued operations. See Note 10 of the Notes to the Consolidated Financial Statements for further discussion of the resolution of the 2001-2004 audits.

At December 31, 2008 and 2007, PG&E Corporation’s Consolidated Balance Sheets included the following assets and liabilities related to NEGT:

(in millions)	2008		2007
Current Assets
Income taxes receivable	$	137	$	33
Current Liabilities
Income taxes payable		-		-
Other		10		11
Noncurrent Liabilities
Income taxes payable		3		74
Deferred income taxes		7		34
Other		12		14

NOTE 7: COMMON STOCK

PG&E Corporation

PG&E Corporation has authorized 800 million shares of no-par common stock, of which 362,346,685 shares were issued and outstanding at December 31, 2008 and 379,646,276 shares were issued and outstanding at December 31, 2007. At December 31, 2007, Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, held 24,665,500 shares of PG&E Corporation common stock. Effective August 29, 2008, Elm Power Corporation was dissolved, and the shares subsequently cancelled.

Of the 362,346,685 shares issued and outstanding at December 31, 2008, 1,287,569 shares were granted as restricted stock as share-based compensation awarded under the PG&E Corporation Long-Term Incentive Program and the 2006 Long-Term Incentive Plan (“2006 LTIP”) and 6,876,919 shares were issued upon the exercise of employee stock options, for the account of 401(k) plan participants, and for the Dividend Reinvestment and Stock Purchase Plan. (See Note 14 of the Notes to the Consolidated Financial Statements.)

Utility

The Utility is authorized to issue 800 million shares of its $5 par value common stock, of which 264,374,809 shares were issued and outstanding as of December 31, 2008 and 282,916,485 shares were issued and outstanding as of December 31, 2007. At December 31, 2007, PG&E Holdings, LLC, a wholly owned subsidiary of the Utility, held 19,481,213 shares of the Utility common stock. Effective August 29, 2008, PG&E Holdings, LLC, was dissolved, and the shares subsequently cancelled. As of December 31, 2008, PG&E Corporation held all of the Utility’s outstanding common stock.

The Utility may pay common stock dividends and repurchase its common stock, provided that cumulative preferred dividends on its preferred stock are paid.

Dividends

During 2008, PG&E Corporation paid common stock dividends of $1.53 per share, totaling $573 million, including $28 million that was paid to Elm Power Corporation. On December 17, 2008, the Board of Directors of PG&E Corporation declared a dividend of $0.39 per share, totaling $141 million, which was paid on January 15, 2009 to shareholders of record on December 31, 2008.

During 2007, the Utility paid common stock dividends of $547 million. Approximately $509 million of common stock dividends were paid to PG&E Corporation and the remaining amount was paid to PG&E Holdings, LLC. During 2007, PG&E Corporation paid common stock dividends of $1.41 per share totaling $529 million, including approximately $35 million that was paid to Elm Power Corporation.

During 2006, the Utility paid common stock dividends of $494 million. Approximately $460 million of common stock dividends were paid to PG&E Corporation and the remaining amount was paid to PG&E Holdings, LLC. During 2006, PG&E Corporation paid common stock dividends of $1.32 per share, totaling $489 million, including approximately $33 million that was paid to Elm Power Corporation.

PG&E Corporation and the Utility record common stock dividends declared to Reinvested earnings.

NOTE 8: PREFERRED STOCK

PG&E Corporation has authorized 85 million shares of preferred stock, which may be issued as redeemable or nonredeemable preferred stock. No preferred stock of PG&E Corporation has been issued.

Utility

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. The Utility specifies that 5,784,825 shares of the $25 par value preferred stock authorized are designated as nonredeemable preferred stock without mandatory redemption provisions. The remainder of the 75 million shares of $25 par value preferred stock and the 10 million shares of $100 par value preferred stock may be issued as redeemable or nonredeemable preferred stock.

At December 31, 2008 and 2007, the Utility had issued and outstanding 5,784,825 shares of nonredeemable $25 par value preferred stock without mandatory redemption provisions. Holders of the Utility's 5.0%, 5.5%, and 6.0% series of nonredeemable $25 par value preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

At December 31, 2008 and 2007, the Utility had issued and outstanding 4,534,958 shares of redeemable $25 par value preferred stock without mandatory redemption provisions. The Utility's redeemable $25 par value preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2008, annual dividends ranged from $1.09 to $1.25 per share and redemption prices ranged from $25.75 to $27.25 per share.

The last of the Utility’s redeemable $25 par value preferred stock with mandatory redemption provisions was redeemed on May 31, 2005. Currently the Utility does not have any shares of the $100 par value preferred stock with or without mandatory redemption provisions outstanding.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. During the years ended December 31, 2008, 2007, and 2006, the Utility paid approximately $14 million of dividends on preferred stock without mandatory redemption provisions. On December 17, 2008, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock totaling approximately $3 million that was paid on February 15, 2009 to shareholders of record on January 30, 2009. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.

NOTE 9: EARNINGS PER SHARE

Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, by 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 Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of a participating security. All PG&E Corporation's participating securities participate on a 1:1 basis with shares of common stock.

PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS in accordance with SFAS No. 128, “Earnings Per Share” (“SFAS No. 128”). Under SFAS No. 128, PG&E Corporation is required to assume that shares underlying stock options, other stock-based compensation, and warrants are issued and that the proceeds received by PG&E Corporation from exercise of these options and warrants are assumed to be used to purchase common shares at the average market price during the reported period. The incremental shares, the difference between the number of shares assumed issued upon exercise and the number of shares assumed purchased is included in weighted average common shares outstanding for the purpose of calculating diluted EPS.

The following is a reconciliation of PG&E Corporation's net income and weighted average shares of common stock outstanding for calculating basic and diluted net income per share:

	Year ended December 31,
(in millions, except per share amounts)	2008		2007		2006

Net Income	$	1,338	$	1,006	$	991
Less: distributed earnings to common shareholders		560		508		460
Undistributed earnings		778		498		531
Less: undistributed earnings from discontinued operations		154		-		-
Undistributed earnings from continuing operations	$	624	$	498	$	531

Common shareholders earnings
Basic
Distributed earnings to common shareholders	$	560	$	508	$	460
Undistributed earnings allocated to common shareholders - continuing operations		592		472		503
Undistributed earnings allocated to common shareholders - discontinued operations		146		-		-
Total common shareholders earnings, basic	$	1,298	$	980	$	963
Diluted
Distributed earnings to common shareholders	$	560	$	508	$	460
Undistributed earnings allocated to common shareholders - continuing operations		593		473		504
Undistributed earnings allocated to common shareholders - discontinued operations		146		-		-
Total common shareholders earnings, diluted	$	1,299	$	981	$	964

Weighted average common shares outstanding, basic		357		351		346
9.50% Convertible Subordinated Notes		19		19		19
Weighted average common shares outstanding and participating securities, basic		376		370		365

Weighted average common shares outstanding, basic		357		351		346
Employee share-based compensation and accelerated share repurchases (1)		1		2		3
Weighted average common shares outstanding, diluted		358		353		349
9.50% Convertible Subordinated Notes		19		19		19
Weighted average common shares outstanding and participating securities, diluted		377		372		368

Net earnings per common share, basic
Distributed earnings, basic (2)	$	1.57	$	1.45	$	1.33
Undistributed earnings - continuing operations, basic		1.66		1.34		1.45
Undistributed earnings - discontinued operations, basic		0.41		-		-
Total	$	3.64	$	2.79	$	2.78
Net earnings per common share, diluted
Distributed earnings, diluted	$	1.56	$	1.44	$	1.32
Undistributed earnings - continuing operations, diluted		1.66		1.34		1.44
Undistributed earnings - discontinued operations, diluted		0.41		-		-
Total	$	3.63	$	2.78	$	2.76


(1) Includes approximately one million shares of PG&E Corporation common stock treated as outstanding in connection with accelerated share repurchase agreements (ASRs) for 2006. The remaining shares of approximately two million at December 31, 2006 relate to share-based compensation and are deemed to be outstanding under SFAS No. 128 for the purpose of calculating EPS. PG&E Corporation has no remaining obligation under these ASRs as of December 31, 2007.
(2) “Distributed earnings, basic” differs 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.

PG&E Corporation stock options to purchase 11,935 and 7,285 shares were excluded from the computation of diluted EPS for 2008 and 2007, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these years. All PG&E Corporation stock options were included in the computation of diluted EPS for 2006 because the exercise price of these stock options was lower than the average market price of PG&E Corporation common stock during the year.

PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted EPS.

NOTE 10: INCOME TAXES

The significant components of income tax (benefit) expense for continuing operations were:

	PG&E Corporation												Utility
	Year Ended December 31,
(in millions)	2008				2007				2006				2008				2007				2006
Current:
Federal		$	(268	)		$	526			$	743			$	(188	)		$	563			$	771
State			33				140				201				24				149				210
Deferred:
Federal			604				(81	)			(286	)			596				(92	)			(276	)
State			62				(40	)			(98	)			62				(43	)			(97	)
Tax credits, net			(6	)			(6	)			(6	)			(6	)			(6	)			(6	)
Income tax expense		$	425			$	539			$	554			$	488			$	571			$	602

The following describes net deferred income tax liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2008		2007		2008		2007
Deferred income tax assets:
Customer advances for construction	$	199	$	143	$	199	$	143
Reserve for damages		130		173		129		173
Environmental reserve		225		172		225		172
Compensation		339		162		306		129
Other		231		289		201		261
Total deferred income tax assets	$	1,124	$	939	$	1,060	$	878
Deferred income tax liabilities:
Regulatory balancing accounts	$	1,425	$	1,219	$	1,425	$	1,219
Property related basis differences		2,819		2,290		2,813		2,293
Income tax regulatory asset		345		298		345		298
Unamortized loss on reacquired debt		102		110		102		110
Other		81		75		81		66
Total deferred income tax liabilities	$	4,772	$	3,992	$	4,766	$	3,986
Total net deferred income tax liabilities	$	3,648	$	3,053	$	3,706	$	3,108
Classification of net deferred income tax liabilities:
Included in current liabilities	$	251	$	-	$	257	$	4
Included in noncurrent liabilities		3,397		3,053		3,449		3,104
Total net deferred income tax liabilities	$	3,648	$	3,053	$	3,706	$	3,108

The differences between income taxes and amounts calculated by applying the federal statutory rate to income before income tax expense for continuing operations were:

	PG&E Corporation							Utility
	Year Ended December 31,
	2008			2007		2006		2008		2007		2006

Federal statutory income tax rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		3.1		4.2		4.3		3.3		4.3		4.6
Effect of regulatory treatment of fixed asset differences		(3.2)		(3.0)		(1.2)		(3.1)		(2.9)		(1.1)
Tax credits, net		(0.5)		(0.7)		(0.6)		(0.5)		(0.7)		(0.6)
IRS Audit Settlements		(7.1)		-		-		(4.1)		-		-
Other, net		(0.9)		(0.6)		(1.6)		(1.7)		0.1		0.1
Effective tax rate		26.4	%	34.9	%	35.9	%	28.9	%	35.8	%	38.0	%

On January 1, 2007, PG&E Corporation and the Utility adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). Under FIN 48, a tax benefit can be recognized only if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The difference between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to FIN 48 represents an unrecognized tax benefit. An unrecognized tax benefit is a liability that represents a potential future obligation to the taxing authority.

