~~Natural Gas~~In December 2007, the FERC approved a settlement between the Utility and PacificCorp, both owners of an electric transmission line which is part of the California – Oregon Intertie, and other entities, relating to the termination of agreements that govern electric transmission service over the California – Oregon Intertie. For more information, see “Electric Utility Operations – Electric Transmission” below. As a condition of the settlement, the Utility will lease back a portion of the capacity allocated to PacifiCorp from 2008 through 2017 over the eastern 500 KV line between the substation in Malin, Oregon, and the Round Mountain substation located in California. In addition, the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.

~~The~~Natural Gas ~~Accord~~

~~Under a ratemaking pact called the Gas Accord, the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services.~~ The Gas Accord ~~established natural gas transportation rates and natural gas storage rates.~~

On ~~December 16, 2004,~~September 20, 2007, the CPUC ~~approved~~issued a final decision approving a multi-party settlement agreement, ~~to retain~~known as the Gas Accord ~~market structure,~~IV, to establish the Utility’s natural gas transmission and ~~resolve the~~storage rates and ~~terms and conditions of service for the Utility's~~associated revenue requirements from January 1, 2008 through December 31, 2010. The Gas Accord IV establishes a 2008 natural gas ~~transportation~~transmission and storage ~~system~~revenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the ~~three-year period~~proposed 2008 revenue requirement), and a 2010 revenue requirement of ~~2005 through 2007. The Utility continues~~$471 million (approximately 2.7% above the proposed 2009 revenue requirement). A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will continue to be atassured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements will continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of ~~not recovering its natural gas transportation~~firm, two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available, one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. The Utility’s backbone transmission costs are partly assured of recovery to the extent backbone capacity is subscribed under long-term firm contracts, and to the extent the costs of that contracted capacity are recovered through fixed reservation charges. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 32% of the total backbone capacity on the Utility’s system. Core customers pay approximately 71% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

Local Transmission. The local transmission revenue requirement is allocated approximately 70% to core customers and 30% to non-core customers. The core portion is protected through a balancing account and therefore represents assured revenues. The non-core portion is subject to volumetric cost recovery risk.

Storage. The storage revenue requirement is allocated approximately 71% to core customers, 13% to non-core storage service, and 17% to pipeline load balancing service. The core portion is protected through a balancing account and therefore represents assured revenues. Recovery of the non-core portion is subject to volumetric and price risk. The pipeline load balancing

portion is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Taken together, the backbone transmission, local transmission, and storage costs that are either protected through balancing accounts or recovered through long-term firm contract reservation charges amount to approximately 47% of the Utility’s total revenue requirement for gas transmission and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues, except for core local transmission revenue and core storage costs.storage.

Biennial Cost Allocation Proceeding

Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

Natural Gas Procurement

~~Natural Gas Procurement~~

The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The ~~CPIM~~Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is ~~used to determine~~protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the ~~reasonableness of the Utility's costs of purchasing natural gas for its customers.~~CPIM. Under the CPIM, the Utility's ~~natural gas~~ purchase costs ~~(including Canadian and interstate capacity and volumetric transportation charges)~~ for a fixed twelve-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 ~~currently between~~ 99% ~~and~~to 102% of the benchmark, are considered reasonable and are fully ~~recoverable~~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 ~~three-fourths~~in their rates 75% of any savings resulting from the ~~savings when the costs are below~~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. ~~Any awards associated~~While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the ~~CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards~~market-based benchmark, are not ~~included in earnings until approved by the CPUC.~~

~~In response~~expected to ~~rising natural~~materially impact net income. The Utility also has received CPUC approval for a long-term gas ~~prices, on October 6, 2005, the CPUC granted the Utility authority to purchase hedges~~hedging program on behalf of ~~the Utility's core gas customers for the winters of 2005-06, 2006-07, and 2007-08, and to book the costs of such hedges in a separate balancing account, outside of the CPIM. As a result,~~ core customers, ~~will pay the cost of these hedges and receive any payouts under these hedges. Since the hedging is outside of CPIM, the Utility is at risk to the extent that the CPUC may disallow portions~~through 2011. The costs of the hedging ~~cost based on its subsequent review of the Utility’s performance under the filed hedging plan. As part of the hedging plan, the Utility also agreed to forgo a shareholder award under~~program are recovered directly from gas customers, outside the CPIM ~~for~~mechanism, and are subject only to a compliance review, not an after-the-fact reasonableness review. (For more information see the ~~2004-2005 CPIM year.~~“Risk Management Activities” section of MD&A in the 2007 Annual Report).

On September 2, 2004, the CPUC issued an order establishing a process whereby utilities receive CPUC pre-approval of contracts for interstate and Canadian pipeline capacity to support their natural gas procurement activities.

Interstate and Canadian Natural Gas Transportation and Storage

The Utility's interstate and Canadian natural gas transportation agreements with ~~third party~~third-party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Energy and Utilities Board and the National Energy Board. The Utility's agreements with interstate and Canadian natural

gas transportation service providers are administered as part of the Utility's core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. In 2007, in conjunction with the settlement of a FERC rate case filed by TransCanada’s Gas Transmission Northwest Corporation, which transports Canadian natural gas to California, the Utility agreed to extend its existing contract commitment for a series of multiple-year terms. The FERC approved the settlement in January 2008. The settlement is further discussed below under “Natural Gas Utility Operations – Interstate and Canadian Natural Gas Transportation Services Agreements.”

~~Environmental Matters~~Electric Utility Operations

Electricity Resources

The following table shows the percentage of the Utility's total sources of electricity for 2007 represented by each major electricity resource:

Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)	32%
DWR	25%
Qualifying Facilities/Renewables	20%
Irrigation Districts	3%
Other Power Purchases	20%

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. Least-cost dispatch requires the Utility, in certain cases, to schedule more electricity than is necessary to meet its retail load and therefore to sell this electricity on the wholesale electricity 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. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR, based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

Owned Generation Facilities

At December 31, 2007, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type	County Location	Number of Units	Net Operating Capacity (MW)
Nuclear:
Diablo Canyon	San Luis Obispo	2	2,240
Hydroelectric:
Conventional	16 counties in northern and central California	107	2,684
Helms pumped storage	Fresno	3	1,212
Hydroelectric subtotal		110	3,896
Fossil fuel:
Humboldt Bay(1)	Humboldt	2	105
Mobile turbines	Humboldt	2	30
Fossil fuel subtotal		4	135
Total		116	6,271

(1)	The Humboldt Bay facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants. As described below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.

Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-year period ended December 31, 2007, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 90.2%.

The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 17: Commitments and Contingencies— Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 48 days. The Utility will replace the steam generators in Unit 2 during the scheduled refueling outage which began on February 4, 2008 and will replace the steam generators in Unit 1 during the scheduled refueling outage to begin January 2009. Due to this additional work, each of these refueling outages is expected to last approximately 76 days. (The capital

expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2007 Annual Report.) The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

	2008	2009	2010	2011	2012
Unit 1
Refueling	-	January	October		April
Duration (days)	-	76	35		30
Startup	-	April	November		May
Unit 2
Refueling	February	October	-	May
Duration (days)	76	35	-	30
Startup	April	November	-	June

In addition, as discussed below under “Environmental Matters — Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed in 2008. To provide another storage alternative in the event that construction of the dry cask storage facility is delayed, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, the operation of Unit 1 may have to be curtailed or halted as early as 2010 and the operation of Unit 2 may have to be curtailed or halted as early as 2011 until such time as additional spent fuel can be safely stored.

Hydroelectric Generation Facilities. The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 statements of water diversion and use. All but three of the Utility's powerhouses are licensed by the FERC, with license terms between 30 and 50 years. In the last five years, the FERC renewed six hydroelectric licenses with a total of 699 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects with approximately 1,314 MW of additional hydroelectric power. Although the original licenses associated with 917 MW of the 1,314 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,569 MW of hydroelectric power will expire between 2013 and 2043.

DWR Power Purchases

During 2007, electricity from the DWR contracts allocated to the Utility provided approximately 25% of the electricity delivered to the Utility's customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. During 2007, the DWR terminated a long-term power purchase agreement it had with Calpine Corporation over the objections of the Utility and other interested parties. As a result, the Utility has had to purchase replacement power on behalf of its customers at a significantly higher price. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as the contracts expire or are terminated. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

Third-Party Power Purchase Agreements

Qualifying Facility Power Purchase Agreements. As of December 31, 2007, the Utility had agreements with 257 QFs for approximately 4,097 MW that are in operation. Agreements for approximately 3,754 MW expire at various dates between 2008 and 2028. QF power purchase agreements for approximately 343 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 approximately 74 inoperative QFs. The total of approximately 4,097 MW consists of approximately 2,524 MW from cogeneration projects, 580 MW from wind projects and 994 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreements accounted for approximately 20%, 20%, and 22% of the Utility’s 2007, 2006, and 2005 electricity sources, respectively. No single QF accounted for more than 5% of the Utility's 2007, 2006, or 2005 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 2008 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 3% of the Utility’s 2007 electricity sources, approximately 6% of the Utility’s 2006 electricity sources and 5% of the Utility’s 2005 electricity sources.

Renewable Energy Contracts. California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010. The CPUC has adopted "flexible compliance" rules, which allow deliveries above interim required levels to be carried forward, permit a retail seller to maintain a procurement deficit for up to three years following the year in which the deficit is incurred, and may, in certain cases, provide allowable reasons for noncompliance. During 2007, the Utility entered into 9 new renewable power purchase agreements, representing approximately 3,000 GWh per year of renewable generation that will help the Utility to meet its goals. The Utility expects to use the flexible compliance Rules to meet the 2010 requirement. Failure to satisfy the targets may result in a penalty of five cents per kWh, with an annual penalty cap of $25 million. The exact amount of any penalty and conditions under which it would be applied are subject to the CPUC’s review of whether supply-side factors or other circumstances caused the under-delivery.

Long Term Power Purchase Agreements. In December 2007, the CPUC approved, with several modifications, the long-term electricity procurement plans (“LTPPs”) of the California investor-owned electric utilities covering the 10-year period from 2007 through 2016. Each utility is required to submit an LTPP designed to reduce greenhouse gas emissions and uses the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation). The decision notes that if a previously approved contract is terminated before the generation project is built, the utilities will retain the procurement authority for the MWs subject to the terminated contract. At the end of the solicitation or request-for-offer (“RFO”) process, the utilities must justify why each bid was selected or rejected. Utilities can acquire ownership of new conventional generation resources in the utilities’ competitive RFO process only through turnkey and engineering, procurement, and construction arrangements proposed by third parties. The utilities are required to submit revised LTPPs reflecting the changes required by the CPUC within 90 days of the date the decision is mailed.

For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

Future Long-Term Generation Resources

On December 20, 2007, the CPUC issued a decision that approves, with several modifications, the California investor-owned utilities’ long-term electricity procurement plan covering procurement during 2007-2016. The CPUC forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new conventional generation by 2015 based on forecasts prepared by the CEC. The decision finds that in earlier years (i.e., 2007-2013), the Utility has a surplus of resources and in 2014 the forecast shows a small need for 66 MW.

The decision allows the utilities to acquire ownership of new conventional generation resources only through turnkey and engineering, construction, and procurement (“EPC”) arrangements proposed by third parties. The decision prohibits the utilities from submitting bids for utility-build generation in their respective RFOs until questions can be resolved about how to compare utility-owned generation bids with bids from independent power producers. The decision also permits utility-owned generation projects to be proposed 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 expand existing facilities, (4) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement) and (5) to meet unique reliability needs.

Electricity Transmission

At December 31, 2007, the Utility owned 18,680 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 54,709 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 140,684 circuit miles of distribution lines and substations with a capacity of 26,370 MVA. In 2007, the Utility delivered 86,179 GWh to its customers, including 6,723 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

In 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility has entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego

Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO.The Utility is required to give the CAISO two years’ notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment- Federal Energy Regulation.”

In April 2006, the Utility completed a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County. As result of the completion of the transmission line, the Utility was able to retire the Hunters Point power plant in San Francisco. The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.) Potential transmission projects include a 500-kV transmission line to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia. In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.

In December 2007, the FERC approved a settlement between the Utility and PacifiCorp, both owners of an electric transmission line which is part of the California – Oregon Intertie (“COI”), as well as other entities, relating to the termination of agreements that govern transmission service over the COI. The COI is a major electric transmission link connecting California with the Pacific Northwest and vital to electric grid reliability. The settlement provides for the shared usage and coordinated planning, operation, and maintenance of the eastern 500 kV transmission line between the Malin substation in Oregon and the Round Mountain substation in California. As a result of the settlement, the Utility and PacifiCorp will each have rights to half of the capacity on the eastern 500 kV transmission line between the Malin and Round Mountain substations for a twenty year period. In addition, the Utility will lease back a portion of the capacity allocated to PacifiCorp for the first ten years. The settlement allows the Utility to continue its rights to all existing available transmission service over the eastern 500 KV line between the Malin and Round Mountain substations through December 31, 2011; these rights decrease to half of the total capacity by 2018. The settlement also provides that the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.

Electricity Distribution Operations

The Utility's electricity distribution network extends through 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,684 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 93 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 605 distribution substations and 110 low-voltage distribution substations. The 54 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 points. This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as

municipal and other utilities, that then resell the electricity.

During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers. These meters will enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which will allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. On December 12, 2007, the Utility filed an application with the CPUC requesting approval to upgrade elements of the Utility’s SmartMeter™ program. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility. These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers. In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner. (For more information about the advanced metering infrastructure, see the section entitled “Capital Expenditures” in the MD&A portion of the 2007 Annual Report.)

2007 Electricity Deliveries

The following table shows the percentage of the Utility's total 2007 electricity deliveries represented by each of its major customer classes:

Total 2007 Electricity Delivered: 86,179 GWh

Agricultural and Other Customers	7%
Industrial Customers	18%
Residential Customers	36%
Commercial Customers	39%

Electricity Distribution Operating Statistics

The following table shows certain of the Utility's operating statistics from 2003 to 2007 for electricity sold or delivered, including the classification of sales and revenues by type of service.

	2007			2006			2005			2004			2003
Customers (average for the year):
Residential		4,464,483			4,417,638			4,353,458			4,366,897			4,286,085
Commercial		521,732			515,297			509,786			509,501			493,638
Industrial		1,261			1,212			1,271			1,339			1,372
Agricultural		80,366			79,006			78,876			80,276			81,378
Public street and highway lighting		29,643			28,799			28,021			27,176			26,650
Other electric utilities		2			4			4			3			4
Total (1)		5,097,487			5,041,956			4,971,416			4,985,192			4,889,127
Deliveries (in GWh):(2)
Residential		30,796			31,014			29,752			29,453			29,024
Commercial		33,986			33,492			32,375			32,268			31,889
Industrial		15,159			15,166			14,932		��	14,796			14,653
Agricultural		5,402			3,839			3,742			4,300			3,909
Public street and highway lighting		833			785			792			2,091			605
Other electric utilities		3			14			33			28			76
Subtotal		86,176			84,310			81,626			82,936			80,156
California Department of Water Resources (DWR)		(21,193	)		(19,585	)		(20,476	)		(19,938	)		(23,554	)
Total non-DWR electricity		64,986			64,725			61,150			62,998			56,602
Revenues (in millions):
Residential	$	4,580		$	4,491		$	3,856		$	3,718		$	3,671
Commercial		4,484			4,414			4,114			4,179			4,440
Industrial		1,252			1,293			1,232			1,204			1,410
Agricultural		664			483			446			491			522
Public street and highway lighting		78			72			66			71			69
Other electric utilities		85			59			4			22			24

Subtotal		11,143			10,812			9,718			9,685			10,136
DWR		(2,229	)		(2,119	)		(1,699	)		(1,933	)		(2,243	)
Direct access credits		—			—			—			—			(277	)
Miscellaneous(3)		215			261			235			(248	)		(52	)
Regulatory balancing accounts		352			(202	)		(327	)		363			18
Total electricity operating revenues	$	9,481		$	8,752		$	7,927		$	7,867		$	7,582
Other Data:
Average annual residential usage (kWh)		6,898			7,020			6,834			6,744			6,772
Average billed revenues (cents per kWh):
Residential		14.87			14.48			12.96			12.62			12.65
Commercial		13.19			13.18			12.71			12.95			13.92
Industrial		8.26			8.53			8.25			8.14			9.62
Agricultural		12.29			12.58			11.92			11.41			13.35
Net plant investment per customer	$	3,418		$	3,148		$	2,966		$	2,790		$	2,689

(1)	Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.