The following table reconciles the changes in unrecognized tax benefits during 2008 and 2007:

	PG&E Corporation			Utility
(in millions)
Balance at January 1, 2007	$	212		$	90
Additions for tax position of prior years		15			4
Reductions for tax position of prior years		(18	)		-
Balance at December 31, 2007	$	209		$	94
Additions for tax position of prior years		43			20
Decreases as a result of settlements with the IRS		(177	)		(77	)
Balance at December 31, 2008	$	75		$	37

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2008 for PG&E Corporation and the Utility is $46 million and $24 million, respectively.

PG&E Corporation and the Utility recognized a reduction in interest and penalties expense on unrecognized tax benefits by $44 million and $21 million, respectively, as of December 31, 2008. PG&E Corporation and the Utility recognized interest and penalties expense on unrecognized tax benefits of $7 million and $2 million, respectively, as of December 31, 2007. Interest and penalties expense is classified as Income tax provision in the Consolidated Statements of Income. Interest and penalties expense included in the liability for uncertain tax position was $11 million and $2 million, respectively, at December 31, 2008, and $55 million and $22 million, respectively, at December 31, 2007.

PG&E Corporation and the Utility do not expect the company’s total amount of unrecognized tax benefits to change significantly within the next 12 months.

On July 9, 2008, PG&E Corporation was notified that the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) had approved a settlement reached with the IRS appellate division in the first quarter of 2007 for tax years 1997 through 2000. As a result of the settlement, PG&E Corporation received a $16 million refund from the IRS in October 2008. This settlement did not result in material changes to the amount of unrecognized tax benefits that PG&E Corporation recorded under FIN 48.

On June 20, 2008, PG&E Corporation reached an agreement with the IRS regarding a change in accounting method related to the capitalization of indirect service costs for tax years 2001 through 2004. This agreement resulted in a $29 million benefit from a reduction in interest expense accrued on unrecognized tax benefits partially offset by a $15 million liability associated with unrecognized state tax benefits, for a net tax benefit of approximately $14 million. In addition, on June 27, 2008, PG&E Corporation agreed to the revenue agent reports (“RARs”) from the IRS that reflected this agreement and resolved 2001 through 2004 audit issues. The RARs for the 2001 through 2004 audit years were submitted to the Joint Committee for approval.

On October 28, 2008, the IRS executed a closing agreement for the 2001 through 2004 years audit after the Joint Committee indicated it took no exception to the settlement. As a result of the settlement, PG&E Corporation recognized after-tax income of approximately $257 million, including interest, in the fourth quarter of 2008, of which approximately $154 million was related to NEGT and recorded as income from discontinued operations, and approximately $60 million was attributable to the Utility. PG&E Corporation expects to receive a tax refund from the IRS of approximately $310 million, plus interest, as a result of the settlement, of which approximately $170 million will be allocated to the Utility. The after-tax income of $257 million includes approximately $204 million primarily related to a reduction in PG&E Corporation’s unrecognized tax benefits and additional claims allowed, and approximately $53 million related to the utilization of federal capital loss carry forwards.

On December 24, 2008, PG&E Corporation filed claims with the California Franchise Tax Board to reduce tax on income related to generator settlements from 2004 through 2007. As a result of the claims, the Utility recorded a tax benefit of $16 million in the fourth quarter 2008.

On January 30, 2009, PG&E Corporation reached a tentative agreement with the IRS to resolve refund claims related to the 1998 and 1999 tax years that, if approved by the Joint Committee, would result in a cash refund of approximately $200 million, plus interest. The refund would result in net income of approximately $50 million. Because the agreement is subject to Joint Committee approval, PG&E Corporation has not recognized any benefit associated with the potential refund.

As of December 31, 2008, PG&E Corporation had $68 million of federal capital loss carry forwards based on tax returns as filed, of which approximately $30 million will expire if not used by tax year 2009.

The IRS is currently auditing tax years 2005 through 2007. For tax year 2008, PG&E Corporation has been participating in the IRS’ Compliance Assurance Process (“CAP”), a real-time audit process intended to expedite the resolution of issues raised during audits. To date, no material adjustments have been proposed for either the 2005 through 2007 audit or for the 2008 CAP, except for adjustments to reflect rollover impact of items settled from prior audits.

The California Franchise Tax Board is currently auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns. To date, no material adjustments have been proposed. In addition to the federal capital loss carry forwards, PG&E Corporation has $2.1 billion of California capital loss carry forwards based on tax returns as filed, the majority of which expired in tax year 2008.

NOTE 11: DERIVATIVES AND HEDGING ACTIVITIES

The Utility enters into contracts to procure electricity, natural gas, nuclear fuel, and firm electricity transmission rights, some of which meet the definition of a derivative under SFAS No. 133. These contracts include physical and financial instruments, such as forwards, futures, swaps, options, and other instruments and agreements and are primarily intended to reduce the volatility in the cost of electricity, natural gas, nuclear fuel, and firm electricity transmission rights. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes.

The Utility also has derivative instruments for the physical delivery of commodities transacted in the normal course of business. These derivative instruments are eligible for the normal purchase and sales exception under SFAS No. 133, where physical delivery is probable, in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and where the price is not tied to an unrelated underlying. Instruments that are eligible for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets.

All such derivative instruments, including instruments designated as cash flow hedges, are recorded at fair value and presented as price risk management assets and liabilities in the Consolidated Balance Sheets (see table below). As a result of applying the provisions of SFAS No. 71, unrealized changes in the fair value of derivative instruments are deferred and recorded to regulatory assets or liabilities. Under the same regulatory accounting treatment, changes in the fair value of cash flow hedges are also recorded to regulatory assets or liabilities, rather than being deferred in accumulated other comprehensive income.

In PG&E Corporation and the Utility’s Consolidated Balance Sheets, price risk management assets and liabilities associated with the Utility’s electricity and gas procurement activities are presented on a net basis by counterparty where the right of offset exists. As PG&E Corporation and the Utility adopted the provisions of FIN 39-1 on January 1, 2008, the net balances include outstanding cash collateral associated with derivative positions. (See Note 2 of the Notes to the Consolidated Financial Statements for discussion of the adoption of FIN 39-1.) The table below shows the total price risk management derivative balances and the portions that are designated as cash flow hedges as of December 31, 2008:

	Price Risk Management Derivatives Balance at December 31, 2008
(in millions)	Derivatives with No Hedge Designation		Designated as Cash Flow Hedges		Cash Collateral			Total Price Risk Management Derivatives
Current Assets – Prepaid expenses and other	$	55	$	-	$	55		$	110
Other Noncurrent Assets – Other		81		-		67			148
Current Liabilities – Other		132		139		(75	)		196
Noncurrent Liabilities – Other		150		211		(69	)		292

The table below shows the total price risk management derivative balances and the portions that are designated as cash flow hedges as of December 31, 2007:

	Price Risk Management Derivatives Balance at December 31, 2007
(in millions)	Derivatives with No Hedge Designation		Designated as Cash Flow Hedges			Cash Collateral (2)			Total Price Risk Management Derivatives
Current Assets – Prepaid expenses and other	$	54	$	(2	)(1)	$	3		$	55
Other Noncurrent Assets – Other		83		42			46			171
Current Liabilities – Other		71		12			(16	)		67
Noncurrent Liabilities – Other		17		3			-			20


(1) $2 million of the cash flow hedges in a liability position at December 31, 2007 related to counterparties for which the total net derivatives position is a current asset.
(2) The net cash collateral receivable balance was classified as Current Assets – Prepaid expenses and other in the 2007 Annual Report. Amounts have been reclassified in accordance with FIN 39-1.

As of December 31, 2008, PG&E Corporation and the Utility had cash flow hedges with expiration dates through December 2012 for energy contract derivative instruments.

Upon settlement of derivative instruments, including those derivative instruments for which the normal purchase and sales exception has been elected and derivative instruments designated as cash flow hedges, any gains or losses are recorded in the cost of electricity and the cost of natural gas. All costs of electricity and natural gas are passed through to customers. Cash inflows and outflows associated with the settlement of price risk management transactions are recognized in operating cash flows on PG&E Corporation and the Utility’s Consolidated Statements of Cash Flows.

The dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes, considered to be derivative instruments, are recorded at fair value in PG&E Corporation’s Consolidated Financial Statements in accordance with SFAS No. 133. The dividend participation rights are not considered price risk management instruments, thus are not included in the tables above. (See Note 4 of the Notes to the Consolidated Financial Statements for discussion of the Convertible Subordinated Notes.)