(2)	These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

(3)	Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.

Natural Gas Utility Operations

The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 39 of California's 58 counties and includes most of northern and central California. In 2007, the Utility served approximately 4.3 million natural gas distribution customers. The total volume of natural gas throughput during 2007 was approximately 875 Bcf.

As of December 31, 2007, the Utility's natural gas system consisted of 41,805 miles of distribution pipelines, 6,393 miles of backbone and local transmission pipelines, and three storage facilities. The Utility's distribution network connects to the Utility's transmission and storage system at approximately 2,200 major interconnection points. The Utility’s backbone transmission system, composed primarily of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution system. The Utility's Line 300, which interconnects with the U.S. Southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.

The Utility also owns and operates three underground natural gas storage fields connected to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

In September 2007, the Utility announced that it had entered into an agreement with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, to develop an underground natural gas storage facility near Fresno, California. The new storage facility would provide approximately 20 Bcf of total capacity once the initial phase is completed, expected in 2010. On February 4, 2008, the parties executed a Joint Project Agreement which provides the Utility a 25% interest in the initial project phase. Development of the project is subject to CPUC issuance of a Certificate of Public Convenience and Necessity and an environmental review to be conducted by the CPUC under the California Environmental Quality Act. The parties plan to file an application with the CPUC in May 2008.

The CPUC divides the Utility's natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2007, core customers represented more than 99% of the Utility's total customers and 38% of its total natural

gas deliveries, while non-core customers comprised less than 1% of the Utility's total customers and 62% of its total natural gas deliveries.

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 procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as bundled natural gas service. Currently, over 99% of core customers, representing over 96% of core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service through that avenue. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility's procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2006 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.3% for the years 2006 through 2025. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.

2007 Natural Gas Deliveries

The following table shows the percentage of the Utility's total 2007 natural gas deliveries represented by each of the Utility's major customer classes:

Total 2007 Natural Gas Deliveries: 875 Bcf

Residential Customers	26%
Transport-only Customers (non-core)	62%
Commercial Customers	12%

Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2003 through 2007 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

	2007		2006		2005		2004		2003
Customers (average for the year):
Residential		4,030,499		3,989,331		3,929,117		3,812,914		3,744,011
Commercial		223,330		220,024		216,749		215,547		208,857
Industrial		958		988		962		2,178		1,988
Other gas utilities		6		6		6		6		6
Total		4,254,793		4,210,349		4,146,834		4,030,645		3,954,862
Gas supply (MMcf):

Purchased from suppliers in:
Canada		199,870			202,274			204,884			205,180			196,278
California		(23,065	)		(13,401	)		(18,951	)		(9,108	)		(7,421	)
Other states		101,271			103,658			103,237			103,801			102,941
Total purchased		278,076			292,531			289,170			299,873			291,798
Net (to storage) from storage		(1,120	)		4,359			(3,659	)		(532	)		1,359
Total		276,955			296,890			285,511			299,341			293,157
Utility use, losses, etc. (1)		(12,760	)		(27,610	)		(14,312	)		(19,287	)		(14,307	)
Net gas for sales		264,196			269,280			271,199			280,054			278,850
Bundled gas sales (MMcf):
Residential		196,092			196,092			194,108			201,601			198,580
Commercial		67,293			73,178			77,056			78,080			79,891
Industrial					10			35			373			379
Other gas utilities	___			___				—			—			—
Total		264,196			269,280			271,199			280,054			278,850
Transportation only (MMcf):		605,259			559,270			572,869			597,706			525,353
Revenues (in millions):
Bundled gas sales:
Residential	$	2,378		$	2,452		$	2,336		$	1,944		$	1,836
Commercial		766			859			885			712			697
Industrial														1
Other gas utilities														1
Miscellaneous		88			121			(22	)		(29	)		(31	)
Regulatory balancing accounts		186			40			340			316			68
Bundled gas revenues		3,417			3,472			3,539			2,943			2,572
Transportation service only revenue		340			315			237			270			284
Operating revenues	$	3,757		$	3,787		$	3,776		$	3,213		$	2,856
Selected Statistics:
Average annual residential usage (Mcf)		49			49			49			53			53
Average billed bundled gas sales revenues per Mcf:
Residential	$	12.07		$	12.50		$	12.04		$	9.64		$	9.25
Commercial		11.38			11.73			11.48			9.12			8.73
Industrial					1.03			0.61			(0.56	)		2.48
Average billed transportation only revenue per Mcf		0.56			0.56			0.42			0.45			0.54
Net plant investment per customer	$	1,375		$	1,304		$	1,262		$	1,266		$	1,261

(1)	Includes fuel for the Utility's fossil fuel-fired generation plants.

Natural Gas Supplies

The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2007, the Utility purchased approximately 278,076 Mcf of natural gas (net of the sale of excess supply) from 67 suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 11% of the total natural gas volume the Utility purchased during 2007.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2007, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

	2007					2006					2005					2004					2003
	MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price		MMcf			Avg. Price
Canada		199,870		$	6.63		202,274		$	6.27		204,884		$	7.12		205,180		$	5.37		196,278		$	4.73
California (1)		(23,065	)	$	6.77		(13,401	)	$	7.04		(18,951	)	$	7.70		(9,108	)	$	4.89		(7,421	)	$	3.39
Other states (substantially all U.S. southwest)		101,271		$	6.30		103,658		$	6.51		103,237		$	7.10		103,801		$	5.44		102,941		$	4.63
Total/weighted average		278,076		$	6.50		292,531		$	6.32		289,170		$	7.07		299,873		$	5.41		291,798		$	4.73

(1)	California purchases include supplies from various California producers and supplies transported into California by others.

Gas Gathering Facilities

The Utility's gas gathering system collects natural gas from third-party wells in California. During 2007, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 117.26 miles of gas gathering pipelines. The Utility receives gas well production at approximately 230 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 8 California counties. Approximately 132 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2007.

Interstate and Canadian Natural Gas Transportation Services Agreements

In 2007, approximately 60% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. hese companies' pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”) which provides natural gas transportation services to a point of interconnection with the Utility's natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has a firm transportation agreement with GTN for these services. As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.

During 2007, approximately 34% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about the Utility's firm natural gas transportation agreements in effect during 2007, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

Pipeline	Expiration Date		Quantity MDth per day	Demand Charges for the Year Ended December 31, 2007 (In millions)

TransCanada NOVA Gas Transmission, Ltd.	12/31/2009	(1)	619	$29.5
TransCanada PipeLines Ltd., B.C. System	10/31/2009		611	15.7
Gas Transmission Northwest Corporation	10/31/2009		610	89.6
Transwestern Pipeline Company	03/31/2010		150	15.9
El Paso Natural Gas Company (2)	Various		252	17.2
Kern River Gas Transmission Company(3)	2/28/2007		29	0.4

(1)	A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2009.

(2)	As of December 31, 2007, the Utility had four active contracts with El Paso with expiration dates ranging from February 29, 2008 to June 30, 2012.

(3)	This contract was not renewed.

As required by the all-party settlement of GTN’s most recent general rate case approved by the FERC on January 7, 2008, the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009 and terminate on various dates unless renewed, as follows:

Also, as part of the same settlement, the Utility has entered into a separate contract with GTN for firm transportation service to support the Utility’s need for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1, 2009, through May 31, 2014.

The settlement sets rates on the GTN pipeline for a minimum term of five years commencing January 1, 2007, and provides for substantial refunds to the Utility and other shippers for the higher rates paid since that time. The Utility estimates it will receive refunds on behalf of customers of approximately $24 million by early April 2008. For contract commitments extending beyond December 31, 2011, the Utility will be obligated to pay the then-effective GTN rate as set by the FERC.

In addition, in December 2007, the Utility entered into an agreement to subscribe for 375 MDth per day of firm service rights on the proposed Ruby Pipeline for a 15-year term commencing in 2011, when the pipeline is proposed to be placed into service. The Utility’s commitment is contingent upon the satisfaction of certain conditions precedent, including CPUC approval. (For more information, see “Competition” above.) The Utility expects the CPUC will issue a decision by the end of 2008.

Environmental Matters

The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental ~~compliance.~~compliance measures. The information below reflects current estimates, ~~that~~which are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties.

General

~~General~~

The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including:

·	~~The~~ the discharge of pollutants into air, water and soil;

·	~~The~~ the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, ~~of,~~ remediation of and emergency response in connection with hazardous and radioactive substances; and

·	~~Land~~environmental impacts of land use, including endangered species and habitat protection.

The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and ~~clean up~~clean-up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where

the ~~Utility~~Utility’s wastes may have ~~disposed of wastes.~~been disposed.

Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (from customers (e.g.~~e.g.~~, for costs of cleaning up the Utility's facilities and sites where the ~~Utility has sent~~Utility’s hazardous ~~substances) from customers.~~substances have been sent). This mechanism allows the Utility to include 90% of ~~the~~eligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites ~~are~~is assigned to the Utility's customers. The balance of any insurance recoveries (90%) ~~are~~is retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels ~~would then be~~are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility's claims against third parties associated with hazardous waste remediation sites ~~are~~is retained by the ~~Utility;~~Utility, with the remainder, 90% of any such recoveries, ~~are~~ assigned to the Utility's customers.

Hazardous waste remediation costs are rising and are likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes that it can recover most of the future costs that it may incur to remediate hazardous waste through rates and insurance recoveries. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.

Air Quality and Climate Change

~~Air Quality~~

The Utility's electricity generation plants, ~~and~~ natural gas pipeline operations, fleet and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act ~~and similar~~as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter.

In addition, various laws and regulations addressing climate change are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired ~~electric utility~~ plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

~~During 2003, 2004~~The Utility’s existing and ~~2005, various multi-pollutant initiatives were introduced~~forecast emissions of climate-changing “greenhouse gases,” or GHGs, are relatively low compared to average emissions by other electric utilities and generators in the ~~U.S. Senate~~country, but the Utility anticipates that it will be affected by the increasing attention of the federal and ~~House~~state government to the control of ~~Representatives. These~~GHGs is gaining increasing attention. At the federal level, several legislative initiatives ~~proposed~~have been introduced recently in Congress aimed at addressing climate change through imposition of nation-wide regulatory limits on the emissions of ~~nitrogen oxide, sulfur dioxide, mercury~~GHGs. No such legislation has yet been enacted by Congress, but extensive hearings and ~~carbon dioxide,~~discussion are expected in the coming year. At the state level, in 2006 California enacted Assembly Bill 32 (“AB 32”), the California Global Warming Solutions Act of 2006, to address climate change. AB 32 establishes a regulatory program and ~~some would allow~~schedule to gradually reduce GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. AB 32 also authorizes the ~~use of trading mechanisms~~California Air Resources Board (“CARB”) to ~~achieve or maintain~~monitor and enforce compliance with the ~~proposed rules. Although these initiatives were~~GHG reduction program and to consider implementing market-based mechanisms, including trading of GHG emissions allowances. Pursuant to AB 32, on December 6, 2007, the CARB adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon dioxide (or its equivalent). This 1990 baseline serves as the 2020 emissions reduction target for the state of California. The CARB has not ~~enacted into law, similar legislation is expected~~yet determined reduction goals applicable to ~~be introduced~~the utility sector or individual utilities within the utility sector. The CARB also adopted a GHG reporting regulation that will require reporting of 2008 GHG emissions in 2006. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004.2009. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates the Utility's costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility's Line 300, which delivers gas from the southwest. Several other air districts are considering nitrogen oxide rules that would apply to the Utility's other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be ~~capital costs which~~required to submit verified GHG emissions reports under CARB’s reporting regulation. AB 32 requires CARB to adopt a Scoping Plan by January 2, 2009 for achieving the ~~Utility expects~~maximum technologically feasible and cost-effective GHG reductions to ~~recover through rates.~~meet the 2020 reduction target.

~~In addition,~~California Senate Bill 1368, also enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility. After a state-wide GHG emissions limit is established and is in operation, in accordance with AB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to continue, modify or rescind it.

The new California legislation, as well as current federal and other state regulatory initiatives relating to emissions of carbon dioxide and other ~~greenhouse gases,~~GHGs, particulates and other ~~toxic~~ pollutants, could ~~increase~~cause the Utility's compliance costs and capital expenditures ~~primarily with respect~~ to ~~the Utility's gas transportation facilities, fleet and fuel storage tanks. If enacted, these~~increase. These laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it ~~would be able to~~will recover these costs and capital expenditures in ~~rates.~~rates consistent with the recovery of other reasonable costs of complying with

environmental laws and regulations.

Water Quality

~~Water Quality~~

The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. The Utility's generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility's steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility's intake structure to various governmental agencies and each power plant's existing intake structure was found to meet the best technology available requirements.

The Utility's Diablo Canyon power plant employs a ~~"once-through"~~“once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System ~~or NPDES,~~(“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board or (“Central Coast ~~Board.~~Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at ~~an average~~a temperature of no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, ~~recreation, commercial/sport fishing,~~ marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant's discharge was not protective of beneficial uses.

In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

At its meeting on July 10, 2003, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published athe scientists' draft report ~~prepared by a team of scientists~~ recommending several ~~measures to mitigate the effect of the cooling water system.~~such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. ~~For a further discussion of this matter, see “Item 3. Legal Proceedings,” below.~~

In ~~addition, on~~ July 9, 2004, the ~~EPA~~U.S. Environmental Protection Agency (“EPA”) published regulations under Section 316(b) of the Clean Water Act ~~for cooling water intake structures. The regulations affect~~that apply to existing electricity generation facilities ~~using~~that use over 50 million gallons of water per day, which typically ~~including~~include some form of "once-through" ~~cooling.~~cooling in which water from natural bodies of water is used to cool a generating facility and the heated water is discharged back into the source. The Utility's Diablo Canyon ~~Hunters Point and Humboldt Bay~~ power ~~plants are~~plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The EPA regulations ~~establish a set of performance standards that vary with the type of water body and that~~ are intended to reduce impacts to aquatic ~~organisms. Significant capital investment may be required to achieve the standards. The~~organisms by establishing a set of performance standards for cooling water intake structures. These regulations allow site-specific compliance

~~determinations~~ measures if a facility's cost of compliance is significantly greater than either the benefits to be achieved or the compliance costs considered by the EPA. The EPA regulations also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In response to the EPA regulations, in June 2006, the California State Water Resources Control Board (“Water Board”) published a draft policy for California’s implementation of Section 316(b) that proposes to eliminate the EPA’s site-specific compliance options, although the draft state policy would permit environmental restoration as a compliance option for nuclear facilities if the installation of cooling towers would conflict with a nuclear safety requirement. Various parties separately challenged the EPA's regulations in court, and the cases were consolidated in U.S. Court of Appeals for the Second Circuit (“Second Circuit”). In January 2007, the Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and held that a cost-benefit test could not be used to comply with performance standards or to obtain a variance from the standards. The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard. Petitions seeking Supreme Court review of the Second Circuit’s decision are pending, and the EPA has suspended its regulations. It is uncertain when the EPA will issue revised regulations, whether the Supreme Court will accept review of the Second Circuit decision, how judicial developments will affect the EPA’s revised regulations; how judicial developments and EPA’s revised regulations will affect the Water Board’s proposed policy, and when the Water Board will issue its final policy. Depending on the nature 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 ~~developing compliance strategies for each plant.~~not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon.

~~Groundwater~~

Compressor Station Litigation

Several lawsuits have been filed against the Utility alleging that exposure to chromium at or near the ~~Utility’s Hinkley and Topock~~Utility's natural gas compressor stations ~~contains hexavalent chromium as~~caused personal injuries, wrongful deaths or other injuries. During 2006, the Utility entered into a ~~result~~settlement

agreement to resolve most of these claims. Pursuant to the settlement agreement, in April 2006 the Utility released $295 million from escrow for payment to approximately 1,100 plaintiffs. Three complaints, filed by approximately 125 plaintiffs who did not participate in the settlement, are still pending in the Superior Court for the County of Los Angeles. During 2007 some individual plaintiffs’ claims were dismissed based on the applicable statute of limitations. Also, during 2007 the Utility agreed to settle with the remaining plaintiffs, subject to execution of final documentation and court approval of the ~~Utility’s past operating practices. The Utility has a comprehensive program~~settlement of the minor plaintiffs' claims which is expected to ~~monitor a network~~occur during the first half of ~~groundwater wells at both the Hinkley~~2008. PG&E Corporation and ~~Topock natural gas compressor stations. At Hinkley,~~ the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2005, the Utility took interim measures to control movement of the Hinkley plume, as well as evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California adjacent to the Colorado River, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies, appropriate federal agencies and other interested parties, to implement interim measures as well as develop a long-term plan to ensuredo not expect that the hexavalent chromium does not affect the Colorado River. In 2005, the Utility took interim measures to control the chromium plume by extracting impacted groundwater and spent approximately $38.8 million on these measures. The Utility plans to continue these activities in 2006 and to work toward the development of a final plan to address the plume in 2006. The Utility currently estimates that itsettlement will spend at least $22 million in 2006 for remediation activities at Topock and $7.4 million in 2006 for remediation activities at Hinkley. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on ~~its~~their financial condition or results of ~~operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.~~operations.

Endangered Species

~~Endangered Species~~

Many of the Utility's facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utility's facilities or operations. The Utility is seeking to secure ~~"habitat~~“habitat conservation ~~plans"~~plans” to ensure long-term compliance with ~~the~~ state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.

Hazardous Waste Compliance and Remediation

The Utility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act ~~or RCRA,~~(“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ~~or CERCLA,~~(“CERCLA”) as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the ~~site.~~site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of a hazardous ~~substance~~substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. Preliminary remedial investigations are underway, with agency approval of a remediation plan expected by second quarter 2009. The Utility estimates that it will spend approximately $16.6 million in 2008 and approximately $22.7 million in 2009 for these activities.

In addition, the federal Toxic Substances Control Act regulates the use, disposal and clean-up of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. The Utility has removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs, representing the vast majority of PCBs ~~existing~~that had existed in the Utility's electricity distribution system.

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain ~~disposal sites and~~ retired manufactured gas plant sites. During their operation, from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The residues ~~that~~from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the

Utility or third parties. The Utility ~~owns all or a portion~~has determined that it is liable for the remediation of ~~27 manufactured gas plant~~42 sites, is potentially liable for remediation of an additional 33 sites, and is not liable for remediation at the
remaining 20 sites. The Utility has a program, in cooperation with environmental agencies and third party owners, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at ~~these sites.~~the 42 sites for which the Utility is liable. The Utility spent approximately $2$7 million in ~~2005~~2007 and expects to spend approximately $5$25 million in ~~2006~~2008 on these ~~projects.~~sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory ~~agencies. In addition, approximately 68 other manufactured gas plants in the Utility's service territory~~agencies and claims by third party owners are ~~now owned by others.~~settled. The Utility ~~spent approximately $4.1 million settling third-party~~is implementing a new program to analyze potential liability for remediation ~~claims by~~at the ~~current owners of former manufactured gas plant sites in 2005 and~~33 additional sites. Although it is ~~possible~~likely that the Utility ~~may~~will incur ~~additional clean-up~~remediation costs related to some of these sites ~~in the future if hazardous substances for which~~ the Utility ~~has liability are found.~~cannot quantify the potential amount.

Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of ~~eight~~six such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility ~~has been directed to perform site studies~~substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and ~~any necessary remedial measures by regulatory agencies. At~~led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several ~~other generators of~~parties that sent waste ~~sent~~ to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and ~~mitigation~~remediation measures.

In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments, and removal of wastes.

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2006, the Utility took interim measures to control movement of the Hinkley plume, and evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River, which is adjacent to the site. The Utility, in cooperation with the California Department of Toxic Substances Control, other state agencies and appropriate federal agencies, has implemented interim measures including a system of extractions wells and a treatment plant designed to prevent movement of the plume toward the river. In addition the Utility is working with the agencies to develop a long-term plan to ensure that the hexavalent chromium does not affect the Colorado River. In 2007, the Utility spent approximately $23 million on the interim measures and for work on the longer term site solution. The Utility plans to continue these activities in 2008 and to work toward the development of a final plan to address the plume in 2008. The Utility currently estimates that it will spend at least $20 million in 2008 for remediation activities at Topock and $14 million in 2008 for remediation activities at Hinkley. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.

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 reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, and considers 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 reasonably 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 estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.~~

The Utility had an undiscounted environmental remediation liability of approximately ~~$469~~$528 million at December 31, ~~2005~~2007 and approximately ~~$327~~$511 million at December 31, 2004. During the year ended December 31, 2005, the liability increased by approximately $142 million. This net increase reflects a $131 million increase attributable to a revised remediation estimate for the Topock gas compressor station and a $24 million increase attributable to a revised remediation estimate for the Hinkley gas compressor station. These increases, in addition to other increases in liability, were offset by remediation payments.2006. The approximately $469 million accrued at December 31, 2005, includes approximately $193 million for remediation at these gas compressor sites, approximately $100 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $176 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $469 million environmental remediation liability, approximately $141 million has been included in prior rate-setting proceedings and the Utility expects that an additional approximately $259 million will be allowable for inclusion in future

rates in accordance with the ratemaking mechanism described above. 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. The Utility'sUtility’s undiscounted future costs could increase to as much as ~~$680~~$834 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. ~~The amount~~

For more information about environmental remediation liabilities, see Note 17 of ~~approximately $680 million does not include an estimate for~~ the ~~cost of remediation at known sites owned or operated~~Notes to the Consolidated Financial Statements in the ~~past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.~~2007 Annual Report.

Nuclear Fuel Disposal

~~Under~~ As part of the Nuclear Waste Policy Act of 1982, ~~or Nuclear Waste Act,~~Congress authorized the DOE ~~is responsible for~~and electric utilities with commercial nuclear power plants to enter into contracts under which the ~~transportation, and permanent storage and disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are~~DOE would be required to ~~provide interim storage facilities until permanent storage facilities are provided by~~dispose of the federal government. The Nuclear Waste Act mandates that one or more permanent disposal sites be in operation by 1998. Consistent with the law, the Utility entered into a contract with the DOE providing for the disposal of theutilities' spent nuclear fuel and high-level radioactive waste ~~from the Utility's nuclear power facilities beginning not~~no later than January ~~1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay~~31, 1998, in ~~identifying a storage site. Then, after~~exchange for fees paid by the utilities. In 1983, the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility'sentered 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 iffailed to develop a permanent storage site by January 31, 1998. The Utility believes that the ~~DOE completes a storage facility by 2010, the earliest Diablo Canyon's~~existing spent fuel ~~would be accepted~~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 ~~storage or disposal would be 2018.~~Unit 1 and 2011 for Unit 2.

~~On January 22, 2004,~~Because the DOE failed to develop a permanent storage site, the Utility ~~filed separate complaints in~~obtained a permit from the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility's costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE's failure to meet its obligations. The Utility's complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities. Trial is scheduled to begin on June 5, 2006.

~~At the projected level of operation for Diablo Canyon, the Utility's current facilities are able to store on-site all spent fuel produced through approximately 2007. In March 2004, the~~ NRC ~~authorized the Utility~~ to build an on-site dry cask storage facility to store spent fuel through ~~approximately 2021 for Unit 1 and to 2024 for Unit 2. Several interveners~~at least 2024. After various parties appealed the ~~NRC's decision to~~NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit ~~or Ninth Circuit. The Ninth Circuit heard oral argument~~issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the ~~appeal~~potential environmental consequences in ~~October 2005,~~the event of a 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. On January 15, 2008, the NRC decided to hold hearings on whether it provided a complete list of the references upon which it relied to find that there would not be a significant environmental impact and ~~a decision is pending. PG&E Corporation~~whether it sufficiently addressed the impacts on land and the ~~Utility cannot predict the outcome~~local economy of ~~this appeal.~~

~~In April 2004, San Luis Obispo County (the California county where Diablo Canyon~~a potential terrorist attack. It is located) issued a permit under the California Coastal Act, subject to a number of conditions. The Utility, along with several other interested parties, filed appeals of the County's decision with the California Coastal Commission. The Utility's appeal challenged one of the conditions pertaining to the granting of public access to the coast and other portions of the Utility's property surrounding Diablo Canyon. On December 8, 2004, the California Coastal Commission granted the Utility's application for a coastal development permit authorizing it to proceed with its planned construction of an on-site dry cask storage facility. The Commission granted the Utility's appeal, denied the appeals of other parties and conducted a de novo review of the application. The Commission's December 8, 2004 decision requiresexpected that the ~~Utility provide expanded public access to the coast and other lands surrounding Diablo Canyon, although such public access is less expansive than the County had originally required and~~NRC will ~~be subject to~~issue a ~~one-year study process. Construction of the on-site dry cask storage facility began~~final decision in the third quarter ~~2005 and is expected to be completed by~~of 2008.

~~To provide another storage alternative in the event construction of~~The Utility expects to complete the dry cask storage facility ~~is delayed, in November 2005 the NRC authorized the Utility to install a temporary storage rack in each unit's existing~~and begin loading spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. The Utility anticipates that it would complete the installation of the temporary storage racks by December 2006. This temporary option does not require local or California Coastal Commission permits to be obtained.in 2008. If the Utility is unable to complete the dry cask storage facility, or if ~~construction~~operation of the facility is delayed beyond 2010, ~~and~~or if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and continued until such time as additional safe storage for spent fuel ~~can be safely stored.~~

is made available.

~~In July 1988,~~The Utility and other nuclear power plant owners have sued the ~~NRC gave the~~DOE for breach of contract. The Utility ~~final approval~~seeks to ~~store radioactive waste from the Utility's retired nuclear generating facility,~~recover its costs to develop on-site storage at Diablo Canyon and Humboldt Bay Unit ~~3, at~~3. In October 2006, the ~~plant until 2015 before ultimately decommissioning~~U.S. Court of Federal Claims found the ~~unit.~~DOE had breached its contract and awarded the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004. The Utility ~~has agreed~~appealed to ~~remove all spent fuel when~~ the ~~federal disposal site is available. In 1988,~~U.S. Court of Appeals for the Federal Circuit seeking to increase the amount of the award and challenged the U.S. Court of Federal Claims’ finding that the Utility ~~completed~~would have incurred some of the ~~first step~~costs for the on-site storage facilities even if the DOE had complied with the contract. A decision on the appeal is expected by the end of 2008. The Utility will seek to recover costs incurred after 2004 in future lawsuits against the DOE. Any 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 this appeal or the amount of any additional awards the Utility may receive. If the U.S. Court of Federal Claims’ decision is not overturned or modified on appeal, it is likely that the Utility will be unable to recover all of its future costs for on-site storage facilities from the DOE. However, reasonably incurred costs related to the on-site storage facilities are, in the ~~decommissioning~~case of Diablo Canyon, recoverable through rates and, in the case of Humboldt Bay Unit 3, and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.recoverable through its decommissioning trust fund.

Nuclear Decommissioning

In June 2004, the Utility reported to the NRC that the Utility was unable to account for all of the used fuel segments from Humboldt Bay Unit 3 that the Utility's records indicate were sent to storage, and that the Utility was evaluating whether the used fuel was placed in the storage pool. On August 19, 2005, the NRC issued an inspection report concluding that the Utility was unable to account for the location of three 18-inch segments of used nuclear fuel. The NRC issued its report after the Utility filed its final report in May 2005 updating the NRC as to the Utility's efforts to locate the used fuel. The Utility's ~~report concludes that it is very likely that these pieces were shipped to a low-level radioactive waste facility. In its August 19, 2005 report,~~nuclear power facilities consist of two units at Diablo Canyon and the NRC determined that the Utility's inability to conclusively locate the used fuel did not pose any threat to the health and safety of the public. In December 2005, the NRC issued a notice of violation to the Utility and imposed a penalty of $96,000 on the Utility for failure to control its inventory and to keep adequate records of these materials. The Utility did not contest the finding of a violation and paid the penalty in January 2006.

~~The Utility has received a license from the NRC to build an on-site dry cask storage~~retired facility at Humboldt Bay Unit 3. The Utility also has received approval from the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to the dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that construction of the dry cask storage facility can be completed in time for decommissioning of Humboldt Bay Unit 3 to begin in 2009.

~~Nuclear Decommissioning~~

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 NRC license and release of the property for unrestricted use. ~~For ratemaking purposes,~~The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding (“NDCTP”), used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 iswould be scheduled to begin in ~~2021~~2024 and to be completed in ~~2040. Decommissioning~~2044; that decommissioning of Diablo Canyon Unit 2 iswould be scheduled to begin in 2025 and to be completed in ~~2041,~~2041; and that decommissioning of Humboldt Bay Unit 3 iswould be scheduled to begin in 2009 and to be completed in 2015.

~~As presented in the~~ The Utility’s ~~Nuclear Decommissioning Costs Triennial Proceeding, or NDCTP, pending at the CPUC, the estimated nuclear~~ decommissioning cost ~~for the Diablo Canyon Units 1 and 2 and Humboldt Bay Unit 3 is approximately $2.03 billion in 2005 dollars (or approximately $5.12 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 are recovered from customers through a non-bypassable charge that 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 nuclear decommissioning cost estimate described above is used for regulatory purposes. Under generally accepted accounted principles, or GAAP, requirements, the decommissioning cost estimate is calculated using a different method. In accordance with Statement of Financial Accounting Standards No. 143, the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. The Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. Decommissioning costs are recorded as a component of depreciation expense, with a corresponding credit to the asset retirement costs regulatory liability. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.3 billion at December 31, 2005 and $1.2 billion at December 31, 2004. The primary difference between the Utility'srecovers its revenue requirements for estimated nuclear decommissioning ~~obligation as recorded in accordance with GAAP and~~costs from customers through a non-bypassable charge that the ~~estimate prepared in accordance with the CPUC requirements is that GAAP incorporates various potential settlement dates for the obligation and includes an estimated amount for third-party labor~~Utility expects will continue until those costs ~~into the fair value calculation.~~

are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for

decommissioning and dismantling the Utility's nuclear facilities. 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. These payments cannot exceed the amount collected from customers through the decommissioning charge. 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, 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.

As authorized in the 2002 NDCTP, in 2005, the Utility was authorized to collect approximately $18.4 million in rates and contributed approximately $18.4 million to the qualified nuclear decommissioning trust for Humboldt Bay Unit 3. For 2006, the Utility is authorized to collect approximately $18.4 million in rates for decommissioning Humboldt Bay Unit 3. The Utility expects to contribute that entire amount to the qualified trusts for Humboldt Bay Unit 3. The Utility has received approval from the IRS to contribute all of the collected amounts to the qualified trust for Humboldt Bay Unit 3 for 2005. The Utility expects to file a ruling request with the IRS in the first quarter of 2006 for contributions made in 2006. The CPUC issued a decision in the 2002 NDCTP finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the eventual decommissioning. Therefore, no contributions were made to the Diablo Canyon trusts in 2005 and no contributions are expected for 2006.

On November 10, 2005, the Utility filed its 2005 NDCTP, seeking approval for its proposed nuclear decommissioning revenue requirements for the years 2007-2009. The Utility’s 2005 NDCTP seeks recovery of $9.5 million in revenue requirements relating to the qualified trust for Diablo Canyon and $14.6 million in revenue requirements relating to the qualified trust for Humboldt Bay Unit 3. The Utility expects to begin evidentiary hearings with the CPUC in May 2006 and expects a decision in October 2006.

For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the ~~2005~~2007 Annual Report.

~~Compressor Station Litigation~~

Several lawsuits have been filed against the Utility seeking damages from alleged chromium contamination at the Utility's Hinkley, Topock and Kettleman natural gas compressor stations. See “Item 3. Legal Proceedings,” below for a description of the pending litigation.

Electric and Magnetic Fields

Electric and magnetic fields ~~or EMFs,~~(“EMFs”) naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.