NOTE 12: FAIR VALUE MEASUREMENTS

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157, which defines fair value measurements and implements a hierarchical disclosure requirement. SFAS No. 157 deferred the disclosure of the hierarchy for certain non-financial instruments to fiscal years beginning after November 15, 2008.

SFAS No. 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date,” or the “exit price.” Accordingly, an entity must determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. The identification of market participant assumptions provides a basis for determining what inputs are to be used for pricing each asset or liability. Additionally, SFAS No. 157 establishes a fair value hierarchy that gives precedence to fair value measurements calculated using observable inputs over those using unobservable inputs. Accordingly, the following levels were established for each input:

Level 1: “Inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.” Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments classified as Level 1 consist of financial instruments such as exchange-traded derivatives (other than options), listed equities, and U.S. government treasury securities.

Level 2: “Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly.” Instruments classified as Level 2 consist of financial instruments such as non-exchange-traded derivatives (other than options) valued using exchange inputs and exchange-traded derivatives (other than options) for which the market is not active.

Level 3: “Unobservable inputs for the asset or liability.” These are inputs for which there is no market data available, or observable inputs that are adjusted using Level 3 assumptions. Instruments classified as Level 3 consist primarily of financial and physical instruments such as options, non-exchange-traded derivatives valued using broker quotes, and new and/or complex instruments that have immature or limited markets.

SFAS No. 157 is applied prospectively with limited exceptions. One such exception relates to SFAS No. 157’s nullification of a portion of EITF No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF 02-3”). Prior to the issuance of SFAS No. 157, EITF 02-3 prohibited an entity from recognizing a day one gain or loss on derivative contracts based on the use of unobservable inputs. A day one gain or loss is the difference between the transaction price and the fair value of the contract on the day the derivative contract is executed (i.e., at inception). Prior to the adoption of SFAS No. 157, the Utility did not record any day one gains associated with Congestion Revenue Rights (“CRRs”) as the fair value was based primarily on unobservable market data. (CRRs allow market participants, including load serving entities, to hedge the financial risk of congestion charges imposed by the CAISO in the day-ahead market to be established when the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) becomes effective.) The costs associated with procuring CRRs are currently being recovered in rates or are probable of recovery in future rates. The adoption of SFAS No. 157 permitted the Utility to record day one gains associated with CRRs resulting in a $48 million increase in price risk management assets and the related regulatory liabilities as of January 1, 2008.

The following table sets forth the fair value hierarchy by level of PG&E Corporation and the Utility’s recurring fair value financial instruments as of December 31, 2008. The instruments are classified based on the lowest level of input that is significant to the fair value measurement. PG&E Corporation and the Utility’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PG&E Corporation
Fair Value Measurements as of December 31, 2008
(in millions)	Level 1			Level 2		Level 3		Total
Assets:
Money market investments (held by PG&E Corporation)	$	164		$	-	$	12	$	176
Nuclear decommissioning trusts(1)		1,505			289		5		1,799
Rabbi trusts		66			-		-		66
Long-term disability trust		99			-		78		177
Assets Total	$	1,834		$	289	$	95	$	2,218
Liabilities:
Dividend participation rights	$	-		$	-	$	42	$	42
Price risk management instruments(2)		(49	)		123		156		230
Other		-			-		2		2
Liabilities Total	$	(49	)	$	123	$	200	$	274


(1) Excludes taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $159 million to Level 1, $32 million to Level 2, and $76 million to Level 3.

Utility
Fair Value Measurements as of December 31, 2008
(in millions)	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts(1)	$	1,505		$	289	$	5	$	1,799
Long term disability trust		99			-		78		177
Assets Total	$	1,604		$	289	$	83	$	1,976
Liabilities:
Price risk management instruments(2)		(49	)		123		156		230
Other		-			-		2		2
Liabilities Total	$	(49	)	$	123	$	158	$	232


(1) Excludes taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $159 million to Level 1, $32 million to Level 2, and $76 million to Level 3.

PG&E Corporation and the Utility’s fair value measurements incorporate various factors required under SFAS No. 157 such as the credit standing of the counterparties involved, nonperformance risk including the risk of nonperformance by PG&E Corporation and the Utility on their liabilities, the applicable exit market, and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on the Utility’s price risk management instruments are based on current market inputs when available, such as credit default swap spreads. When such information is not available, internal models may be used. As of December 31, 2008, the nonperformance and credit risk adjustment represents approximately 5% of the net price risk management value. As permitted under SFAS No. 157, PG&E Corporation and the Utility utilize a mid-market pricing convention (the mid-point between bid and ask prices) as a practical expedient in valuing the majority of its derivative assets and liabilities at fair value.

Money Market Investments

PG&E Corporation invests in AAA-rated money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued based on observable inputs such as expected yield and credit quality and are thus classified as Level 1 instruments. Approximately $164 million held in money market funds are recorded as Cash and cash equivalents in PG&E Corporation’s Consolidated Balance Sheets.

Trust Assets

The nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust hold primarily equities, debt securities, mutual funds, and life insurance policies. These instruments are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. The rabbi trusts are classified as Current Assets-Prepaid expenses and other and Other Noncurrent Assets-Other in PG&E Corporation’s Consolidated Balance Sheets. The long-term disability trust is classified as Current Liabilities-Other in PG&E Corporation and the Utility’s Consolidated Balance Sheets, representing a net obligation as the projected obligation exceeds plan assets.

The Consolidated Balance Sheets of PG&E Corporation and the Utility contain assets held in trust for the PG&E Retirement Plan Master Trust, the Postretirement Life Insurance Trust, and the Postretirement Medical Trusts presented on a net basis. The assets held in these trusts are fair valued annually and are included in the scope of SFAS No. 157, but the pension liabilities are not considered fair value instruments under SFAS No. 157. As the assets are presented net of a non-fair value measure in PG&E Corporation and the Utility’s Consolidated Financial Statements, the fair value hierarchy disclosure in the table above does not require the inclusion of pension assets. The pension assets include equities, debt securities, swaps, commingled funds, futures, cash equivalents, and insurance policies. The pension assets are presented net of pension obligations as Noncurrent Liabilities - Other in PG&E Corporation and the Utility’s Consolidated Balance Sheets.

Price Risk Management Instruments

Price risk management instruments are comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. PG&E Corporation and the Utility consistently apply valuation methodology among their instruments. SFAS No. 71 allows the Utility to defer the unrealized gains and losses associated with these derivatives, as they are expected to be refunded or recovered in future rates.

All energy options (exchange-traded and OTC) are valued using the Black’s Option Pricing Model and classified as Level 3 measurements primarily due to volatility inputs.

CRRs allow market participants, including load serving entities, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market to be established when MRTU becomes effective. Firm Transmission Rights (“FTRs”) allow market participants, including load serving entities to hedge both the physical and financial risk associated with CAISO-imposed congestion charges until the MRTU becomes effective. The Utility’s demand response contracts (“DRs”) 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. As the market for CRRs, FTRs, and DRs have minimal activity, observable inputs may not be available in pricing these instruments. Therefore, the pricing models used to value these instruments often incorporate significant estimates and assumptions that market participants would use in pricing the instrument. Accordingly, they are classified as Level 3 measurements. When available, observable market data is used to calibrate pricing models.

Exchange-traded derivative instruments (other than options) are generally valued based on unadjusted prices in active markets using pricing models to determine the net present value of estimated future cash flows. Accordingly, a majority of these instruments are classified as Level 1 measurements. However, certain of these 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, trading volumes, frequency of available quotes, and open interest. In addition, a number of OTC contracts have been valued using unadjusted exchange prices in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments. The remaining OTC derivative instruments are valued using pricing models based on the net present value of estimated future cash flows based on broker quotations. Such instruments are generally classified within Level 3 of the fair value hierarchy as broker quotes are only indicative of market activity and do not necessarily reflect binding offers to transact.

See Note 11 of the Notes to the Consolidated Financial Statements for further discussion of the price risk management instruments.

Dividend Participation Rights

The dividend participation rights of the Convertible Subordinated Notes are embedded derivative instruments in accordance with SFAS No. 133 and, therefore, are bifurcated from Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Consolidated Balance Sheets. The dividend participation rights are valued based on the net present value of estimated future cash flows using internal estimates of future common stock dividends. The fair value of the dividend participation rights is recorded as Current Liabilities-Other and Noncurrent Liabilities-Other in PG&E Corporation’s Consolidated Balance Sheets. (See Note 4 of the Notes to the Consolidated Financial Statements for further discussion of these instruments.)

Debt Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

●	The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, price risk management assets and liabilities, short-term borrowings, accounts payable, customer deposits, and the Utility's variable rate pollution control bond loan agreements approximate their carrying values as of December 31, 2008 and 2007.

●	The fair values of the Utility’s fixed rate senior notes, fixed rate pollution control bond loan agreements, and the ERBs issued by PG&E Energy Recovery Funding LLC, were based on quoted market prices obtained from the Bloomberg financial information system at December 31, 2008.

●	The estimated fair value of PG&E Corporation’s 9.50% Convertible Subordinated Notes was determined by considering the prices of securities displayed as of the close of business on December 31, 2008 by a proprietary bond trading system which tracks and marks a broad universe of convertible securities including the securities being assessed.

The carrying amount and fair value of PG&E Corporation's and the Utility's financial instruments are as follows (the table below excludes financial instruments with fair values that approximate their carrying values, as these instruments are presented at their carrying value in the Consolidated Balance Sheets):

	At December 31,
	2008				2007
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4):
PG&E Corporation	$	280	$	739	$	280	$	849
Utility		8,740		9,134		6,823		6,701
Energy recovery bonds (Note 5)		1,583		1,564		1,936		1,928

Level 3 Rollforward

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the twelve month period ended December 31, 2008:

PG&E Corporation
(in millions)	Money Market Investments			Price Risk Management Instruments			Nuclear Decommissioning Trusts (3)			Long-term Disability			Dividend Participation Rights			Other			Total
Asset (liability) Balance as of January 1, 2008	$	-		$	115	(1)	$	8		$	87		$	(68	)(2)	$	(4	)	$	138
Realized and unrealized gains (losses):
Included in earnings		-			-			-			(34	)		(3	)		-			(37	)
Included in regulatory assets and liabilities or balancing accounts		-			(271	)		(3	)		-			-			2			(272	)
Purchases, issuances, and settlements		(50	)		-			-			25			29			-			4
Transfers in (out) of Level 3		62			-			-			-			-			-			62
Asset (liability) Balance as of December 31, 2008	$	12		$	(156	)	$	5		$	78		$	(42	)	$	(2	)	$	(105	)

(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1.
(2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157, resulting in a $6 million expense to increase the value of the liability.
(3) Excludes taxes on appreciation of investment value.