In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. As part of the Utility's effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.

In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from ~~EMFs, to the CPUC and the public.~~EMFs. The report's conclusions contrast with other

recent reports by authoritative health agencies in that the California Department of Health Services' report has assigned a higher probability to the possibility ~~that there is~~of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

On January 26, 2006, the CPUC issued a decision which affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to ~~mitigate~~reduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF ~~mitigation. In addition, the CPUC (1) adopted rules and policies to improve~~

utility design guidelines for reducing EMFs, (2) ordered a utility workshop to implement these policies and standardize design guidelines, and (3) established a rule whereby the CPUC will not take EMF testimony in any future proceedings other than issues concerning utilities’ compliance with established CPUC mitigation standards.reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.

The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. ~~The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged~~In a case involving allegations of personal injury, resulting from exposure to EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which the plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, thea California appeals court ~~in this matter~~ held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs, and barred plaintiffs' personal injury claims. ~~Plaintiffs filed an appeal of this decision with the California Supreme Court.~~ The California Supreme Court declined to hear the ~~case.~~plaintiffs’ appeal of this decision.

Item 1A. Risk Factors

~~Item 1A.~~ ~~Risk Factors~~

A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading ~~"Management's Discussion and Analysis of Financial Condition and Results of Operations— Risk~~“Risk Factors” in the ~~2005~~MD&A in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 1B. Unresolved Staff Comments

~~Item 1B.~~ ~~Unresolved Staff Comments~~Not applicable.

~~Not applicable.~~Item 2. Properties

~~Item 2.~~ ~~Properties.~~

The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under ~~"Electricity~~“Electric Utility ~~Operations"~~Operations” and ~~"Gas~~“Natural Gas Utility ~~Operations."~~Operations” above. In total, the Utility occupies ~~8.2~~9.8 million square feet of real property, including ~~7.0~~8.5 million square feet that the Utility owns. Of the ~~8.2~~9.8 million square feet of occupied real property, approximately ~~1.5~~1.7 million square feet represent the Utility's corporate headquarters located in several buildings in San Francisco, California. The Utility leases approximately 120,000 square feet of the approximate ~~1.5~~1.7 million square feet of office space. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental ~~authorities~~

authorities. The Utility currently owns approximately 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council ~~or the Council,~~(“Council”) to oversee the development and implementation of a Land Conservation Plan ~~or LCP,~~(“LCP”) that will articulate the long-term management objectives for the 140,000 acres. The Council is ~~guided~~governed by an 18-member Board of Directors that ~~represent~~represents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed ~~one~~1 out of 18 members of the Board of Directors of the Council. ~~The~~In December 2007, the Council ~~is charged to adopt and present~~adopted the LCP and submitted it to the ~~Utility by April 2007.~~ Utility.

The Utility has accepted the LCP and will ~~then~~ seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP. If the Council is unable to reach consensus on all or part of the LCP, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members before April 2013.

PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2012.

~~Item 3.~~ ~~Legal Proceedings~~.

Item 3. Legal Proceedings

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.

~~Pacific Gas and Electric Company Chapter 11 Filing~~

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California, or Bankruptcy Court. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations.

The Utility's plan of reorganization incorporated the terms of the Settlement Agreement. Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the Bankruptcy Court. The CPUC's waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the Settlement Agreement, the plan of reorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order.

The Settlement Agreement generally terminates nine years after the effective date of the plan of reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the Bankruptcy Court will have jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement, the plan of reorganization and the confirmation order. The Bankruptcy Court retains jurisdiction to resolve remaining disputed claims. The parties also agreed that the Settlement Agreement, the plan of reorganization or any order entered by the Bankruptcy Court contemplated or required to implement the Settlement Agreement or the plan of reorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC.

Two former CPUC commissioners who did not vote to approve the Settlement Agreement filed an appeal of the Bankruptcy Court's confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed their appeal. The former commissioners have appealed the District Court's order to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. The Ninth Circuit heard oral arguments on the appeal on February 13, 2006. It is uncertain when a decision will be issued.

Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed as moot. If the Bankruptcy Court's confirmation order is overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected. PG&E Corporation and the Utility believe the former commissioners' appeal of the confirmation order is without merit and will be rejected.

~~Pacific Gas and Electric Company vs. Michael Peevey, et al.~~

On November 8, 2000, the Utility filed a lawsuit in the District Court against the CPUC commissioners. In this lawsuit, the Utility seeks a declaration that the federally tariffed wholesale electricity costs that the Utility had incurred to serve the Utility's customers are recoverable in retail rates under the federal filed rate doctrine.

Under the Settlement Agreement, the Utility agreed to dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the plan of reorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case as requested by the Utility. Since the appeal brought by two former CPUC commissioners challenging the

~~Bankruptcy Court’s confirmation order incorporating the terms of the Settlement Agreement is still pending in the Ninth Circuit, as discussed above, the Utility has not yet dismissed its complaint.~~

Diablo Canyon Power Plant

The Utility's Diablo Canyon power plant employs a ~~"once-through"~~“once-through” cooling water system that is regulated under a ~~NPDES~~Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board or (“Central Coast ~~Board.~~Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.

In October 2000, the Utility and the Central Coast Board reached a tentative settlement ~~of this matter pursuant to~~under which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the ~~Utility's~~ Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the ~~Central Coast~~tentative settlement, ~~agreement,~~ the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the ~~Central Coast~~ settlement agreement. On June 17, 2003, the ~~Central Coast~~ settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the ~~Central Coast~~ settlement agreement, ~~accepted in March 2003,~~ and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. The California State Water Resources Control Board is developing a state policy for the implementation of Section 316(b) of the Clean Water Act, the adoption of which could affect future negotiations between the Central Coast Board and the Utility. For more information about the draft state policy, see “Environmental Matters—Water Quality” in this report.

~~The~~PG&E Corporation and the Utility ~~believes~~believe that the ultimate outcome of this matter will not have a material adverse impact on ~~the~~their Utility's financial condition or results of operations.

Complaints Filed by the California Attorney General and the City and County of San Francisco

On January 10, 2002, the California Attorney General filed a complaint in the ~~San Francisco~~ Superior Court for the County of San Francisco or (“Superior ~~Court,~~Court”) against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200 or (“Section ~~17200.~~17200”). Among other allegations, the California Attorney General alleged that past transfers of funds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis.

The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, 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. The California Attorney General's complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E

Corporation from the Utility.

On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in the Superior Court. The complaint contains some of the same allegations contained in the California Attorney General's complaint, including allegations of unfair competition in violation of Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation ~~"took~~“took at least

~~$5.2~~ $5.2 billion from the Utility,"” and for unjust enrichment. The City and County of San Francisco ~~or CCSF,~~(“CCSF”) seeks injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties of $2,500 against each defendant for each violation of Section 17200 and costs of suit.

The complaints, which have been consolidated in the Superior Court, were filed after the CPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC would, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties, the failure of the holding companies to financially assist the utilities when needed, the transfer by the holding companies of assets to unregulated subsidiaries, and the holding companies' actions to ~~"ringfence"~~“ringfence” their unregulated subsidiaries. In May 2005, the CPUC closed this investigation without making any findings. ~~Under the Settlement Agreement, the CPUC agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.~~

PG&E Corporation believes that the intercompany transactions challenged by the California Attorney General and CCSF were in full compliance with applicable law and CPUC conditions. The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases. As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends. The CPUC did not challenge or question those payments.

In ~~February and March 2002, PG&E Corporation filed notices~~January 2006, the U.S. Court of ~~removal in~~Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision on the parties’ appeals of various rulings by the Bankruptcy Court ~~to transfer~~and the ~~complaints to~~U.S. District Court for the ~~Bankruptcy Court. Subsequently,~~Northern District of California concerning jurisdictional issues. The Ninth Circuit found that the ~~plaintiffs filed motions to remand their actions to state court. In June 2002, the Bankruptcy~~Superior Court ~~held that federal law preempted~~had jurisdiction over the California Attorney General’s ~~allegations concerning~~and CCSF’s restitution claims. (In October 2006, the U.S. Supreme Court declined to grant PG&E Corporation’s ~~participation in~~request to review the ~~Utility’s bankruptcy proceedings.~~Ninth Circuit’s decision.) The Bankruptcy Court directed the California Attorney General to file an amended complaint omitting certain of his Section 17200 allegations and remanded the amended complaint to the Superior Court. The Bankruptcy Court retained jurisdiction over CCSF’s causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by CCSF, but remanded CCSF’s Section 17200 cause of action to state court. In both cases, the parties appealed the Bankruptcy Court’s remand order to the District Court. In August 2002, the California Attorney General filed its amended complaint in the Superior Court. The Superior Court has coordinatedNinth Circuit did not address the California Attorney General’s ~~case with~~and CCSF’s underlying allegations that PG&E Corporation and the ~~case filed by CCSF.~~

~~On October 8, 2003,~~other defendants violated Section 17200. The Ninth Circuit also did not decide the ~~District Court reversed, in part,~~issue of who would be entitled to receive the ~~Bankruptcy Court’s June 2002 decision~~proceeds, if any, of a restitution award, and ~~ordered~~PG&E Corporation continues to believe that ~~the plaintiffs’ restitution claims under Section 17200~~any such proceeds would be ~~sent to the Bankruptcy Court. The District Court found that these claims, estimated by plaintiffs to be approximately $5 billion, are~~ the property of the ~~Utility’s~~Utility. Pursuant to the Chapter 11 ~~estate and are therefore properly within~~Settlement Agreement, the ~~Bankruptcy Court’s jurisdiction. The District Court also affirmed,~~CPUC released all claims against PG&E Corporation or the Utility arising out of or in part, the Bankruptcy Court’s June 2002 decision and found that the plaintiffs’ civil penalty and injunctive relief claims under Section 17200 could be resolved in Superior Court. The California Attorney General and CCSF appealed the District Court’s remand orderany way related to the ~~Ninth Circuit.~~energy crisis, including the CPUC’s investigation into past PG&E Corporation actions during the California energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.

While the Ninth Circuit appeal was pending, the Superior Court held a trial in December 2004 to consider the appropriate standard to determine what constitutes a separate violation of Section 17200 in order to determine the magnitude of potential penalties under Section 17200 (up to $2,500 per separate “violation”). The Superior Court did not address the question of whether any violations occurred. In March 2005, the Superior Court issued a decision rejecting the “per victim” and “per [customer] bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate “violations.” The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200. In July ~~27,~~ 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision.

On January 10, 2006, a three-judge panel of the Ninth Circuit issued a 2-1 decision reversing the District Court’s October 2003 order regarding which court had jurisdiction of the California Attorney General’s and CCSF’s restitution claims. The Ninth Circuit ruled that the plaintiffs’ restitution claims constituted actions to enforce their police or regulatory power, actions which are exempt from the provisions of the Bankruptcy Code permitting removal of state actions to Bankruptcy Court. The Ninth Circuit remanded the restitution claims back to thenext case management conference in Superior ~~Court. PG&E Corporation has filed a request for rehearing en banc with the Ninth Circuit.~~

The Ninth Circuit did not address the California Attorney General’s and CCSF’s underlying allegations that PG&E Corporation and the other defendants violated Section 17200. The Ninth Circuit also did not decide the issue of who would

be entitled to receive the proceeds, if any, of a restitution award, and PG&E Corporation continues to believe that any such proceeds would be the property of the Utility. The Settlement Agreement provides that all claims by the CPUC against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis are released, including the CPUC’s investigation into past PG&E Corporation actions during the energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.Court is scheduled on May 13, 2008.

PG&E Corporation believes that the California Attorney General’s and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation.PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.

~~Compressor Station Chromium Litigation~~Solano County District Attorney’s Office

~~The following 12~~In a letter dated July 11, 2007, the Solano County District Attorney's Office stated its intention to file a civil ~~suits are pending~~complaint against the Utility ~~relating~~for record-keeping violations related to ~~alleged chromium contamination: (1)~~ ~~Aguayo v. Pacific Gas and Electric Company~~~~, filed March 15, 1995,~~an underground storage tank at the Utility’s service center in ~~the Superior Court for the County of Los Angeles or Los Angeles County Superior Court, (2)~~ ~~Aguilar v. Pacific Gas and Electric Company~~~~, filed October 4, 1996, in Los Angeles County Superior Court, (3)~~ ~~Acosta, et al. v. Betz Laboratories, Inc., et al.~~~~, filed November 27, 1996, in Los Angeles County Superior Court, (4)~~ ~~Adams v. Pacific Gas and Electric Company and Betz Chemical Company~~~~, filed July 25, 2000, in Los Angeles County Superior Court, (5)~~ ~~Baldonado v. Pacific Gas and Electric Company~~~~, filed October 25, 2000, in Los Angeles County Superior Court, (6)~~ ~~Gale v. Pacific Gas and Electric Company~~~~, filed January 30, 2001, in Los Angeles County Superior Court,~~ ~~Puckett v. Pacific Gas and Electric Company~~~~, filed March 30, 2001, in Los Angeles County Superior Court, (9)~~ ~~Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al.~~~~, filed April 11, 2001, in Los Angeles County Superior Court, (10)~~ ~~Bowers, et al. v. Pacific Gas and Electric Company, et al.~~~~, filed April 20, 2001, in Los Angeles County Superior Court, (11)~~ ~~Boyd, et al. v. Pacific Gas and Electric Company, et al.~~~~, filed May 2, 2001, in Los Angeles County Superior Court, (12)~~ ~~Martinez, et al. v. Pacific Gas and Electric Company~~~~, filed June 29, 2001, in San Bernardino County Superior Court and (13)~~ ~~Miller v. Pacific Gas and Electric Company~~~~, filed November 21, 2001, in Los Angeles County Superior Court.~~

All of these civil actions, referred to as the Chromium Litigation, are now pending in the Los Angeles County Superior Court, or Superior Court. There are now approximately 1,200 plaintiffs in the Chromium Litigation who seek compensatory damages, more than 1,000 of whom are also seeking punitive damages. Although the plaintiffs’ complaints in the Chromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000Vallejo, California. The letter attached a copy of the ~~current plaintiffs filed claims in the Utility’s Chapter 11 proceeding requesting compensatory damages in an approximate aggregate amount~~draft complaint, which detailed a series of ~~$500 million~~alleged California Health and ~~others filed claims for an "unknown amount." These claims were not discharged when the Utility’s plan~~Safety Code record-keeping violations, some of ~~reorganization became effective.~~

~~In general, plaintiffs~~which date back to 2004. Alleged violations include failing to complete inspections, testing, and ~~claimants allege that exposure~~certifications, and to chromium contamination in the vicinity of the Utility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death or other injuries, and seek related damages.

On February 3, 2006, the Utility entered into a settlement agreement with attorneys for approximately 1,100 plaintiffs in the Chromium Litigation. The following cases are covered by the settlement agreement: ~~Aguayo~~, ~~Aguilar~~, ~~Acosta~~, ~~Baldonado~~, ~~Bowers~~, ~~Boyd~~, ~~Gale~~, ~~Martinez~~, ~~Miller~~ ~~and~~ ~~Puckett~~~~. The Utility has agreed to pay $295 million~~make records available to the ~~settling plaintiffs.~~County. Under the California Health and Safety Code, penalties of up to $5,000 per day for each violation may be assessed. The ~~Utility will deposit the settlement amount into escrow on April 21, 2006. The settling plaintiffs are required~~draft complaint also seeks penalties for unfair and unlawful business practices under California Business and Professions Code Section 17200, under which penalties of up to execute general releases in favor of the Utility, PG&E Corporation, its officers, directors, employees, and other affiliates, as to any and all claims asserted or which could have been asserted in the Chromium Litigation. After receipt of releases from at least 90% of the settling plaintiffs, executed requests for dismissals with prejudice of the settled cases, and documentation evidencing the Superior Court’s approval of the compromises or settlements with the settling plaintiffs who are minors, payments will$2,500 per violation may be released from escrow to plaintiffs’ attorneys for the plaintiffs who have submitted executed releases. If 90% of the settling plaintiffs do not execute releases by September 15, 2006, including a release signed by each of the eighteen plaintiffs scheduled to participate in the first trial, the Utility may, at its option, terminate the settlement agreement. In order to obtain 100% of the settlement funds from escrow, plaintiffs’ attorneys must submit releases from or on behalf of 100% of the settling plaintiffs.