Earnings for the period were impacted by a $37 million unrealized loss relating to assets or liabilities still held at December 31, 2008.

The following table is a reconciliation of changes in fair value of the Utility’s instruments that have been classified as Level 3 in the fair value hierarchy for the twelve month period ended December 31, 2008:

Utility
(in millions)	Price Risk Management Instruments			Nuclear Decommissioning Trusts (2)			Long-term Disability			Other			Total
Asset (liability) Balance as of January 1, 2008	$	115	(1)	$	8		$	87		$	(4	)	$	206
Realized and unrealized gains (losses):
Included in earnings		-			-			(34	)		-			(34	)
Included in regulatory assets and liabilities or balancing accounts		(271	)		(3	)		-			2			(272	)
Purchases, issuances, and settlements		-			-			25			-			25
Transfers in (out) of Level 3		-			-			-			-			-
Asset (liability) Balance as of December 31, 2008	$	(156	)	$	5		$	78		$	(2	)	$	(75	)

(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1.
(2) Excludes taxes on appreciation of investment value.

Earnings for the period were impacted by a $34 million unrealized loss relating to assets or liabilities still held at December 31, 2008.

PG&E Corporation and the Utility did not have any nonrecurring financial measurements that are within the scope of SFAS No. 157 as of December 31, 2008.

NOTE 13: NUCLEAR DECOMMISSIONING

The Utility's nuclear power facilities consist of two units at Diablo Canyon (“Diablo Canyon Unit 1” and “Diablo Canyon Unit 2”) and the retired facility at Humboldt Bay (“Humboldt Bay Unit 3”). Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission (“NRC”) license and release of the property for unrestricted use. The Utility makes contributions to trust funds (described below) to provide for the eventual decommissioning of each nuclear unit. The CPUC conducts a Nuclear Decommissioning Cost Triennial Proceeding (“NDCTP”) every three years to review the Utility’s updated nuclear decommissioning cost study and to determine the level of Utility trust contributions and related revenue requirements. In the Utility’s 2005 NDCTP, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044; that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041; and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The 2008 NDCTP application was originally scheduled to be filed on November 10, 2008; however, on April 29 2008, the CPUC extended the filing date to April 3, 2009.

As presented in the Utility’s 2005 NDCTP, the estimated nuclear decommissioning cost for Diablo Canyon Units 1 and 2 and Humboldt Bay Unit 3 is approximately $2.27 billion in 2008 dollars (or approximately $5.42 billion in future dollars). These estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The Utility's revenue requirements for nuclear decommissioning costs (i.e., the revenue requirements used by the Utility to make contributions to the decommissioning trust funds) are recovered from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates, regulatory requirements, technology, and costs of labor, materials and equipment.

The estimated nuclear decommissioning cost described above is used for regulatory purposes. However, under SFAS No. 143 requirements, the decommissioning cost estimate is calculated using a different method in accordance with SFAS No. 143. Under GAAP, the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities and records this as an asset retirement obligation on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.4 billion at December 31, 2008 and $1.3 billion at December 31, 2007. The primary difference between the Utility's estimated nuclear decommissioning obligation as recorded in accordance with GAAP and the estimate prepared in accordance with the CPUC requirements is that the estimated obligation calculated in accordance with GAAP incorporates various potential settlement dates for the obligation and includes an estimated amount for third-party labor costs in the fair value calculation. Differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the decommissioning obligation recorded in accordance with GAAP are reflected as a regulatory liability. (See Note 3 of the Notes to the Consolidated Financial Statements.)

Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts' after-tax returns. Among other requirements, in order to maintain the qualified trust status the IRS must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until such decommissioning costs are actually incurred.

The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility's nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. The CPUC has authorized the qualified and non-qualified trusts to invest a maximum of 60% of its funds in publicly-traded equity securities, of which up to 20% may be invested in publicly-traded non-U.S. equity securities. The allocation of the trust funds is monitored monthly. To the extent that market movements cause the asset allocation to move outside these ranges, the investments are rebalanced toward the target allocation.

Trust earnings are included in the nuclear decommissioning trust assets and the corresponding regulatory liability for asset retirement costs. There is no impact on the Utility’s earnings. Annual returns decrease in later years as higher portions of the trusts are dedicated to fixed income investments leading up to and during the entire course of decommissioning activities.

During 2008, the trusts earned $76 million in interest and dividends. All earnings on the assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. All of the Utility’s investment securities in the trust are classified as “Available for Sale” in accordance with SFAS No. 115. At December 31, 2008, the Utility had accumulated nuclear decommissioning trust funds with an estimated fair value of approximately $1.7 billion, net of deferred taxes on unrealized gains.

In general, investment securities are exposed to various risks, such as interest rate, credit and market volatility risks. Due to the level of risk associated with certain investment securities, 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. (See Note 12 of the Notes to the Consolidated Financial Statements.)

The Utility records unrealized gains and losses on investments held in the trusts in other comprehensive income. Realized gains and losses are recognized as additions or reductions to trust asset balances. The Utility, however, accounts for its nuclear decommissioning obligations in accordance with SFAS No. 71; therefore, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

At December 31, 2008, total unrealized losses on the investments held in the trusts were $39 million. SFAS Nos. 115-1 and 124-1 state that an investment is impaired if the fair value of the investment is less than its cost and if the impairment is concluded to be other-than-temporary, an impairment loss is recognized. Since the day-to-day investing activities of the trusts are managed by external investment managers, the Utility is unable to conclude that the $39 million impairment is not other-than-temporary. As a result, an impairment loss was recognized and the Utility recorded a $39 million reduction to the nuclear decommissioning trusts assets and the corresponding regulatory liability asset retirement costs.

The following table provides a summary of the fair value of the investments held in the Utility’s nuclear decommissioning trusts:

(in millions)	Maturity Date		Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated (1) Fair Value
Year ended December 31, 2008
U.S. government and agency issues		2009-2038	$	617	$	103	$	-		$	720
Municipal bonds and other		2009-2049		187		3		(12	)		178
Equity securities				588		340		(27	)		901
Total			$	1,392	$	446	$	(39	)	$	1,799
Year ended December 31, 2007
U.S. government and agency issues		2008-2037	$	767	$	59	$	-		$	826
Municipal bonds and other		2008-2049		209		5		-			214
Equity securities				464		682		(7	)		1,139
Total			$	1,440	$	746	$	(7	)	$	2,179


(1) Excludes taxes on appreciation of investment value.

The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of the activity for the debt and equity securities:

	Year Ended December 31,
(in millions)	2008			2007			2006
Proceeds received from sales of securities	$	1,635		$	830		$	1,087
Gross realized gains on sales of securities held as available-for-sale		30			61			55
Gross realized losses on sales of securities held as available-for-sale		(142	)		(42	)		(29	)

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. The DOE failed to develop a permanent storage site by January 31, 1998. The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.

PG&E Corporation and the Utility are unable to predict the outcome of any rehearing petition.

NOTE 14: EMPLOYEE COMPENSATION PLANS

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for certain employees and retirees, referred to collectively as pension benefits. PG&E Corporation and the Utility also provide contributory postretirement medical plans for certain employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for certain employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Code as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. The following schedules aggregate all of PG&E Corporation’s and the Utility’s plans and are presented based on the sponsor of each plan. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

Under SFAS No. 71, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking, which is based on a funding approach. A regulatory adjustment is also recorded for the amounts that would otherwise be charged to accumulated other comprehensive income under SFAS No. 158 for the pension benefits related to the Utility’s qualified benefit pension plan. Since 1993, the CPUC has authorized the Utility to recover the costs associated with its other benefits based on the lesser of the expense under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS No. 106”), or the annual tax deductible contributions to the appropriate trusts. The Utility records a regulatory liability for an overfunded position of other benefits. However, this recovery mechanism does not allow the Utility to record a regulatory asset for an underfunded position related to other benefits. Therefore, the SFAS No. 158 charge is recorded in accumulated other comprehensive income (loss) for other benefits.

Benefit Obligations

The following tables reconcile changes in aggregate projected benefit obligations for pension benefits and changes in the benefit obligation of other benefits during 2008 and 2007:

Pension Benefits

	PG&E Corporation						Utility
	2008			2007			2008			2007
(in millions)
Projected benefit obligation at January 1	$	9,081		$	9,064		$	9,036		$	9,023
Service cost for benefits earned		236			233			234			228
Interest cost		581			544			578			541
Actuarial (gain) loss		258			(397	)		255			(396	)
Plan amendments		2			1			3			2
Benefits and expenses paid		(391	)		(364	)		(389	)		(362	)
Projected benefit obligation at December 31	$	9,767		$	9,081		$	9,717		$	9,036
Accumulated benefit obligation	$	8,601		$	8,243		$	8,559		$	8,206

Other Benefits

	PG&E Corporation						Utility
	2008			2007			2008			2007
(in millions)
Benefit obligation at January 1	$	1,311		$	1,310		$	1,311		$	1,310
Service cost for benefits earned		29			29			29			29
Interest cost		81			79			81			79
Actuarial (gain) loss		22			(66	)		22			(66	)
Plan amendments		-			17			-			17
Gross benefits paid		(101	)		(97	)		(101	)		(97	)
Federal subsidy on benefits paid		4			4			4			4
Participants paid benefits		36			35			36			35
Benefit obligation at December 31	$	1,382		$	1,311		$	1,382		$	1,311

Change in Plan Assets

To determine the fair value of the plan assets, PG&E Corporation and the Utility use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee.

The following tables reconcile aggregate changes in plan assets during 2008 and 2007:

Pension Benefits

	PG&E Corporation								Utility
	2008				2007				2008				2007
(in millions)
Fair value of plan assets at January 1		$	9,540			$	9,028			$	9,540			$	9,028
Actual return on plan assets			(1,232	)			766				(1,232	)			766
Company contributions			182				139				179				137
Benefits and expenses paid			(424	)			(393	)			(421	)			(391	)
Fair value of plan assets at December 31		$	8,066			$	9,540			$	8,066			$	9,540

Other Benefits

	PG&E Corporation						Utility
	2008			2007			2008			2007
(in millions)
Fair value of plan assets at January 1	$	1,331		$	1,256		$	1,331		$	1,256
Actual return on plan assets		(316	)		107			(316	)		107
Company contributions		48			38			48			38
Plan participant contribution		36			36			36			36
Benefits and expenses paid		(109	)		(106	)		(109	)		(106	)
Fair value of plan assets at December 31	$	990		$	1,331		$	990		$	1,331

Funded Status

The following schedule shows the plans' aggregate funded status on a plan sponsor basis. The funded status is the difference between the fair value of plan assets and projected benefit obligations.

Pension Benefits

	PG&E Corporation								Utility
	December 31,								December 31,
	2008				2007				2008				2007
(in millions)
Fair value of plan assets at December 31		$	8,066			$	9,540			$	8,066			$	9,540
Projected benefit obligation at December 31			(9,767	)			(9,081	)			(9,717	)			(9,036	)
Prepaid/(accrued) benefit cost		$	(1,701	)		$	459			$	(1,651	)		$	504
Noncurrent asset		$	-			$	532			$	-			$	532
Current liability			(5	)			(2	)			(3	)			(3	)
Noncurrent liability			(1,696	)			(71	)			(1,648	)			(25	)
Prepaid/(accrued) benefit cost		$	(1,701	)		$	459			$	(1,651	)		$	504

Other Benefits

	PG&E Corporation								Utility
	December 31,								December 31,
	2008				2007				2008				2007
(in millions)
Fair value of plan assets at December 31		$	990			$	1,331			$	990			$	1,331
Benefit obligation at December 31			(1,382	)			(1,311	)			(1,382	)			(1,311	)
Prepaid/(accrued) benefit cost		$	(392	)		$	20			$	(392	)		$	20

Noncurrent asset		$	-			$	54			$	-			$	54
Noncurrent liability			(392	)			(34	)			(392	)			(34	)
Prepaid/(accrued) benefit cost		$	(392	)		$	20			$	(392	)		$	20

Other Information

The aggregate projected benefit obligation, accumulated benefit obligation and fair value of plan asset for plans in which the fair value of plan assets is less than the accumulated benefit obligation and the projected benefit obligation as of December 31, 2008 and 2007 were as follows:

	Pension Benefits								Other Benefits
	2008				2007				2008				2007
(in millions)
PG&E Corporation:
Projected benefit obligation		$	(9,767	)		$	(73	)		$	(1,382	)		$	(187	)
Accumulated benefit obligation			(8,601	)			(64	)			-				-
Fair value of plan assets			8,066				-				990				153
Utility:
Projected benefit obligation		$	(9,717	)		$	(27	)		$	(1,382	)		$	(187	)
Accumulated benefit obligation			(8,559	)			(27	)			-				-
Fair value of plan assets			8,066				-				990				153

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation's Consolidated Statements of Income for 2008, 2007, and 2006, is as follows:

Pension Benefits

	December 31,
	2008			2007			2006
(in millions)
Service cost for benefits earned	$	236		$	233		$	236
Interest cost		581			544			511
Expected return on plan assets		(696	)		(711	)		(640	)
Amortization of prior service cost (1)		47			49			56
Amortization of unrecognized gain (1)		1			2			22
Net periodic benefit cost	$	169		$	117		$	185


(1) In 2007 and 2008, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71.

Other Benefits

	December 31,
	2008			2007			2006
(in millions)
Service cost for benefits earned	$	29		$	29		$	28
Interest cost		81			79			74
Expected return on plan assets		(93	)		(96	)		(90	)
Amortization of transition obligation (1)		26			26			26
Amortization of prior service cost (1)		16			16			14
Amortization of unrecognized gain (1)		(15	)		(10	)		(3	)
Net periodic benefit cost	$	44		$	44		$	49


(1) In 2007 and 2008, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71.

There was no material difference between PG&E Corporation and the Utility's consolidated net periodic benefit costs.

Components of Accumulated Other Comprehensive Income

Since December 31, 2006, the effective date of SFAS No. 158, PG&E Corporation and the Utility have recorded unrecognized prior service costs, unrecognized gains and losses, and unrecognized net transition obligations as components of accumulated other comprehensive income, net of tax. In subsequent years, PG&E Corporation and the Utility recognize these amounts as components of net periodic benefit cost in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No. 106.

Pre-tax amounts recognized in accumulated other comprehensive income consist of:

	PG&E Corporation						Utility
	2008			2007			2008			2007
(in millions)
Pension Benefits:
Beginning unrecognized prior service cost	$	(222	)	$	(268	)	$	(226	)	$	(275	)
Current year unrecognized prior service cost		(2	)		(3	)		(3	)		(2	)
Amortization of unrecognized prior service cost		49			49			48			51
Unrecognized prior service cost		(175	)		(222	)		(181	)		(226	)
Beginning unrecognized net gain (loss)		105			(318	)		117			(306	)
Current year unrecognized net gain (loss)		(2,219	)		421			(2,217	)		423
Amortization of unrecognized net gain		1			2			-			-
Unrecognized net gain (loss)		(2,113	)		105			(2,100	)		117
Beginning unrecognized net transition obligation		-			(1	)		-			(1	)
Amortization of unrecognized net transition obligation		-			1			-			1
Unrecognized net transition obligation		-			-			-			-
Less: transfer to regulatory account(1)		2,259			109			2,259			109
Total	$	(29	)	$	(8	)	$	(22	)	$	-
Other Benefits:
Beginning unrecognized prior service cost	$	(116	)	$	(114	)	$	(116	)	$	(114	)
Current year unrecognized prior service cost		-			(18	)		-			(18	)
Amortization of unrecognized prior service cost		17			16			17			16
Unrecognized prior service cost		(99	)		(116	)		(99	)		(116	)
Beginning unrecognized net gain		311			250			311			250
Current year unrecognized net gain (loss)		(438	)		71			(438	)		71
Amortization of unrecognized net loss		(15	)		(10	)		(15	)		(10	)
Unrecognized net gain (loss)		(142	)		311			(142	)		311
Beginning unrecognized net transition obligation		(128	)		(154	)		(128	)		(154	)
Amortization of unrecognized net transition obligation		26			26			26			26
Unrecognized net transition obligation		(102	)		(128	)		(102	)		(128	)
Less: transfer to regulatory account(2)		-			(44	)		-			(44	)
Total	$	(343	)	$	23		$	(343	)	$	23


(1) The Utility recorded approximately $2,259 million in 2008 and $109 million in 2007 as a reduction to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71. The adjustment resulted in a regulatory asset balance at December 31, 2008. (2) The Utility recorded approximately $44 million in 2007 as an addition to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71.

The estimated amounts that will be amortized into net periodic benefit cost in 2009 are as follows:

	PG&E Corporation		Utility
(in millions)
Pension benefits:
Unrecognized prior service cost	$	47	$	48
Unrecognized net loss		98		97
Total	$	145	$	145
Other benefits:
Unrecognized prior service cost	$	16	$	16
Unrecognized net loss		3		3
Unrecognized net transition obligation		26		26
Total	$	45	$	45

Valuation Assumptions

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. Weighted average year-end assumptions were used in determining the plans' projected benefit obligations, while prior year-end assumptions are used to compute net benefit cost.

	Pension Benefits							Other Benefits
	December 31,							December 31,
	2008			2007		2006		2008		2007		2006

Discount rate		6.31	%	6.31	%	5.90	%	5.85-6.33	%	5.52-6.42	%	5.50-6.00	%
Average rate of future compensation increases		5.00	%	5.00	%	5.00	%	-		-		-
Expected return on plan assets		7.30	%	7.40	%	8.00	%	7.00-7.30	%	7.00-7.50	%	7.30-8.20	%

The assumed health care cost trend rate for 2008 is approximately 8%, decreasing gradually to an ultimate trend rate in 2014 and beyond of approximately 5%. A one-percentage point change in assumed health care cost trend rate would have the following effects:

(in millions)	One-Percentage Point Increase		One-Percentage Point Decrease
Effect on postretirement benefit obligation	$	68	$	(57	)
Effect on service and interest cost		7		(6	)

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were estimated based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility pension plan, the assumed return of 7.3% compares to a ten-year actual return of 4.6%. The rate used to discount pension and other post-retirement benefit plan liabilities was based on a yield curve developed from market data of over approximately 300 Aa-grade non-callable bonds at December 31, 2008. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The difference between actual and expected return on plan assets is included in unrecognized gain (loss), and is considered in the determination of future net periodic benefit income (cost). The actual return on plan assets was above the expected return in 2007 and 2006. The actual return on plan assets for 2008 was lower than the expected return due to the significant decline in equity market values that occurred in 2008.

Asset Allocations

The asset allocation of PG&E Corporation's and the Utility's pension and other benefit plans at December 31, 2008 and 2007, and target 2009 allocation, were as follows:

	Pension Benefits									Other Benefits
	2009			2008			2007			2009			2008			2007
Equity securities
U.S. equity		32	%		31	%		30	%		37	%		35	%		36	%
Non-U.S. equity		18	%		17	%		18	%		18	%		16	%		19	%
Global equity		5	%		3	%		5	%		3	%		2	%		4	%
Absolute return		5	%		4	%		5	%		3	%		3	%		3	%
Fixed income securities		40	%		42	%		41	%		34	%		34	%		37	%
Cash		0	%		3	%		1	%		5	%		10	%		1	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Equity securities include a small amount (less than 0.1% of total plan assets) of PG&E Corporation common stock.