With respect to the unresolved claims, the Utility will continue to pursue appropriate legal defenses, including the statute of limitations and the exclusivity of workers’ compensation and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

assessed. There

3634

are no allegations related to the discharge of any hazardous substances. The Utility is investigating the allegations and has ~~recorded a $314 million reserve in its financial statements~~entered into discussions with ~~respect to~~ the ~~Chromium Litigation. PG&E Corporation and the~~District Attorney. The Utility ~~do not expect~~believes that the ultimate outcome ~~with respect to the remaining unresolved claims will have~~of this matter would not result in a material adverse effect on ~~their~~its financial condition or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

~~Not applicable.~~

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages and positions of PG&E Corporation ~~"executive~~“executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 or (“Exchange ~~Act,~~Act”) at February ~~1, 2006,~~20, 2008, are as follows:

Name	Age	Position

P.Peter A. Darbee	5355	Chairman of the Board, Chief Executive Officer, and President
~~L. H. Everett~~	55	~~Senior Vice President, Communications and Public Affairs~~
~~K.M.~~Kent M. Harvey	4749	Senior Vice President and Chief Risk and Audit Officer
~~R. M. Jackson~~	48	~~Senior Vice President, Human Resources~~
C.Christopher P. Johns	4547	Senior Vice President, Chief Financial Officer, and Treasurer
~~T. B. King~~Nancy E. McFadden	4449	Senior Vice ~~President;~~ President, Public Affairs
William T. Morrow	48	President and Chief Executive Officer, Pacific Gas and Electric Company
R.Hyun Park	46	Senior Vice President and General Counsel
Greg S. Pruett	50	Senior Vice President, Corporate Relations
Rand L. Rosenberg	5254	Senior Vice President, Corporate Strategy and Development
B.John R. ~~Worthington~~Simon	5643	Senior Vice President, ~~and General Counsel~~Human Resources

All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 20, 2008, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.

Name	Position	Period Held Office

P.Peter A. Darbee	Chairman of the Board, Chief Executive Officer, and President	September 19, 2007 to present
	Chairman of the Board and Chief Executive Officer	July 1, 2007 to September 18, 2007
	Chairman of the Board, Chief Executive Officer, and President	January 1, 2006 to ~~present~~June 30, 2007
	Chairman of the Board, Pacific Gas and Electric Company	January 1, 2006 to ~~present~~May 31, 2007
	President and Chief Executive Officer	January 1, 2005 to December 31, 2005
	Senior Vice President and Chief Financial Officer	~~July 9, 2001~~September 20, 1999 to December 31, 2004
	~~Senior Vice President, Chief Financial Officer, and Treasurer~~	~~September 20, 1999 to July 8, 2001~~

~~L. H. Everett~~	~~Senior Vice President, Communications and Public Affairs~~	~~January 9, 2006 to present~~
	~~Senior Vice President and Assistant to the Chief Executive Officer~~	~~January 1, 2005 to January 8, 2006~~
	~~Senior Vice President and Assistant to the Chairman~~	~~August 2, 2004 to December 31, 2004~~
	~~Vice President and Assistant to the Chairman~~	~~June 1, 2001 to August 1, 2004~~
	~~Vice President, Corporate Secretary, and Assistant to the Chairman~~	~~May 1, 2001 to May 31, 2001~~
	~~Vice President and Corporate Secretary~~	~~July 1, 1997 to April 30, 2001~~
	~~Vice President and Corporate Secretary, Pacific Gas and Electric Company~~	~~November 1, 1996 to May 31, 2001~~

K.Kent M. Harvey	Senior Vice President and Chief Risk and Audit Officer	October 1, 2005 to present
	Senior Vice President, - Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company	November 1, 2000 to September 30, 2005
	~~Senior Vice President - Chief Financial Officer, Controller, and Treasurer, Pacific Gas and Electric Company~~	~~January 1, 2000 to October 31, 2000~~

~~R. M. Jackson~~	~~Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company~~	~~August 2, 2004 to present~~
	~~Vice President, Human Resources, PG&E Corporation~~	~~June 1, 2004 to August 1, 2004~~
	~~Vice President, Human Resources, Pacific Gas and Electric Company~~	~~June 1, 1999 to August 1, 2004~~

C.Christopher P. Johns	Senior Vice President, Chief Financial Officer, and Treasurer	October 4, 2005 to present
	Senior Vice President and Treasurer, Pacific Gas and Electric Company	June 1, 2007 to present
	Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company	October 1, 2005 to ~~present~~May 31, 2007
	Senior Vice President, Chief Financial Officer, and Controller	January 1, 2005 to October 3, 2005
	Senior Vice President and Controller	September 19, 2001 to December 31, 2004
	~~Vice President and Controller~~	~~July~~
Nancy E. McFadden	Senior Vice President, Public Affairs	March 1, ~~1997~~2007 to present
	Senior Vice President, Public Affairs, Pacific Gas and Electric Company	June 20, 2007 to present
	Vice President, Governmental Relations, Pacific Gas and Electric Company	September ~~18,~~26, 2005 to February 28, 2007
	Chairperson, California Medical Assistance Commission	November 13, 2003 to November 30, 2005
	Senior Advisor and Deputy Chief of Staff, Office of Governor Gray Davis	May, 2001 to November, 2003


William T. ~~B. King~~	~~Senior Vice President, PG&E Corporation~~	~~January 1, 2006 to present~~
Morrow	President and Chief Executive Officer, Pacific Gas and Electric Company	~~January~~July 1, ~~2006~~2007 to present
	~~Executive Vice~~ President and Chief Operating Officer, Pacific Gas and Electric Company	August 1, 2006 to June 30, 2007
	Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company)	May 1, 2006 to July 31, 2006
	President, Vodafone KK, Japan	April 1, 2005 to ~~December~~April 30, 2006
	Chief Executive Officer, Vodafone UK, Ltd.	February 1, 2004 to March 31, 2005
	~~Executive Vice~~ President, ~~and Chief of Utility Operations, Pacific Gas and Electric Company~~	~~August 2, 2004 to June 30, 2005~~
	~~Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric Company~~	~~November 1, 2003 to August 1, 2004~~
	~~Senior Vice President, PG&E Corporation~~	~~January 1, 1999 to October 31, 2003~~
	~~President, PG&E National Energy Group,~~Japan Telecom Holdings Co., Inc.	~~November 15, 2002~~December 21, 2001 to ~~July 8, 2003~~
	~~President and Chief Operating Officer, PG&E Gas Transmission Corporation~~	~~August 27, 2002 to July 8, 2003~~
	~~President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc.~~	~~August 9, 2002 to November 14, 2002~~
	~~President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.~~	~~July 1, 2000 to August 8, 2002~~
	~~President and Chief Operating Officer, PG&E Gas Transmission Corporation~~	~~November 23, 1998 to September 10, 2002~~January 31, 2004

R.Hyun Park	Senior Vice President and General Counsel	November 13, 2006 to present
	Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)	April 5, 2005 to October 17, 2006
	Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.	March 2000 to February 2005

Greg S. Pruett	Senior Vice President, Corporate Relations	November 1, 2007 to present
	Vice President, Corporate Relations	March 1, 2007 to October 31, 2007
	Vice President, Communications and Marketing, American Gas Association	April 10, 2006 to February 23, 2007
	Chief Public Affairs Officer, Bechtel National, Inc.	June 12, 2004 to September 12, 2005
	Vice President, Corporate Communications, PG&E Corporation	January 1, 1998 to September 12, 2003

Rand L. Rosenberg	Senior Vice President, Corporate Strategy and Development	November 1, 2005 to present
	Executive Vice President and Chief Financial Officer, Infospace, Inc.	September 2000 to January 20, 2001
	~~Chief Financial Officer and Senior Vice President, Finance and Corporate Development, Infospace, Inc.~~	~~June 2000 to September 2000~~

B.John R. ~~Worthington~~Simon	Senior Vice President, ~~and General Counsel~~Human Resources	~~June 1, 1997~~April 16, 2007 to present
	Senior Vice President, Human Resources, Pacific Gas and Electric Company	April 16, 2007 to present
	Executive Vice President, Global Human Capital, TeleTech Holdings, Inc.	March 21, 2006 to April 13,2007
	Senior Vice President, Human Capital, TeleTech Holdings, Inc.	July 31, 2001 to March 20, 2006

The names, ages and positions of the Utility's ~~"executive~~“executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February ~~1, 2006,~~20, 2008, are as follows:

Name	Age	Position

~~P.A.~~Peter A. Darbee	5355	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
William T. ~~B. King~~Morrow	4448	President and Chief Executive Officer
T.Thomas E. Bottorff	5254	Senior Vice President, Regulatory Relations
~~J. D. Butler~~Helen Burt	5051	Senior Vice President ~~Energy Delivery~~and Chief Customer Officer
~~L.H. Everett~~Christopher P. Johns	5547	Senior Vice President ~~Communications~~ and ~~Public Affairs, PG&E Corporation~~Treasurer
~~R.M. Jackson~~John S. Keenan	4859	Senior Vice President ~~Human Resources~~and Chief Operating Officer
~~C. P. Johns~~Patricia M. Lawicki	4547	Senior Vice President and Chief ~~Financial~~Information Officer ~~and Treasurer~~
~~J. S. Keenan~~Nancy E. McFadden	5749	Senior Vice President, ~~Generation and Chief Nuclear Officer~~Public Affairs
~~S. M. Ramsay~~Hyun Park	47	~~Vice President, Asset Management and Electric Transmission~~
~~F Wan~~	44	~~Vice President, Energy Procurement~~
~~B. R. Worthington~~	5646	Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett	50	Senior Vice President, Corporate Relations, PG&E Corporation
Edward A. Salas	51	Senior Vice President, Engineering and Operations
John R. Simon	43	Senior Vice President, Human Resources
Geisha J. Williams	46	Senior Vice President, Energy Delivery
G. Robert Powell	44	Vice President, Chief Financial Officer, and Controller
Fong Wan	46	Vice President, Energy Procurement

All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February ~~1, 2006,~~20,

2008, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

Name	Position	Period Held Office

P.Peter A. Darbee	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation	September 19, 2007 to present
	Chairman of the Board and Chief Executive Officer, PG&E Corporation	January 1, 2006 to September 19, 2007
	Chairman of the Board, Pacific Gas and Electric Company	January 1, 2006 to ~~present~~May 31, 2007
	Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation	January 1, 2006 to ~~present~~June 30, 2006
	President and Chief Executive Officer, PG&E Corporation	January 1, 2005 to December 31, 2005
	Senior Vice President and Chief Financial Officer, PG&E Corporation	July 9, 2001 to December 31, 2004
	~~Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation~~	~~September 20, 1999~~
William T. Morrow	President and Chief Executive Officer	July 1, 2007 to present
	President and Chief Operating Officer	August 1, 2006 June 30, 2007
	Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company)	May 1, 2006 to July 8,31, 2006
	President, Vodafone KK, Japan	April 1, 2005 to April 30, 2006
	Chief Executive Officer, Vodafone UK, Ltd.	February 1, 2004 to March 31, 2005
	President, Japan Telecom Holdings Co., Inc.	December 21, 2001 to January 31, 2004

~~T. B. King~~	~~President and Chief Executive Officer~~	~~January 1, 2006 to present~~
	~~Senior Vice President, PG&E Corporation~~	~~January 1, 2006 to present~~
	~~Executive Vice President and Chief Operating Officer~~	~~July 1, 2005 to December 31, 2005~~
	~~Executive Vice President and Chief of Utility Operations~~	~~August 2, 2004 to June 30, 2005~~
	~~Senior Vice President and Chief of Utility Operations~~	~~November 1, 2003 to August 1, 2004~~
	~~Senior Vice President, PG&E Corporation~~	~~January 1, 1999 to October 31, 2003~~
	~~President, PG&E National Energy Group, Inc.~~	~~November 15, 2002 to July 8, 2003~~
	~~President and Chief Operating Officer, PG&E Gas Transmission Corporation~~	~~August 27, 2002 to July 8, 2003~~
	~~President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc.~~	~~August 9, 2002 to November 14, 2002~~
	~~President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.~~	~~July 1, 2000 to August 8, 2002~~
	~~President and Chief Operating Officer, PG&E Gas Transmission Corporation~~	~~November 23, 1998 to September 10, 2002~~

T.Thomas E. Bottorff	Senior Vice President, Regulatory Relations	October 14, 2005 to present
	Senior Vice President, Customer Service and Revenue	March 1, 2004 to October 13, 2005
	Vice President, Customer Service	June 1, 1999 to February 29, 2004

~~J. D. Butler~~	~~Senior Vice President, Energy Delivery~~	~~January 9, 2006 to present~~
	~~Senior Vice President, Transmission and Distribution~~	~~March 1, 2004 to January 8, 2006~~
	~~Vice President, Operations, Maintenance and Construction~~	~~June 12, 2000 to February 29, 2004~~

~~L. H. Everett~~	~~Senior Vice President, Communications and Public Affairs, PG&E Corporation~~	~~January 9, 2006 to present~~
Helen Burt	Senior Vice President and ~~Assistant to the~~ Chief ~~Executive~~Customer Officer ~~PG&E Corporation~~	~~January 1, 2005 to January 8, 2006~~
	~~Senior Vice President and Assistant to the Chairman, PG&E Corporation~~	~~August 2, 2004 to December 31, 2004~~
	~~Vice President and Assistant to the Chairman, PG&E Corporation~~	~~June 1, 2001 to August 1, 2004~~
	~~Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E Corporation~~	~~May 1, 2001 to May 31, 2001~~
	~~Vice President and Corporate Secretary, PG&E Corporation~~	~~July 1, 1997 to April 30, 2001~~
	~~Vice President and Corporate Secretary~~	~~November 1, 1996 to May 31, 2001~~

~~R. M. Jackson~~	~~Senior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation~~	~~August 2, 2004 to present~~
	~~Vice President, Human Resources, PG&E Corporation~~	~~June 1, 2004 to August 1, 2004~~
	~~Vice President, Human Resources~~	~~June 1, 1999 to August 1, 2004~~

~~C. P. Johns~~	~~Senior Vice President, Chief Financial Officer and Treasurer~~	~~October 1, 2005 to present~~
	~~Senior Vice President, Chief Financial Officer and Treasurer, PG&E Corporation~~	~~October 4, 2005 to present~~
	~~Senior Vice President, Chief Financial Officer and Controller, PG&E Corporation~~	~~January 1, 2005 to October 3, 2005~~
	~~Senior Vice President and Controller, PG&E Corporation~~	~~September 19, 2001 to December 31, 2004~~
	~~Vice President and Controller, PG&E Corporation~~	~~July 1, 1997 to September 18, 2001~~

~~J. S. Keenan~~	~~Senior Vice President, Generation and Chief Nuclear Officer~~	~~December 19, 2005 to present~~
	~~Vice President, Fossil Generation, Progress Energy~~	~~November 10, 2003 to December 18, 2005~~
	~~Vice President, Brunswick Nuclear Plant, Progress Energy~~	~~May 1, 1998 to November 9, 2003~~

~~S. M. Ramsay~~	~~Vice President, Asset Management and Electric Transmission~~	January 9, 2006 to present
	Vice President, Electric Transmission	July 1, 2005 to January 8, 2006
	Vice President, Distribution Asset Management, American Electric Power	February 1, 2004 to June 30, 2005
	Senior Vice President, Power and Gas, UMS Group, Inc.	October 1, 2001 to January 31, 2004
	~~Managing Director, UK Operations, UMS Group, Inc.~~
Christopher P. Johns	Senior Vice President and Treasurer	June 1, 2007 to present
	Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation	October 4, 2005 to present
	Senior Vice President, Chief Financial Officer, and Treasurer,	October 1, 2005 to May 31, 2007
	Senior Vice President, Chief Financial Officer, and Controller, PG&E Corporation	January 2,1, 2005 to October 3, 2005
	Senior Vice President and Controller, PG&E Corporation	September 19, 2001 to ~~September 30, 2001~~December 31, 2004

F.Patricia M. Lawicki	Senior Vice President and Chief Information Officer	November 1, 2007 to present
	Vice President and Chief Information Officer	January 12, 2005 to October 31, 2007
	Vice President, Chief Information Officer, NiSource, Inc.	April 23, 2003 to January 7, 2005

John S. Keenan	Senior Vice President and Chief Operating Officer	January 1, 2008 to present
	Senior Vice President, Generation and Chief Nuclear Officer	December 19, 2005 to December 31, 2007
	Vice President, Fossil Generation, Progress Energy	November 10, 2003 to December 18, 2005
	Vice President, Brunswick Nuclear Plant, Progress Energy	May 1, 1998 to November 9, 2003

Nancy E. McFadden	Senior Vice President, Public Affairs	June 20, 2007 to present
	Senior Vice President, Public Affairs, PG&E Corporation	March 1, 2007 to present
	Vice President, Governmental Relations	September 26, 2005 to February 28, 2007
	Chairperson, California Medical Assistance Commission	November 13, 2003 to November 30, 2005
	Senior Advisor and Deputy Chief of Staff, Office of Governor Gray Davis	May 2001 to November 2003


Hyun Park	Senior Vice President and General Counsel, PG&E Corporation	November 13, 2006 to present
	Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)	April 5, 2005 to October 17, 2006
	Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.	March 2000 to February 2005

Greg S. Pruett	Senior Vice President, Corporate Relations, PG&E Corporation	November 1, 2007 to present
	Vice President, Corporate Relations, PG&E Corporation	March 1, 2007 to October 31, 2007
	Vice President, Communications and Marketing, American Gas Association	April 10, 2006 to February 23, 2007
	Chief Public Affairs Officer, Bechtel National, Inc.	June 12, 2004 to September 12, 2005
	Vice President, Corporate Communications, PG&E Corporation	January 1, 1998 to September 12, 2003

Edward A. Salas	Senior Vice President, Engineering and Operations	April 11, 2007 to present
	Staff Vice President, Network Planning, Verizon Wireless, Basking Ridge, N.J. Contractor, Verizon Wireless, Local Number Portability Implementation	May 2004 to April 2007 May 2003 to April 2004

John R. Simon	Senior Vice President, Human Resources	April 16, 2007 to present
	Senior Vice President, Human Resources, PG&E Corporation	April 16, 2007 to present
	Executive Vice President, Global Human Capital, TeleTech	March 21, 2006 to April 13, 2007
	Senior Vice President, Human Capital, TeleTech Holdings, Inc.	July 13, 2001 to March 20, 2006

Geisha J. Williams	Senior Vice President, Energy Delivery	December 1, 2007 to present
	Vice President, Power Systems, Distribution, Florida Power and Light Company	July 2003 to July 2007
	Vice President, Distribution Operations, Florida Power and Light Company	February 2002 to July 2003

G. Robert Powell	Vice President, Chief Financial Officer, and Controller	June 1, 2007 to present
	Vice President and Controller	December 21, 2005 to May 31, 2007
	Controller (Interim)	November 9, 2005 to December 20, 2005
	Vice President and Controller, PG&E Corporation	October 4, 2005 to present
	Partner, PricewaterhouseCoopers LLP	July 2002 to September 2005

Fong Wan	Vice President, Energy Procurement	January 9, 2006 to present
	Vice President, Power Contracts and Electric Resource Development	May 1, 2004 to January 8, 2006
	Vice President, Risk Initiatives, PG&E Corporation Support Services, Inc.	November 1, 2000 to April 30, 2004

~~B. R. Worthington~~	~~Senior Vice President and General Counsel, PG&E Corporation~~	~~June 1, 1997 to present~~

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

~~(a)~~As of February ~~1, 2006,~~19, 2008, there were ~~98,083~~88,752 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed ~~principally~~ on the New York Stock ~~Exchange. PG&E Corporation common stock also is listed on the Pacific~~ Exchange and the Swiss stock exchanges. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading ~~"Quarterly~~“Quarterly Consolidated Financial Data (Unaudited)"” in the ~~2005~~2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. The discussion of dividends with respect to PG&E Corporation's common stock ~~is hereby incorporated by reference from "Management's~~set forth under the heading “Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Financial Resources—~~Dividends"~~Dividends” in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of ~~the 2005 Annual Report.~~Exhibit 13 to this report.

~~As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002,~~ PG&E Corporation ~~issued warrants to purchase 5,066,931~~did not repurchase any shares of its common stock of PG&E Corporation at an exercise price of $0.01 per share. On November 17, 2005 and December 29, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase, in the aggregate, 73,559 shares, and received, in the aggregate, 73,538 shares of PG&E Corporation common stock in reliance on the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) of the Act.

~~Pacific Gas and Electric Company did not make any sales of unregistered equity securities~~ during ~~the quarter ended December 31, 2005.~~

~~(b)~~~~Issuer Purchases of Equity Securities~~

~~PG&E Corporation common stock:~~

Period

Total Number of Shares Purchased

Average Price Paid Per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(1)(2)(3)

Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs

October 1 through October 31, 2005 - $ - - $ -
November 1 through November 30, 2005 31,650,300 $ 34.75 31,650,300 $ 500,000,000
December 1 through December 31, 2005 - $ - - $ -
Total
31,650,300 $ 34.75 31,650,300 $ 500,000,000

⁽¹⁾	On September 15, 2004, the PG&E Corporation Board of Directors authorized PG&E Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 14, 2004. The program expired on December 31, 2005.
⁽²⁾	On December 15, 2004, the PG&E Corporation Board of Directors authorized the repurchase of up to $975 million in PG&E Corporation common stock. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors increased the repurchase authorization to $1.05 billion, which was announced in PG&E Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004. PG&E Corporation used all of this authorization to enter into an accelerated share repurchase arrangement on March 4, 2005 with Goldman, Sachs & Co., Inc., or GS&Co, to repurchase 29,489,400 shares at an initial price of $35.60 per share. Under the share forward component of the March 2005 arrangement, certain additional payments were required by both PG&E Corporation and GS&Co upon termination. Most significantly, PG&E Corporation was to receive from, or be required to pay to, GS&Co a price adjustment on the repurchased shares based on the difference between the amount it paid and the daily volume weighted average price, or VWAP, of PG&E Corporation common stock over the approximately six-month intended arrangement period. PG&E Corporation made additional payments to GS&Co of $78,000 on June 30, 2005 and $22 million on September 12, 2005. The amount of the price adjustment based on the VWAP of PG&E Corporation common stock over the term of the arrangement increased the average purchase price per share to $36.19.
⁽³⁾	On October 19, 2005, the PG&E Corporation Board of Directors authorized the repurchase of up to $1.6 billion in shares of PG&E Corporation's common stock, from time to time, but no later than December 31, 2006. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 21, 2005. As described in a Current Report on Form 8-K filed by PG&E Corporation on November 18, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement with GS&Co on November 16, 2005 under which PG&E Corporation repurchased 31,650,300 shares of its outstanding common stock at an initial price of $34.75 per share and an aggregate price of approximately $1.1 billion. As with the March 2005arrangement, PG&E Corporation may receive from, or be required to pay, GS&Co various payments, including a price adjustment based on the daily VWAP of PG&E Corporation common stock over a period of approximately seven months.

~~During the fourth quarter of 2005, Pacific Gas and Electric Company~~2007. The Utility did not redeem or repurchase any shares of its various series of preferred stock ~~outstanding.~~outstanding during of 2007.

Item 6. Selected Financial Data

~~Item 6.~~ ~~Selected Financial Data~~

A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading ~~"Selected~~“Selected Financial ~~Data"~~Data” in the ~~2005~~2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated financial condition and results of operations ~~and financial condition~~ is set forth under the heading ~~"Management's~~“Management's Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” in the ~~2005~~2007 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 7A appears in the ~~2005~~2007 Annual Report under the heading ~~"Management's~~“Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities,"” and under Notes 12 and 12 of the ~~"Notes~~“Notes to the Consolidated Financial ~~Statements"~~Statements” of the ~~2005~~2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 8. Financial Statements and Supplementary Data

Information responding to Item 8 appears in the ~~2005~~2007 Annual Report under the following headings for PG&E Corporation: ~~"Consolidated~~“Consolidated Statements of Income,~~" "Consolidated~~” “Consolidated Balance Sheets,~~" "Consolidated~~” “Consolidated Statements of Cash Flows,"” and ~~"Consolidated~~“Consolidated Statements of Shareholders' Equity;"” under the following headings for Pacific Gas and Electric Company: ~~"Consolidated~~“Consolidated Statements of Income,~~" "Consolidated~~” “Consolidated Balance Sheets,~~" "Consolidated~~” “Consolidated Statements of Cash Flows,"” and ~~"Consolidated~~“Consolidated Statements of Shareholders' Equity;"” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: ~~"Notes~~“Notes to the Consolidated Financial Statements,~~" "Quarterly~~” “Quarterly Consolidated Financial Data (Unaudited),"” and ~~"Report~~“Report of Independent Registered Public Accounting Firm,"” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

~~Not applicable.~~

Item 9A. Controls and Procedures

Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures as of December 31, ~~2005,~~2007, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities ~~and~~ Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized and reported within the time periods specified in the ~~Securities and Exchange Commission~~SEC rules and forms. In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, ~~2005~~2007 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal control over financial reporting.

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management's report, together with the report of the independent registered public accounting firm, appears in ~~their joint 2005~~the 2007 Annual Report ~~to Shareholders~~ under the heading ~~"Management's~~“Management's Report on Internal Control Over Financial ~~Reporting"~~Reporting” and ~~"Report~~“Report of Independent Registered Public Accounting Firm,"” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this ~~report.~~

report.

Item 9B. Other Information

~~Adoption of Golden Parachute Restriction Policy~~Amendment to Bylaws

~~In response to a shareholder proposal that was approved at PG&E Corporation’s 2005 annual meeting of shareholders on~~On February ~~15, 2006,~~20, 2008, the ~~Board~~Boards of Directors of PG&E Corporation orand the Utility amended the respective company’s Bylaws to decrease the authorized number of directors, effective May 14, 2008, to eliminate the vacancy on the Board ~~adopted~~of Directors that will result from the retirement of David A. Coulter as a ~~Golden Parachute Restriction Policy~~director of each company following the companies’ joint annual meeting of shareholders. Under PG&E Corporation’s Bylaws, the authorized number of directors may not be less than 7 or more than 13, but within that ~~became effective on February 15, 2006, subject~~range the Board of Directors may set the exact number of directors by an amendment to ~~existing contractual obligations. This policy requires~~the Bylaws. Under the Utility’s Bylaws, the authorized number of directors may not be less than 9 or more than 17, but within that range the ~~holders~~Board of ~~a majority~~Directors may set the exact number of directors by an amendment to the Bylaws. Effective May 14, 2008, PG&E Corporation’s authorized number of directors will decrease from 10 to 9 and the Utility’s authorized number of directors will decrease from 11 to 10. The text of the ~~shares represented~~amendment to PG&E Corporation’s Bylaws is attached to this report as Exhibit 3.4 and ~~voting approve executive severance payments provided~~the text of the amendment to the Utility’s Bylaws is attached to this report as Exhibit 3.7.

Under PG&E Corporation’s and the Utility’s Corporate Governance Guidelines, at least 75% of its Board is required to be composed of independent directors, generally defined as directors who (1) are neither current nor former officers or employees of, nor consultants to, PG&E Corporation, the Utility, or their consolidated subsidiaries, (2) are neither current nor former officers or employees of any other corporation on whose board of directors any officer of the Utility serves as a member, and (3) otherwise meet the definition of “independence” set forth in ~~connection with a change in control~~the stock exchange rules applicable to PG&E Corporation and the Utility. The composition of PG&E Corporation to the extent that those payments exceed 2.99 times the sum of a covered officer’s base salary and target annual bonus. The Golden Parachute Restriction Policy applies generally to the value of cash, special benefits, or perquisites that would be due to the executive following both a change in controlCorporation’s and the ~~termination or constructive termination~~Utility’s Board of ~~an officer covered by~~Directors currently meets the Corporate Governance Guidelines and will continue to do so after May 14, 2008.

2008 Officer Compensation

On February 20, 2008, the Compensation Committee of the PG&E Corporation ~~Officer Severance Policy. It does not apply to~~Board of Directors (“Committee”) approved the value of benefits that would be triggered by a change in control without severance, or to the value of benefits that would be triggered by severance in the absence of a change in control. Under the Golden Parachute Restriction Policy, the Board has delegated to the Nominating, Compensation and Governance Committeespecific performance targets for each component of the ~~Board, or the Committee, full authority to make determinations regarding the interpretation of the provisions of the Golden Parachute Restriction Policy in its sole discretion.~~

~~Amendments to the PG&E Corporation Officer Severance Policy, the 2006 Long-Term Incentive Plan, and the Executive Stock Ownership Program~~

On February 15, 2006, the Board also adopted amendments to the definition of the term “change in control” that appears in the PG&E Corporation Officer Severance Policy, or the Officer Severance Policy, and the PG&E Corporation 2006 Long-Term Incentive Plan, or the 2006 LTIP. The definition of the term “change in control” has been amended so that a “change in control” will occur upon the consummation of a consolidation or merger of PG&E Corporation, other than a merger or consolidation that would result in the voting securities of PG&E Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the combined voting power of PG&E Corporation, such surviving entity, or the parent of such surviving entity outstanding immediately after the merger or consolidation. Under the prior definition, a “change in control” would have occurred upon shareholder approval of such a transaction. Certain other events, including the turnover of two-thirds of the incumbent board members without incumbent board member approval within two years, the acquisition of a 20 percent voting stake in PG&E Corporation, and shareholder approval of certain asset sales or a plan of liquidation or dissolution, will continue to constitute a change in control.

Payments granted pursuant to the Officer Severance Policy became subject to the Golden Parachute Restriction Policy and the new definition of “change in control” effective as of February 15, 2006, subject to existing contractual obligations. The Officer Severance Policy provides that any changes which would reduce the aggregate level of benefits provided under the policy will become effective three years after the covered officers receive notice of those changes. The Golden Parachute Restriction Policy and the amendments to the Officer Severance Policy would reduce the aggregate level of benefits, and therefore will become effective three years after the covered officers receive notice of those changes. PG&E Corporation intends to provide such notice shortly.

The Officer Severance Policy has been further amended to provide that: (i) the term “Participating Employers” is defined to more clearly identify which entities may provide severance benefits to their officers pursuant to the Officer Severance Policy and (ii) upon severance related to a change in control, benefits conditioned upon continued future employment will accelerate in full. These amendments became effective on February 15, 2006.

The 2006 LTIP also has been amended such that a change in control by itself will not generally result in the accelerated vesting or settling of grants under the 2006 LTIP. Accelerated vesting or settling will occur upon a change in control only if (1) the successor or surviving company does not assume or continue the grants in a manner that preserves the value of the grants or (2) the grant holder is terminated within a set amount of time before or after the change in control. These amendments will take effect starting with grants made in 2007. The 2006 LTIP administrative provisions were amended to clarify that benefits that may be payable upon termination of employment following the sale or other divestiture of a subsidiary will be identical to those provided upon severance. These amendments became effective February 15, 2006.

In addition, the Committee amended the Executive Stock Ownership Program Administrative Guidelines, or the Guidelines, to replace the reference to the current PG&E Corporation Long-Term Incentive Program, which expired on December 31, 2005, with the new 2006 LTIP, which became effective on January 1, 2006. The Guidelines also were amended to be consistent with the amended terms of the 2006 LTIP as described above. These changes became effective February 15, 2006.

~~2006 Short-Term Incentive Plan~~

~~As previously disclosed, the Committee has approved the structure of the 2006~~2008 Short-Term Incentive Plan or(“STIP”). The Committee previously approved the STIP ~~under which officers~~structure and the weighting of each component in December 2007. Officers of PG&E Corporation and the Utility are ~~provided an opportunity~~eligible to receive cash incentives under the STIP based on the extent to which the adopted 2008 performance targets are met. The Committee will continue to retain full discretion as to the determination of final officer STIP payments.