During 2008, the duration of fixed income assets was extended to better align with the interest rate sensitivity of the benefit plan liability. The maturity of fixed income securities at December 31, 2008 ranged from zero to 59 years and the average duration of the bond portfolio was approximately 12.2 years. The maturity of fixed income securities at December 31, 2007 ranged from zero to 60 years and the average duration of the bond portfolio was approximately 10.5 years.

PG&E Corporation's investment strategy for all plans is to maintain actual asset weightings within 1.0% to 5.0% of target asset allocations varying by asset class. A rebalancing review is triggered whenever the actual weighting falls outside of the specified range.

A benchmark portfolio for each asset class is set based on market capitalization and valuations of equities and the durations and credit quality of fixed income securities. Investment managers for each asset class are retained to either passively or actively manage the combined portfolio against the benchmark. Active management covers approximately 70% of the U.S. equity, 80% of the non-U.S. equity, and virtually 100% of the fixed income and global security portfolios.

During 2007, PG&E Corporation began extending the benchmarks of its fixed income managers and began using interest rate swaps for certain plans in order to better match the interest rate sensitivity of the plans’ assets with that of the plans’ liabilities. Changes in the value of these investments will affect future contributions to the trust and net periodic benefit cost on a lagged basis.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed approximately $182 million to the pension benefits, including $176 million to the qualified defined benefit pension plan, and approximately $48 million to the other benefit plans in 2008. These contributions are consistent with PG&E Corporation's and the Utility's funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2008. The Utility's pension benefits met all the funding requirements under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation and the Utility expect to make total contributions of approximately $176 million annually during 2009 and 2010 to the pension plan and expect to make contributions of approximately $58 million annually for the years 2009 and 2010 to other postretirement benefit plans.

Benefits Payments

The estimated benefits expected to be paid in each of the next five fiscal years and in aggregate for the five fiscal years thereafter, are as follows:

	PG&E Corporation		Utility
(in millions)
Pension
2009	$	440	$	437
2010		470		467
2011		502		500
2012		538		536
2013		575		573
2014-2018		3,433		3,415
Other benefits
2009	$	98	$	98
2010		101		101
2011		104		104
2012		105		105
2013		108		108
2014-2018		572		572

Defined Contribution Benefit Plans

PG&E Corporation and its subsidiaries also sponsor defined contribution benefit plans. These plans are qualified under applicable sections of the Code. These plans provide for tax-deferred salary deductions and after-tax employee contributions as well as employer contributions. Employees designate the funds in which their contributions and any employer contributions are invested. Before April 1, 2007, PG&E Corporation employees received matching of up to 5% of the employee’s base compensation and basic contributions of up to 5% of the employee’s base compensation. Matching contributions vary up to 6% of the employee’s base compensation based on years of service for Utility employees. Beginning April 1, 2007, the basic employer contribution was discontinued for PG&E Corporation employees and matching contributions were changed to match the Utility employee plan. Matching employer contributions are made with company stock, however, employees may reallocate matching employer contributions and accumulated earnings thereon to another investment fund or funds available to the plan at any time after they have been credited to the employee’s account. Employer contribution expense reflected in PG&E Corporation's Consolidated Statements of Income amounted to:

(in millions)	PG&E Corporation		Utility
Year ended December 31,
2008	$	53	$	52
2007		47		46
2006		45		43

PG&E Corporation Supplemental Retirement Savings Plan

The PG&E Corporation Supplemental Retirement Savings Plan (“SRSP”) is a non-qualified plan that allows eligible officers and key employees of PG&E Corporation and its subsidiaries to defer 5% to 50% of their base salary and all or part of their incentive awards. In addition, to the extent that matching employer contributions cannot be made to a participant under the qualified defined contribution benefit plan because the contributions would exceed the limitations set by the Code, PG&E Corporation credits the excess amount to an SRSP account for the eligible employee. Each SRSP participant has a separate account which is adjusted on a monthly basis to reflect the performance of the investment options selected by the participant. The change in the value of participants’ accounts is recorded as additional compensation expense or income in the Consolidated Statements of Income. Total compensation expense and (income) recognized by PG&E Corporation and the Utility in connection with the plan amounted to:

	PG&E Corporation				Utility
(in millions)
2008		$	(7	)		$	(4	)
2007			2				1
2006			4				2

Long-Term Incentive Plan

The 2006 LTIP permits the award of various forms of incentive awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance shares, deferred compensation awards, and other stock-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive restricted stock and either stock options or restricted stock units under the formula grant provisions of the 2006 LTIP. A maximum of 12 million shares of PG&E Corporation common stock (subject to adjustment for changes in capital structure, stock dividends, or other similar events) have been reserved for issuance under the 2006 LTIP, of which 10,342,381 shares were available for award at December 31, 2008.

Awards made under the PG&E Corporation Long-Term Incentive Program before December 31, 2005 and still outstanding continue to be governed by the terms and conditions of the PG&E Corporation Long-Term Incentive Program.

PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2.5% for stock options and restricted stock and 3% for performance shares, based on historic forfeiture rates, for purposes of determining compensation expense for share-based incentive awards. The following table provides a summary of total compensation expense for PG&E Corporation and the Utility for share-based incentive awards for the years ended December 31, 2007 and 2008:

	Year ended December 31, 2008
	PG&E Corporation		Utility
(in millions)
Stock Options	$	2	$	2
Restricted Stock		22		15
Performance Shares		33		20
Total Compensation Expense (pre-tax)	$	57	$	37
Total Compensation Expense (after-tax)	$	34	$	22

	Year ended December 31, 2007
	PG&E Corporation			Utility
(in millions)
Stock Options	$	7		$	4
Restricted Stock		24			15
Performance Shares		(8	)		(7	)
Total Compensation Expense (pre-tax)	$	23		$	12
Total Compensation Expense (after-tax)	$	14		$	7

Stock Options

Other than the grant of options to purchase 4,032 shares of PG&E Corporation common stock to non-employee directors of PG&E Corporation in accordance with the formula and nondiscretionary provisions of the 2006 LTIP, no other stock options were granted during 2008. The exercise price of stock options granted under the 2006 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a ten-year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $4.46, $7.81, and $6.98 per share in 2008, 2007, and 2006, respectively. The significant assumptions used for shares granted in 2008, 2007, and 2006 were:

	2008			2007			2006
Expected stock price volatility		18.9	%		16.5	%		22.1	%
Expected annual dividend payment	$	1.56		$	1.44		$	1.32
Risk-free interest rate		2.77	%		4.73	%		4.46	%
Expected life	5.4 years			5.4 years			5.6 years

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

The following table summarizes total intrinsic value (fair market value of PG&E Corporation’s stock less stock option strike price) of options exercised for PG&E Corporation and the Utility in 2008, 2007, and 2006:

	PG&E Corporation		Utility
(in millions)
2008:
Intrinsic value of options exercised	$	13	$	9
2007:
Intrinsic value of options exercised	$	59	$	34
2006:
Intrinsic value of options exercised	$	97	$	51

The tax benefit from stock options exercised totaled $4 and $20 million for the year ended December 31, 2008 and December 31, 2007, respectively, of which approximately $3 million and $10 million was recorded by the Utility.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2008:

Options	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1		3,882,672		$	24.00
Granted(1)		4,032		$	37.91
Exercised		(900,732	)	$	25.72
Forfeited or expired		(17,711	)	$	31.49
Outstanding at December 31		2,968,261		$	23.45		3.75	$	45,300,037
Expected to vest at December 31		254,854		$	33.74		6.00	$	1,270,206
Exercisable at December 31		2,712,725		$	22.48		3.54	$	44,029,831


(1) No stock options were awarded to employees in 2008; however, certain non-employee directors of PG&E Corporation were awarded stock options.

The following table summarizes stock option activity for the Utility for 2008:

Options	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1(1)		2,912,552		$	23.40
Granted		-			-
Exercised		(588,333	)	$	24.86
Forfeited or expired		(14,396	)	$	31.14
Outstanding at December 31(1)		2,309,823		$	22.99		3.79	$	36,318,945
Expected to vest at December 31		164,303		$	33.09		5.80	$	923,072
Exercisable at December 31		2,145,520		$	22.21		3.64	$	35,395,873


(1) Includes net employee transfers between PG&E Corporation and the Utility during 2008.

As of December 31, 2008, there was less than $1 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted average period of less than one year for PG&E Corporation and the Utility.

Restricted Stock

During 2008, PG&E Corporation awarded 591,294 shares of PG&E Corporation restricted common stock to eligible participants of PG&E Corporation and its subsidiaries, of which 396,854 shares were awarded to the Utility’s eligible participants.

Although the recipients of restricted stock can vote their shares, they may not sell or transfer their shares until the shares vest. For restricted stock awarded in 2005, there were no performance criteria and the restrictions lapsed ratably over four years. The terms of the restricted stock awarded in 2006, 2007, and 2008, provide that 60% of the shares will vest over a period of three years at the rate of 20% per year. If PG&E Corporation’s annual total shareholder return (“TSR”) is in the top quartile of its comparator group, as measured for the three immediately preceding calendar years, the restrictions on the remaining 40% of the shares will lapse in the third year. If PG&E Corporation’s TSR is not in the top quartile for such period, then the restrictions on the remaining 40% of the shares will lapse in the fifth year. Compensation expense related to the portion of the restricted stock award that is subject to conditions based on TSR is recognized over the shorter of the requisite service period and three years. Dividends declared on restricted stock are paid to recipients only when the restricted stock vests.

The tax benefit from restricted stock which vested during 2008 and 2007 totaled $2 and $7 million, respectively, of which approximately $1 million and $5 million was recorded by the Utility.

The following table summarizes restricted stock activity for PG&E Corporation and the Utility for 2008:

	Number of Shares of Restricted Stock			Weighted Average Grant-Date Fair Value

Nonvested at January 1		1,261,125		$	40.51
Granted		591,294		$	37.91
Vested		(440,652	)	$	37.20
Forfeited		(124,198	)	$	43.27
Nonvested at December 31		1,287,569		$	40.18

The following table summarizes restricted stock activity for the Utility for 2008:

	Number of Shares of Restricted Stock			Weighted Average Grant-Date Fair Value

Nonvested at January 1(1)		859,745		$	40.65
Granted		396,854		$	37.91
Vested		(303,923	)	$	37.46
Forfeited		(95,746	)	$	43.12
Nonvested at December 31		856,930		$	40.24


(1) Includes net employee transfers between PG&E Corporation and the Utility during 2008.

As of December 31, 2008, there was approximately $20 million of total unrecognized compensation cost relating to restricted stock, of which $15 million related to the Utility. The cost is expected to be recognized over a weighted average period of 1.2 years by PG&E Corporation and the Utility.

Performance Shares

During 2008, PG&E Corporation awarded 581,175 performance shares to eligible participants of PG&E Corporation and its subsidiaries, of which 396,230 shares were awarded to the Utility’s eligible participants. Performance shares are hypothetical shares of PG&E Corporation common stock that vest at the end of a three-year performance period and are settled in cash. Upon vesting, the amount of cash that recipients are entitled to receive, if any, is determined by multiplying the number of vested performance shares by the average closing price of PG&E Corporation common stock for the last 30 calendar days of the last year in the three year performance period. This result is then adjusted by a payout percentage ranging from 0% to 200% as measured by PG&E Corporation’s TSR relative to its comparator group for the applicable three-year performance period. During 2008, PG&E Corporation paid $6.9 million to performance share recipients, of which $5 million related to Utility employees.

As of December 31, 2008, $46 million was accrued as the performance share liability for PG&E Corporation, of which $29.7 million related to Utility employees. The number of performance shares that were outstanding at December 31, 2008 was 1,422,302, of which 938,059 was related to Utility employees. Outstanding performance shares are classified as a liability on the Consolidated Balance Sheets of PG&E Corporation and the Utility because the performance shares can only be settled in cash. The liability related to the performance shares is marked to market at the end of each reporting period to reflect the market price of PG&E Corporation common stock and the payout percentage at the end of the reporting period. Accordingly, compensation expense recognized for performance shares will fluctuate with PG&E Corporation’s common stock price and its TSR relative to its comparator group.

NOTE 15: 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.

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, 2007:

(in millions)
Balance at December 31, 2007	$	1,719
Interest accrued		80
Less: Settlements		(49	)
Balance at December 31, 2008	$	1,750

As of December 31, 2008, the Utility’s net disputed claims liability was approximately $1,750 million, consisting of approximately $1,580 million of remaining disputed claims (classified on the Consolidated Balance Sheets as Accounts payable – Disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $664 million (classified on the Consolidated Balance Sheets as Interest payable) offset by accounts receivable from the CAISO and PX of approximately $494 million (classified on the Consolidated Balance Sheets as Accounts receivable – Customers).

In connection with the Utility’s proceedings under Chapter 11, the Utility established an escrow account for the payment of the disputed claims, which is classified on the Consolidated Balance Sheets as Restricted cash. As of December 31, 2008, the Utility held $1,212 million in escrow, including interest earned, for payment of the remaining net disputed claims.

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.

The Utility and the PX have been negotiating the terms of a proposed agreement regarding the potential transfer of $700 million to the PX from the Utility’s escrow account established for disputed claims to enable the PX to fund future settlements, pay refund claims, or amounts owed to CAISO or PX markets, as may be authorized by the FERC or a court of competent jurisdiction. The proposed agreement would be subject to approval by the FERC and by the bankruptcy courts that have jurisdiction of the Chapter 11 proceedings of the PX and the Utility. Under the proposed agreement, the Utility’s payment would reduce its liability for remaining net disputed claims. To protect the Utility against the imposition of double liability, the proposed agreement would provide that, to the extent that both the PX and an individual electricity supplier have filed claims relating to the same transaction, such claim would be paid by the Utility only once, either to the PX or directly to the electricity supplier, as may be ordered by the FERC or a court of competent jurisdiction. It is uncertain when a final agreement will be executed and, if executed, when required approvals would be obtained.

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

In accordance with various agreements, 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 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 expenses excluding fuel purchases, 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:

	Year Ended December 31,
	2008			2007			2006
(in millions)
Utility revenues from:
Administrative services provided to PG&E Corporation		$	4		$	4		$	5
Interest from PG&E Corporation on employee benefit assets			-			1			1
Utility expenses from:
Administrative services received from PG&E Corporation		$	122		$	107		$	108
Utility employee benefit payments provided to PG&E Corporation Corporation			2			4			3

At December 31, 2008 and December 31, 2007, the Utility had a receivable of approximately $29 million from PG&E Corporation included in Accounts receivable – Related parties and Other Noncurrent Assets – Related parties receivable on the Utility’s Consolidated Balance Sheets and a payable of approximately $25 million and $28 million, respectively to PG&E Corporation included in Accounts payable – Related parties on the Utility’s Consolidated Balance Sheets.

NOTE 17: 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, employee matters, 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 electric energy and capacity and makes payments under existing power purchase agreements. The price of purchased power may be fixed or variable. Variable pricing is generally based on either the current market price of gas or electricity at the date of purchase.

Qualifying Facility Power Purchase Agreements – Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), electric utilities were required to purchase energy and capacity from independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (“QFs”). To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices, and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the QF’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the applicable power purchase agreement.

The Energy Policy Act of 2005 significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to waive the obligation of an electric utility under Section 210 of PURPA to purchase the electricity offered to it by a QF (under a new contract or obligation) if the FERC finds the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits such waivers to a particular QF or on a “service territory-wide basis.” The Utility plans to wait until after the new day-ahead market structure provided for in the CAISO’s MRTU initiative to restructure the California electricity market becomes effective to assess whether it will file a request with the FERC to terminate its obligations under PURPA and to enter into new QF purchase obligations.

As of December 31, 2008, the Utility had agreements with 246 QFs for approximately 3,900 MW that are in operation. Agreements for approximately 3,600 MW expire at various dates between 2009 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with 74 inoperative QFs. The total of approximately 3,900 MW consists of approximately 2,500 MW from cogeneration projects, 600 MW from wind projects and 800 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreements accounted for approximately 18%, 20%, and 20% of the Utility’s 2008, 2007, and 2006 electricity sources, respectively. No single QF accounted for more than 5% of the Utility’s 2008, 2007, or 2006 electricity sources.

Irrigation Districts and Water Agencies – The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2010 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 2%, 3%, and 6% of the Utility’s electricity sources in 2008, 2007, and 2006, respectively.

Renewable Energy Contracts – California law requires that each California retail seller of electricity, except for municipal utilities, increase its purchases of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity delivered from renewable resources equals at least 20% of its total retail sales by the end of 2010. The Utility has entered into new renewable power purchase contracts that will help the Utility meet this renewable portfolio standard (“RPS”) by 2010.

Long-Term Power Purchase Agreements – In accordance with the Utility’s CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements with third parties. The Utility’s obligations under a portion of these agreements are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreements.

Annual Receipts and Payments – The payments made under QFs, irrigation district and water agency, renewable energy, and other power purchase agreements during 2008, 2007 and 2006 were as follows:

(in millions)	2008		2007		2006
Qualifying facility energy payments	$	969	$	812	$	661
Qualifying facility capacity payments		343		363		366
Irrigation district and water agency payments		69		72		64
Renewable energy and capacity payments		714		604		429
Other power purchase agreement payments		2,036		1,166		670

The amounts above do not include payments related to DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

At December 31, 2008, the undiscounted future expected power purchase agreement payments were as follows:

	Qualifying Facility				Irrigation District & Water Agency				Renewable				Other
(in millions)	Energy		Capacity		Operations & Maintenance		Debt Service		Energy		Capacity		Energy		Capacity		Total Payments
2009	$	949	$	412	$	38	$	26	$	427	$	12	$	5	$	270	$	2,139
2010		960		378		45		23		460		7		6		281		2,160
2011		947		364		46		21		602		7		7		164		2,158
2012		808		334		32		21		688		7		7		86		1,983
2013		755		324		21		15		583		-		7		71		1,776
Thereafter		4,882		1,866		46		38		6,986		-		3		1,038		14,859
Total	$	9,301	$	3,678	$	228	$	144	$	9,746	$	33	$	35	$	1,910	$	25,075

The following table shows the future fixed capacity payments due under the QF contracts that are accounted for as capital leases. These amounts are also included in the table above. The fixed capacity payments are discounted to the present value shown 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)
2009	$	50
2010		50
2011		50
2012		50
2013		50
Thereafter		204
Total fixed capacity payments		454
Amount representing interest		110
Present value of fixed capacity payments	$	344

Minimum lease payments associated with the lease obligation are included in Cost of electricity on PG&E Corporation and the Utility’s Consolidated Statements of Income. In accordance with SFAS No. 71, 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 accounted for as capital leases expire between April 2014 and September 2021.

At December 31, 2008, the Utility had approximately $30 million included in Current Liabilities – Other and $314 million included in Noncurrent Liabilities – Other representing the present value of the fixed capacity payments due under these contracts recorded on the Utility’s Consolidated Balance Sheets. The corresponding assets of $344 million, including amortization of $64 million, are included in Property, Plant, and Equipment on the Utility’s Consolidated Balance Sheets at December 31, 2008.

Capacity payments, which allow QFs to recover investment costs, are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the applicable power purchase agreement.

Natural Gas Supply and Transportation 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 have fluctuated generally based on market conditions. At December 31, 2008, the Utility’s undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2009	$	898
2010		183
2011		115
2012		49
2013		42
Thereafter		157
Total	$	1,444

Payments for natural gas purchases and gas transportation services amounted to approximately $2.7 billion in 2008, $2.2 billion in 2007, and $2.2 billion in 2006.