The 2008 STIP structure for officers focuses the annual incentive ~~cash payments. For these officers, corporate~~opportunity on returns to shareholders by emphasizing financial objectives such as earnings from operations. The structure also recognizes the equal importance of improving reliability and customer satisfaction, and employee safety and engagement. Corporate financial performance, as measured by corporate earnings from operations, will account for ~~70 percent~~40% of the ~~award and Utility operational performance, as measured by 11 equally weighted financial, operating, and service measures, will account for 30 percent~~incentive, 20% of the ~~award. At its meeting~~incentive will be based on ~~February 15, 2006,~~the Utility’s success in improving reliability, 20% of the incentive will be based on the Utility’s success in improving customer satisfaction, 10% will be based on the results of an employee opinion survey, and the remaining 10% will be based on achieving safety standards. For 2008, the Committee ~~approved the specific performance scale~~has adopted a mechanism stating that ~~will be used to determine the extent to which the~~if corporate financial ~~objective, as measured by~~performance does not exceed 98% of the budgeted earnings from operations, ~~has been met. The Committee used~~ the ~~same methodology~~aggregate operational metric contribution to ~~establish~~ the ~~performance scale for the corporate financial performance portion~~2008 STIP pool will be capped at 100% of the ~~2006~~operational component target award, or 60% of the total target STIP ~~as was used for the 2005 STIP.~~ award pool.

The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the basis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded.

The Committee also approved the ~~following 2006~~2008 performance targets for each of the ~~11 equally weighted financial, operating, and service~~four other measures ~~that will be used to determine whether~~set forth in the ~~portion~~table below. The 2007 performance results for each of these measures are included for comparative purposes.

2008 STIP Operational Performance Targets(1)

Measure	Relative Weight	2007 Results	2008 Target
Customer Satisfaction and Brand Health Index (Residential & Business)(2)	20%	76.00	77.00
Reliable Energy Delivery Index(3)	20%	1.17	1.0
Employee Survey (Premier) Index(4)	10%	64.3%	66.0%
Occupational Safety and Health Administration (OSHA) Recordable Injury Rate(5)	10%	4.097	3.483

1. As explained above, 40% of the STIP award will be based on ~~the~~ achievement of ~~operational excellence and improved customer service has been met. The 2005 performance results for each measure are included for reference:~~

~~2006 STIP Performance Targets~~corporate earnings from operations targets.

Measure

2005 Results

2006 Target
1.
Customer Satisfaction (Residential & Business) ¹
94.0 96.0
2. Timely bills (% issued within 35 days) 99.38% 99.51%
3. Estimate of Outage Restoration Accuracy 47% 50%
4.
System Average Interruption Duration Index (SAIDI) ²
178.7 166
5.
System Average Interruption Frequency Index (SAIFI) ²
1.344 1.31
6.
Energy Availability (Generation and Procurement) ³

-- ³

-- ³
7.
Telephone Service Level ⁴
75/20 76/20
8. Expense Per Customer $278
$283⁵
9.
Diablo Canyon composite performance index⁶
98.2 98.2
10. Employee survey (Premier) index 64.0% 68.0%
11.
Lost workday case rate⁷
1.04 0.878

1.This measure is based on the JD Power Residential Survey and the JD Power Business Survey combined with equal weighting. The 2006 target assumes the 2006 quartile ranges will be the same as the 2005 quartile ranges. The 2006 target will be adjusted to reflect the revised quartile ranges expected to be available in July 2006.

2.“SAIDI,” or system average interruption duration index, refers to the average outage time over a one-year period. “SAIFI,” or system average interruption frequency index, refers to the average number of sustained outages over a one-year period.

3.The Energy Availability measure combines two separate reliability measures, each equally weighted. One assesses whether Utility-owned generation is available as planned and the other assesses whether the Utility has obtained adequate electric supplies for its customers, as measured by California Independent System Operator alerts. This is a new measure in 2006.

4.~~This refers to the percentage of customer calls to the contact centers that are answered within a specified number of seconds; 75/20 means that 75% of calls are answered within 20 seconds.~~

5. The 2006 target expense per customer amount is based on the approved budget for 2006. The increase of 1.7 percent over the 2005 recorded amount of $278 is comprised of a 3.3 percent increase in expenses, offset by a 1.5 percent increase in customers.

6.~~The composite performance index provides a quantitative indication of plant performance in the areas of nuclear plant safety and reliability and plant efficiency.~~

The Customer Satisfaction and Brand Health Index is the result of a quarterly survey performed by an independent research firm, Research International, and is a combination of a customer satisfaction score, which has a 75% weighting, as well as a brand favorability score (measuring the relative strength of the PG&E brand against a select group of companies), which has a 25% weighting. The customer satisfaction score will measure overall satisfaction with the Utility’s operational performance in delivering its services. The brand favorability score will measure residential, small business and medium business customer perceptions. This index replaces the index used in the 2006 and 2007 STIP structures based on residential and business customer satisfaction indices as reported the J.D. Power Residential Customer Satisfaction Survey and the J.D. Power Business Customer Satisfaction Survey.

7.This measures the number of non-fatal injury and illness cases that (1) satisfy certain federal requirements for recordability, (2) occur in the current year, and (3) result in at least one day away from work. The rate measures how frequently new lost workday cases occur for every 200,000 hours worked, or for approximately every 100 employees.

The Reliable Energy Delivery Index is a composite index score that measures key drivers of reliability, including outage frequency and duration (System Average Interruption Frequency Index (SAIFI), Customer Average Interruption Duration Index (CAIDI)), Execution of Electric-Based Work Units, and Gas Transmission and Distribution Integrity. This index replaces the Business Transformation Index used in the 2007 STIP structure.

The Premier Survey is the primary tool used to measure employee engagement at PG&E Corporation and the Utility. The employee index is designed around 15 key drivers of employee engagement and organizational health. The average overall employee survey index score provides a comprehensive metric that is derived by adding the percent of favorable responses from all 40 core survey items (all of which fall into one of 15 broader topical areas), and then dividing the total sum by 40.

An “OSHA Recordable” is an occupational (job-related) injury or illness that requires medical treatment beyond first aid, or results in work restrictions, death or loss of consciousness. The “OSHA Recordable Rate” is the number of OSHA Recordables for every 200,000 hours worked, or for approximately 100 employees. This metric measures the percentage reduction in the Corporation’s OSHA Recordable rate from the prior year and is used to monitor the effectiveness of the Corporation’s safety programs, which are intended to significantly reduce the number and degree of employee injuries and illnesses.

~~The Chief Executive Officer~~Cash awards under the STIP may range from 30 percent to 100 percent of base salary depending on officer level, with a maximum payout of 200 percent of base salary, as determined by the Committee.

Non-Employee Director Compensation

Also on February 20, 2008, the Boards of Directors of PG&E Corporation ~~has~~and the ~~discretion~~Utility amended each company’s resolution regarding non-employee director compensation to ~~recommend~~clarify and restate the application of the compensation program for non-employee directors in light of (1) the division of the PG&E Corporation Nominating, Compensation, and Governance Committee into two separate committees (the Nominating and Governance Committee and the Compensation Committee), and (2) recent changes to the ~~Committee an additional performance rating~~process for ~~an individual officer. This rating will be determined~~selecting the lead director. The amended resolutions do not change the compensation levels previously authorized by ~~such officer’s efforts~~the Boards of Directors on December 20, 2006. The amended resolutions are effective as of January 1, 2008 and are attached to manage their organization’s respective financial budget. This additional performance rating can modify (up or down) an individual officer’s final STIP award by no more than 15 percent. The Committee will continue to retain full discretionthis report as ~~to the determination of final officer STIP awards.~~

exhibits.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

~~Item 10.~~ ~~Directors and Executive Officers of the Registrant~~

Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included above in a separate item captioned ~~"Executive~~“Executive Officers of the ~~Registrants"~~Registrants” at the end of Part I of this report. Other information responding to Item 10 is included under the heading ~~"Item~~“Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric ~~Company"~~Company” and under the heading ~~"Section~~“Section 16(a) Beneficial Ownership Reporting ~~Compliance"~~Compliance” in the Joint Proxy Statement relating to the ~~2006~~2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on PG&E Corporation's website www.pgecorp.com~~www.pgecorp.com~~, and Pacific Gas and Electric Company's website, www.pge.com~~www.pge.com~~: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation's and Pacific Gas and Electric Company's corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies' Audit Committees and the PG&E Corporation Nominating ~~Compensation,~~ and Governance Committee and Compensation Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Vice President, Corporate Governance and Corporate Secretary of PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.

If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4 business days of the waiver.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2007 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2007 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or the Utility’s Boards of Directors.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyBoard CommitteesAudit Committees” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 11. Executive Compensation

Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under ~~the heading "Compensation of Directors" and under~~

the headings ~~"Summary~~“Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table~~" "Option/SAR Grants in 2005," "Aggregated Option/SAR Exercises in 2005 and Year-End Option/SAR Values," "Long-Term Incentive Program—~~ - 2007,” “Grants of Plan-based Awards in ~~2005," "Retirement~~2007,” “Outstanding Equity Awards at Fiscal Year End - 2007,” “Option Exercises and Stock Vested During 2007,” “Pension Benefits,"” “Non-Qualified Deferred Compensation,” “Compensation of Directors,” and ~~"Employment Contracts,~~“Potential Payments Upon Resignation, Retirement, Termination, ~~of Employment, and~~ Change Inin Control, ~~Provisions"~~Death, or Disability” in the Joint Proxy Statement relating to the ~~2006~~2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading ~~"Security~~“Security Ownership of ~~Management"~~Management” and under the heading ~~"Principal Shareholders"~~“Principal Shareholders” in the Joint Proxy Statement relating to the ~~2006~~2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Equity Compensation Plan Information

The following table provides information as of December 31, ~~2005~~2007 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.

Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	(b) Weighted Average Exercise Price of Outstanding Options, Warrants and Rights	(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
Equity compensation plans approved by shareholders	3,970,661(1)	$24.00	10,847,999(2)
Equity compensation plans not approved by shareholders	—	$—	—
Total equity compensation plans	3,970,661(1)	$24.00	10,847,999(2)

(1) Includes 87,989 phantom stock units and restricted stock units. The weighted average exercise price reported in column (b) does not take these awards into account.

(2) Represents the total number of shares available for issuance under the PG&E Corporation's Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2007. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006 authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units and phantom stock payable in an equal number of shares upon termination of employment or service as a director. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

Plan Category

(a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights

(b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights

(c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by shareholders 12,012,774 $23.26 8,952,785(1)
Equity compensation plans not approved by shareholders — $— —
Total equity compensation plans 12,012,774 $23.26 8,952,785

(1) Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program, or LTIP, as of December 31, 2005. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. The LTIP expired on December 31, 2005. The PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, became effective on January 1, 2006. The 2006 LTIP authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the ~~heading "Certain Relationships~~headings “Related Person Transactions,” “Review, Approval, and Ratification of Related ~~Transactions"~~Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyDirector Independence” in the Joint Proxy Statement relating to the ~~2006~~2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 14. Principal Accountant Fees and Services

Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading ~~"Information~~“Information Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric ~~Company"~~Company” in the Joint Proxy Statement relating to the ~~2006~~2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

PART IV

~~PART IV~~

Item 15. Exhibits and Financial Statement Schedules

(a)The following documents are filed as a part of this report:

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the ~~2005~~2007 Annual Report and are incorporated by reference in this report:

Consolidated Statements of Income for the Years Ended December 31, ~~2005, 2004,~~2007, 2006, and ~~2003,~~2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, ~~2005,~~2007 and ~~2004~~2006 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Shareholders' Equity for the Years Ended December 31, ~~2005, 2004,~~2007, 2006, and ~~2003,~~2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2.The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:

Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

I—Condensed Financial Information of Parent as of December 31, ~~2005~~2007 and ~~2004~~2006 and for the Years Ended December 31, ~~2005, 2004,~~2007, 2006, and ~~2003.~~2005.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, ~~2005, 2004,~~2007, 2006, and ~~2003.~~2005.

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

3.Exhibits required by Item 601 of Regulation S-K:

Exhibit Number	Exhibit Description
2.1	Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2	Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1	Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2	Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3	Bylaws of PG&E Corporation amended as of ~~January 1, 2006~~September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4	Text of the amendment to the Bylaws of PG&E Corporation effective May 14, 2008
3.5	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
~~3.5~~3.6	Bylaws of Pacific Gas and Electric Company amended as of January 1, ~~2006~~2008
3.7	Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3	Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4	Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
~~4.3~~4.5	Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
~~4.4~~	Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1	Amended and Restated Unsecured Revolving Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
~~10.2~~	~~First Amendment, dated as of November 30, 2005, to the Credit Agreement~~entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan ~~Chase Bank, N.A.~~Securities Inc., as syndication agent, ~~and a lender,~~ Barclays Bank ~~PLC~~Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and ~~the following~~ other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation.
~~10.3~~	~~Credit Agreement,~~lenders, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New YorkFebruary 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form ~~8-K filed December 15, 2004~~10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit ~~99)~~10.2)


45


~~10.4~~10.2	~~First Amendment, dated as of April 8, 2005, to the~~Amended and Restated Unsecured Revolving Credit Agreement ~~dated as of December 10, 2004,~~entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ~~and a lender,~~ ABN ~~Amro~~AMRO Bank, N.V., ~~Goldman Sachs Credit Partners L.P.~~Bank of America, N.A., and ~~Union~~Barclays Bank ~~of California, N.A.,~~Plc, as documentation agents and lenders, and ~~the following~~ other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New Yorklenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q ~~filed May 4, 2005~~for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
~~10.5~~	~~Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.~~
~~10.6~~10.3	Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
~~10.7~~	Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
~~10.8~~	Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
~~10.9~~	PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
~~10.10~~10.4	Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
~~10.11~~10.5	Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*~~10.12~~10.6	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)

46


*~~10.13~~10.7	PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*~~10.14~~	Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.1510.8	Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*~~10.16~~10.9	~~Letter regarding Compensation Arrangement~~Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10	Retention Agreement between PG&E Corporation and Thomas B. King dated ~~November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December~~August 31, ~~2000 (File No. 1-12609), Exhibit 10.6)~~
*10.17	~~Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003~~2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, ~~2003~~2006 (File No. 1-12609), Exhibit ~~10.3)~~10.2)
*~~10.18~~10.11	Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13	Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.15	Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005
*10.19	Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-2348), Exhibit 10.1)
*10.20	~~Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005, regarding the 2006 Officer Compensation Program~~ (incorporated by reference to PG&E Corporation’s ~~Quarterly Report on~~ Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~September 30, 2005~~December 31, 2005) (File No. 1-12609), Exhibit ~~10.2)~~10.18)
*~~10.21~~10.16	Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)

*10.17	Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated August 8, 2005
*10.18	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.17)
*~~10.22~~10.19	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, ~~2006~~2008
*~~10.23~~10.20	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, ~~2005~~2007 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit ~~10.18)~~10.20)
*~~10.24~~	~~Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries~~
*10.25	~~Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries~~
*10.2610.21	Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004) (File No. 1-2348), Exhibit 10.20)
*~~10.27~~10.22	Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006
*10.28.1	~~Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002~~ (incorporated by reference to PG&E ~~Corporation's~~Corporation’s Form 10-K for the year ended December 31, ~~2002~~2005) (File ~~No. 1-12609), Exhibit 10.37.1)~~
*10.28.2	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
*10.28.3	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit ~~10.37.3)~~10.27)
*~~10.28.4~~	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
*10.29.1	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1)

47


*10.29.2	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2)
*10.29.3	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4)
*10.29.4	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5)
*10.3010.23	Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*~~10.31~~10.24	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*~~10.32~~10.25	PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*~~10.33~~10.26	Resolution of the PG&E Corporation Board of Directors dated ~~June 16, 2004,~~December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~June 30, 2004~~December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit ~~10.1)~~10.29)
*~~10.34~~10.27	Resolution of the Pacific Gas and Electric Company Board of Directors dated ~~June 16, 2004,~~December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~June 30, 2004~~December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit ~~10.2)~~ 10.30)
*~~10.35~~10.28	Resolution of the PG&E Corporation Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.29	Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.30	PG&E Corporation 2006 Long-Term Incentive Plan, ~~effective as of January 1, 2006,~~ as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 and October 17, 2007 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*~~10.36~~10.31	PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*~~10.37~~10.32	Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)

*~~10.38~~10.33	Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*~~10.39~~10.34	Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*~~10.40~~10.35	Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*~~10.41~~10.36	Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.37	Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*~~10.42~~10.38	Form of Performance Share Award Agreement for 2004 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*~~10.43~~10.39	Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*~~10.44~~10.40	Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.41
48

Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*~~10.45~~10.42	PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit ~~10. 2)~~10.2)
*~~10.46~~10.43	PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.46)
*~~10.47~~10.44	PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*~~10.48~~10.45	PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*~~10.49~~10.46	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*~~10.50~~10.47	PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*~~10.51~~10.48	PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)

*~~10.52~~10.49	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*~~10.53~~10.50	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
11	Computation of Earnings Per Common Share
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13	The following portions of the ~~2005~~2007 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: ~~"Selected~~“Selected Financial Data,~~" "Management's~~” “Management's Discussion and Analysis of Financial Condition and Results of Operations,"” financial statements of PG&E Corporation entitled ~~"Consolidated~~“Consolidated Statements of Income,~~" "Consolidated~~” “Consolidated Balance Sheets,~~" "Consolidated~~” “Consolidated Statements of Cash Flows,"” and ~~"Consolidated~~“Consolidated Statements of Shareholders' Equity,"” financial statements of Pacific Gas and Electric Company entitled ~~"Consolidated~~“Consolidated Statements of Income,~~" "Consolidated~~” “Consolidated Balance Sheets,~~" "Consolidated~~” “Consolidated Statements of Cash Flows,"” and ~~"Consolidated~~“Consolidated Statements of Shareholders' Equity,~~" "Notes~~” “Notes to the Consolidated Financial Statements,"” and ~~"Quarterly~~“Quarterly Consolidated Financial Data (Unaudited),~~" "Management's~~” “Management's Report on Internal Control Over Financial Reporting,~~" "Report~~” “Report of Independent Registered Public Accounting Firm,"” and ~~"Report~~“Report of Independent Registered Public Accounting Firm."”
21	Subsidiaries of the Registrant
23	Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1	Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2	Powers of Attorney
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*Management contract or compensatory agreement.