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, conversion and enrichment services provide for 100% coverage of reactor requirements through 2010, 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 also are diversified, ranging from market-based prices to base prices that are escalated using published indices. New agreements are primarily based on forward market pricing and will begin to impact nuclear fuel costs starting in 2010.

At December 31, 2008, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2009	$	95
2010		108
2011		92
2012		79
2013		81
Thereafter		495
Total	$	950

Payments for nuclear fuel amounted to approximately $157 million in 2008, $102 million in 2007, and $106 million in 2006.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases, vehicle leasing, and telecommunication and information system contracts. At December 31, 2008, the future minimum payments related to other commitments were as follows:

(in millions)
2009	$	45
2010		18
2011		17
2012		17
2013		16
Thereafter		34
Total	$	147

Payments for other commitments and operating leases amounted to approximately $41 million in 2008, $38 million in 2007, and $100 million in 2006.

Underground Electric Facilities

At December 31, 2008, the Utility was committed to spending approximately $228 million for the conversion of existing overhead electric facilities to underground electric facilities. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and telephone utilities involved. The Utility expects to spend approximately $40 million to $60 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain indemnity obligations of its former subsidiary, NEGT, that were issued to the purchaser of an NEGT subsidiary company. PG&E Corporation’s sole 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 its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

Utility

Application to Recover Hydroelectric Facility Divestiture Costs

California Department of Water Resources Contracts

Electricity purchased under the DWR allocated power purchase contracts with various generators provided approximately 15.1% of the electricity delivered to the Utility’s customers for the year ended December 31, 2008. The DWR remains legally and financially responsible for its power purchase contracts. The Utility acts as a billing and collection agent of the DWR’s revenue requirements from the Utility’s customers.

The DWR has stated publicly in the past that it intends to transfer full legal title of, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. In addition, the Chapter 11 Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

●	After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by S&P will be no less than A. The Utility’s current issuer rating by Moody’s is A3 and the Utility’s long-term issuer credit rating by S&P is BBB+;

●	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

●	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

In February 2008, the CPUC, opened an investigation of how the DWR can end its role in purchasing power for the customers of the California investor-owned utilities through novation of the DWR contracts or otherwise. In November 2008, the CPUC issued a decision directing the investor owned utilities to proceed with efforts to novate or renegotiate the DWR contracts, and set a tentative goal of January 1, 2010 for completing novation or renegotiations. However, the CPUC recognized that various uncertainties may influence the achievement of this goal, and indicated that it will continue to monitor the progress of the investor-owned utilities, and make mid-course adjustments as necessary. Until the DWR’s obligation under its power purchase contracts are terminated, the CPUC is prohibited by state law from reinstating “direct access.” Direct access is the ability of retail end-user customers to purchase electricity from energy providers other than the California investor-owned electric utilities.

Incentive Ratemaking for Energy Efficiency Programs

The CPUC has established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. The maximum amount of revenue that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers, over the 2006-2008 program cycle is $180 million.

On December 18, 2008, the CPUC awarded the Utility $41.5 million in interim shareholder incentive revenues for the 2006-2007 interim claim, ruling that 65% of the 2006-2007 incentive claims should be “held back” until completion of final measurement studies and a final verification report for the entire three-year program cycle.

As long as the final measured energy savings are at least 65% of each of the CPUC’s individual savings goals over the 2006-2008 program period, the utilities will not be required to pay back any incentives received on an interim basis. The CPUC also ruled that the utilities will not be entitled to any additional incentives for the 2006-2008 program period beyond the incentives already received if the utility’s performance falls within a “deadband;” i.e., if a utility achieves (1) less than 80% of the CPUC’s goal for any individual savings metric or (2) less than 85% of the CPUC’s overall energy savings goal but greater than 65% of the CPUC’s goal for each individual savings metric. On February 2, 2009, The Utility Reform Network and the CPUC’s Division of Ratepayer Advocates filed an application for rehearing of the CPUC’s December 18, 2008 award.

On January 29, 2009 the CPUC instituted a new proceeding to modify the existing incentive ratemaking mechanism, to adopt a new framework to review the utilities’ 2008 energy efficiency performance, and to conduct a final review of the utilities’ performance over the 2006-2008 program period. The CPUC also plans to develop a long-term incentive mechanism for program periods beginning in 2009 and beyond.

Whether the Utility will receive all or a portion of the remaining $77 million in incentives for the 2006 and 2007 program years, whether the Utility will receive any additional incentives or incur a reimbursement obligation in 2009 based on the second interim claim, and whether the final true-up in 2010 will result in a positive or negative adjustment, depends on the new framework and rules to be adopted by the CPUC.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at its Diablo Canyon nuclear generating facilities 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 $39.3 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.)

100

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $12.5 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for Diablo Canyon. The balance of the $12.5 billion 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 MW or higher. If a nuclear incident results in costs in excess of $300 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 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.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of possible clean-up costs. The Utility reviews its remediation liability on a quarterly basis. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure using current technology, and considering enacted laws and regulations, experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. The Utility estimates the upper end of this cost range using possible outcomes that are least favorable to the Utility. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives.

The Utility had an undiscounted and gross environmental remediation liability of approximately $568 million at December 31, 2008, and approximately $528 million at December 31, 2007. The $568 million accrued at December 31, 2008 consists of:

●	Approximately $51 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

●	Approximately $167 million for remediation at the Utility’s natural gas compressor site located in Topock, Arizona near the California border;

●	Approximately $83 million related to remediation at divested generation facilities;

●	Approximately $216 million related to remediation costs for the Utility’s generation and other facilities, third-party disposal sites, and manufactured gas plant 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 manufactured gas plant sites); and

●	Approximately $51 million related to remediation costs for fossil decommissioning sites.

Of the approximately $568 million environmental remediation liability, approximately $123 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately $356 million will be recoverable in future rates. 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. Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable from customers.

The Utility's undiscounted future costs could increase to as much as $944 million 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. The amount of approximately $944 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

The Utility’s Diablo Canyon power plant uses a process known as “once through cooling” that takes in water from the ocean to cool the generating facility and discharges the heated water back into the ocean. 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 reflect the best technology available to minimize adverse environmental impacts. In July 2004, the U.S. Environmental Protection Agency (“EPA”) issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued a proposed policy to address once through cooling. The Water Board’s current proposal would require the installation of cooling towers at nuclear facilities by January 1, 2021, unless the installation of cooling towers would conflict with a nuclear safety requirement.

Various parties separately challenged the EPA’s regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test could not be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court is expected to issue a decision by mid-2009 regarding the cost-benefit test. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.

101

Legal Matters

In accordance with SFAS No. 5, "Accounting for Contingencies" 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 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 and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability for legal matters is included in PG&E Corporation and the Utility's Current Liabilities - Other in the Consolidated Balance Sheets, and totaled approximately $72 million at December 31, 2008 and approximately $78 million at December 31, 2007. After consideration of these accruals, PG&E Corporation and the Utility do not expect losses associated with legal matters would have a material adverse impact on their financial condition and result of operations.

102

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

	Quarter ended
	December 31		September 30		June 30		March 31
(in millions, except per share amounts)
2008
PG&E CORPORATION
Operating revenues	$	3,643	$	3,674	$	3,578	$	3,733
Operating income		545		639		584		493
Income from continuing operations		363		304		293		224
Net income		517		304		293		224
Earnings per common share from continuing operations, basic		0.98		0.83		0.80		0.62
Earnings per common share from continuing operations, diluted		0.97		0.83		0.80		0.62
Net income per common share, basic		1.39		0.83		0.80		0.62
Net income per common share, diluted		1.37		0.83		0.80		0.62
Common stock price per share:
High		39.20		42.64		40.90		44.95
Low		29.70		36.81		38.09		36.46
UTILITY
Operating revenues	$	3,643	$	3,674	$	3,578	$	3,733
Operating income		548		640		585		493
Net income		329		321		313		236
Income available for common stock		325		318		309		233
2007
PG&E CORPORATION
Operating revenues	$	3,415	$	3,279	$	3,187	$	3,356
Operating income		448		582		555		529
Income from continuing operations		203		278		269		256
Net income		203		278		269		256
Earnings per common share from continuing operations, basic		0.56		0.77		0.75		0.71
Earnings per common share from continuing operations, diluted		0.56		0.77		0.74		0.71
Net income per common share, basic		0.56		0.77		0.75		0.71
Net income per common share, diluted		0.56		0.77		0.74		0.71
Common stock price per share:
High		48.56		47.87		50.89		47.71
Low		43.09		42.14		43.90		43.87
UTILITY
Operating revenues	$	3,416	$	3,279	$	3,187	$	3,356
Operating income		453		585		556		531
Net income		206		283		274		261
Income available for common stock		203		279		270		258

103

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of PG&E Corporation and Pacific Gas and Electric Company (“Utility”) is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation's and the Utility's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2008.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the Consolidated Balance Sheets of PG&E Corporation and the Utility as of December 31, 2008 and 2007, and the related Consolidated Statements of Income, Shareholders’ Equity, and Cash Flows ended December 31, 2008 for each of the three years in the period ended December 31, 2008. As stated in their report, which is included in this annual report, Deloitte & Touche LLP also has audited PG&E Corporation’s and the Utility's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PG&E Corporation and Pacific Gas and Electric Company

San Francisco, California

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2008 and 2007, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. We also have audited the Company’s and the Utility’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s and the Utility’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s and the Utility’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audits of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company and of the Utility as of December 31, 2008 and 2007, and the respective results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company and the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 of the Notes to the Consolidated Financial Statements, in January 2008 the Company and the Utility adopted new accounting standards addressing fair value measurement and an amendment to an interpretation of accounting standards for offsetting amounts related to certain contracts. In 2007, the Company and the Utility adopted a new interpretation of accounting standards for uncertainty in income taxes. In 2006, the Company and the Utility adopted new accounting standards for defined benefit pensions and other postretirement plans and share-based payments.

DELOITTE & TOUCHE LLP

February 19, 2009

San Francisco, CA

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