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

4948

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, ~~2005~~2007 to be signed on their behalf by the undersigned, thereunto duly authorized.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
By	(Registrant) ~~BRUCE R WORTHINGTON~~ ~~(Bruce R. Worthington, Attorney-in-Fact)~~*PETER A. DARBEE	By	(Registrant) ~~BRUCE R WORTHINGTON~~ ~~(Bruce R. Worthington, Attorney-in-Fact)~~*WILLIAM T. MORROW
By:	Peter A. Darbee Chairman of the Board, Chief Executive Officer and President	By:	William T. Morrow President and Chief Executive Officer
Date:	February ~~17, 2006~~ 22, 2008	Date:	February ~~17, 2006~~ 22, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.

Signature		~~Title~~	Title		Date
A.		Principal Executive Officers
		*PETER A. DARBEE		Chairman of the Board, Chief Executive Officer, President and ~~President~~Director (PG&E Corporation)		February ~~17, 2006~~22, 2008
Peter A. Darbee

*~~THOMAS B. KING~~WILLIAM T. MORROW			President and Chief Executive Officer (Pacific Gas and Electric Company)		February ~~17, 2006~~22, 2008
William T. Morrow

B.		Principal Financial Officers
		*CHRISTOPHER P. JOHNS		Senior Vice President, Chief Financial Officer and Treasurer (PG&E ~~Corporation~~Corporation)		February 22, 2008
Christopher P. Johns
*G. ROBERT POWELL			Vice President, Chief Financial Officer and ~~Pacific~~Controller (Pacific Gas and Electric ~~Company )~~Company)		February ~~17, 2006~~22, 2008
G. Robert Powell
C. Principal Accounting Officer					February 22, 2008
C.	~~Principal Accounting Officers~~
	*G. ROBERT POWELL			Vice President and Controller (PG&E Corporation and ~~Pacific~~(Pacific Gas and Electric Company)		February ~~17, 2006~~22, 2008
G. Robert Powell
D. Directors
*DAVID R. ANDREWS			Director		February 22, 2008
David R. Andrews

D. *LESLIE S. BILLER		~~Directors~~	Director		February 22, 2008
Leslie S. Biller
*DAVID A. COULTER			Director		February 22, 2008
David A. Coulter
*C. LEE COX			Director		February 22, 2008
C. Lee Cox
*MARYELLEN C. HERRINGER			Director		February 22, 2008
Maryellen C. Herringer

*~~DAVID R. ANDREWS~~RICHARD A. MESERVE			Director		February 22, 2008
Richard A. Meserve

*DAVID A. COULTER

*C. LEE COX

*PETER A. DARBEE

*MARYELLEN C. HERRINGER

*THOMAS B. KING

~~(Director of Pacific Gas andElectric Company only)~~


MARY S. METZ BARBARA L. RAMBO *BARRY LAWSON WILLIAMS	~~Directors of PG&E Corporation and~~ ~~Pacific~~	Director	February 22, 2008
Mary S. Metz

*WILLIAM T. MORROW		Director (Pacific Gas and Electric Company ~~except as noted~~ only)	February ~~17, 2006~~22, 2008

William T. Morrow

*ByBARBARA L. RAMBO		~~BRUCE R WORTHINGTON~~ ~~(Bruce R. Worthington, Attorney-in-Fact)~~	Director	February 22, 2008
Barbara L. Rambo

*BARRY LAWSON WILLIAMS			Director	February 22, 2008
Barry Lawson Williams

*By:	HYUN PARK
HYUN PARK, Attorney-in-Fact

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Boards of Directors and Shareholders of

PG&E Corporation and Pacific Gas and Electric Company

We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the ~~“Company”~~"Company") and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, ~~2005~~2007 and ~~2004,~~2006, and for each of the three years in the period ended December 31, ~~2005, management’s assessment of~~2007, and the ~~effectiveness of the Company’s~~Company's and ~~the~~ Utility’s internal control over financial reporting as of December 31, ~~2005, and the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2005,~~2007, and have issued our reports thereon dated February ~~15, 2006;~~21, 2008; such consolidated financial statements and reports are included in your ~~2005~~2007 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the ~~condensed~~consolidated financial statement schedules of the Company and ~~the~~ Utility listed in Item ~~15 (a)~~ 15(a)2. These ~~condensed~~consolidated financial statement schedules are the responsibility of the ~~Company’s~~Company's and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such ~~condensed~~consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

San Francisco, California

February ~~15, 2006~~21, 2008

PG&E CORPORATION

SCHEDULE I --— CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS

(in millions)

	Balance at December 31,						Balance at December 31,
	2005			2004			2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	250		$	183		$	204		$	386
Advances to affiliates		38			22			30			42
Income taxes receivable								46			-
Other current assets		3			3			3			3
Total current assets		291			208			283			431
Equipment		15			15			17			15
Accumulated depreciation		(14	)		(13	)		(15	)		(14	)
Net equipment		1			2			2			1
Investments in subsidiaries		7,401			8,848			8,886			7,959
Other investments		71			31			87			81
Deferred income taxes		127			104			51			132
Other		15			14			9			10
Total Assets	$	7,906		$	9,207		$	9,318		$	8,614
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable—related parties	$	27		$	3
Accounts payable—other		17			15
Current Liabilities:
Accounts payable
Related parties							$	40		$	41
Other								24			18
Long-term debt, classified as current								-			280
Income taxes payable		28			83			-			122
Other		193			53			174			210
Total current liabilities		265			154			238			671
Noncurrent Liabilities:
Long-term debt		280			280			280			-
Income taxes payable								131			-
Other		143			140			116			133
Total noncurrent liabilities		423			420			527			133
Preferred stock		—			—
Common Shareholders' Equity
Common stock		5,827			6,518			6,110			5,877
Common stock held by subsidiary		(718	)		(718	)		(718	)		(718	)
Unearned compensation		(22	)		(26	)
Reinvested earnings		2,139			2,863			3,151			2,670
Accumulated other comprehensive loss		(8	)		(4	)
Accumulated other comprehensive income (loss)								10			(19	)
Total common shareholders' equity		7,218			8,633			8,553			7,810
Total Liabilities and Shareholders' Equity	$	7,906		$	9,207		$	9,318		$	8,614

PG&E CORPORATION

SCHEDULE I --— CONDENSED FINANCIAL INFORMATION OF PARENT --— (Continued)~~(Continued)~~

CONDENSED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year Ended December 31,									Year Ended December 31,
	2005			2004			2003			2007			2006			2005
Administrative service revenue	$	97		$	85		$	101		$	102		$	110		$	97
Equity in earnings of subsidiaries		918			3,959			917			1,006			964			918
Operating expenses		(97	)		(110	)		(133	)		(112	)		(115	)		(97	)
Interest income		9			15			20			15			15			9
Interest expense		(35	)		(132	)		(200	)		(31	)		(30	)		(35	)
Other income (expense)		(17	)		(91	)		2
Other expense											(6	)		(1	)		(17	)
Income before income taxes		875			3,726			707			974			943			875
Income tax benefit		29			94			84			32			48			29
Income from continuing operations		904			3,820			791			1,006			991			904
Gain on disposal of NEGT		13			684			—			--			--			13
Discontinued operations		—			—			(365	)
Cumulative effect of changes in accounting principles		—			—			(6	)
Net income before intercompany eliminations	$	917		$	4,504		$	420		$	1,006		$	991		$	917
Weighted average common shares outstanding		372			398			385
Earnings per common share, basic⁽¹⁾	$	2.40		$	10.80		$	1.04
Earnings per common share, diluted⁽¹⁾	$	2.37		$	10.57		$	1.02
Weighted average common shares outstanding, basic											351			346			372
Weighted average common shares outstanding, diluted											353			349			378
Earnings per common share, basic(1)										$	2.79		$	2.78		$	2.40
Earnings per common share, diluted(1)										$	2.78		$	2.76		$	2.37

(1) PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.

PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.

Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2007 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.

PG&E CORPORATION

SCHEDULE I — – CONDENSED FINANCIAL INFORMATION OF PARENT — – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2007			2006			2005
Cash Flows from Operating Activities:
Net income	$	1,006		$	991		$	917
Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005)		--			--			(13	)
Net income from continuing operations		1,006			991			904
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		1			--			--
Equity in earnings of subsidiaries		(1,006	)		(964	)		(918	)
Deferred taxes		47			2			(23	)
Other		(24	) )		130			86
Net cash provided by operating activities		24			159			49
Cash Flows From Investing Activities:
Capital expenditures		(1	)		(1	)		(1	)
Investment in subsidiaries		(405	)		--			--
Stock repurchase by subsidiary		--			--			1,910
Dividends received from subsidiaries		509			460			445
Other		--			--			(38	)
Net cash provided by investing activities		103			459			2,316
Cash Flows From Financing Activities(2):
Common stock issued		175			131			243
Common stock repurchased		--			(114	)		(2,188	)
Common stock dividends paid		(496	)		(456	)		(334	)
Long-term debt redeemed		--			--			(2	)
Other		12			(43	)		(17	)
Net cash used by financing activities		(309	)		(482	)		(2,298	)
Net change in cash and cash equivalents		(182	)		136			67
Cash and cash equivalents at January 1		386			250			183
Cash and cash equivalents at December 31	$	204		$	$386		$	$250

Year Ended December 31,

2005

2004

2003

Cash Flows from Operating Activities:
Net income $ 917 $ 4,504 $ (420 )
Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005 and income tax expense of $374 million in 2004) (13 ) (684 ) —
Loss from operations of NEGT (net of income tax benefit of $320 million) — — 365
Cumulative effect of changes in accounting principles — — 6
Net income from continuing operations 904 3,820 791
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries (918 ) (3,959 ) (917 )
Deferred taxes (23 ) 27 265
NEGT settlement payment — (30 ) —
Other 86 160 391
Net cash provided by operating activities 49 18 530
Cash Flows From Investing Activities:
Capital expenditures (1 ) — —
Investment in subsidiaries — (28 ) —
Stock repurchase by subsidiary 1,910 — —
Dividends received from subsidiaries 445 — —
Increase in restricted cash — 361 —
Other (38 ) — —
Net cash provided by investing activities 2,316 333 —
Cash Flows From Financing Activities⁽²⁾:

Common stock issued 243 162 166
Common stock repurchased (2,188 ) (350 ) —
Common stock dividends paid (334 ) — —
Long-term debt issued — — 581
Long-term debt redeemed (2 ) (652 ) (787 )
Other (17 ) (1 ) 1
Net cash used by financing activities (2,298 ) (841 ) (39 )
Net change in cash and cash equivalents 67 (490 ) 491
Cash and cash equivalents at January 1 183 673 182
Cash and cash equivalents at December 31 $ 250 $ 183 $ 673
(2) On January 15, 2007, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share. On April 15, July 15, and October 15, 2007, PG&E Corporation paid quarterly common stock dividends of $0.36 per share. Of the total dividend payments made by PG&E Corporation in 2006, approximately $35 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

~~__________________________________~~

On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million. Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

⁽¹⁾	PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31,On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004.
	PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.
	Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2005 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.

⁽²⁾	On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004 and 2003.

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, ~~2005~~ 2007
Or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Title of Each Class		Name of Each Exchange on Which Registered
PG&E Corporation: Common Stock, no par value		New York Stock Exchange ~~and Pacific Exchange~~
Pacific Gas and Electric Company: First Preferred Stock, cumulative, par value $25 per share:		American Stock Exchange ~~and Pacific Exchange~~
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%
Nonredeemable: 6%, 5.50%, 5%

PG&E Corporation	~~Large accelerated filer~~ x	~~Accelerated filer~~ ¨	~~Non-accelerated filer~~ ¨
Pacific Gas and Electric Company
Large accelerated filer x		Large accelerated filer ¨
Accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer ¨		Non-accelerated filer x
Smaller reporting company ¨		Smaller reporting company ¨

PG&E Corporation Common Stock	$~~13,975~~15,962 million
Pacific Gas and Electric Company Common Stock	Wholly owned by PG&E Corporation
Common Stock outstanding as of February ~~10, 2006:~~ 19, 2008:
PG&E Corporation:	~~345,319,971~~355,749,692 (excluding shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company:	Wholly owned by PG&E Corporation

Designated portions of the combined ~~2005~~2007 Annual Report to Shareholders	Part I (Item ~~1, Item~~ 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A)
Designated portions of the Joint Proxy Statement relating to the ~~2006~~2008	Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders

Commission File Number	Exact Name of Registrant as specified in its charter	State or Other Jurisdiction of Incorporation or Organization	IRS Employer Identification Number
1-12609	PG&E CORPORATION	California	94-3234914
1-2348	PACIFIC GAS AND ELECTRIC COMPANY	California	94-0742640

PG&E Corporation	Yes x No o
Pacific Gas and Electric Company	Yes x No ¨

PG&E Corporation	Yes ¨ No x
Pacific Gas and Electric Company	Yes o No x

		Page
	Units of Measurement	iii
PART I
Item 1.	Business	1
	General	1
	Corporate Structure and Business	1
	Corporate and Other Information	1
	Employees	1
	~~Units of Measurement~~	~~iii~~
~~PART I~~
~~Item 1~~.Cautionary Language Regarding Forward Looking Statements	~~Business~~	1
	~~General~~	1
	~~Corporate Structure and Business~~	1
	~~Corporate and Other Information~~	1
	~~Employees~~	1
	~~Forward Looking Statements~~.	1
	~~Electric Utility Operations~~ PG&E Corporation's Regulatory Environment	3
	~~Electricity Distribution Operations~~ Federal Energy Regulation	3
	~~2005 Electricity Deliveries~~ State Energy Regulation	4 3
	~~Electricity Distribution Operating Statistics~~ The Utility's Regulatory Environment	4
	~~Electricity Resources~~ Federal Energy Regulation	4
	State Energy Regulation	5
	~~Owned Generation Facilities~~ Other Regulation	56
	~~DWR Power Purchases~~ Competition	7
	~~Third Party Power Purchase Agreements~~ Competition in the Electricity Industry	7
	Competition in the Natural Gas Industry	8
	~~Other Power Purchase Agreements~~ Ratemaking Mechanisms	910
	~~Electricity Transmission~~ Overview	910
	Electricity and Natural Gas ~~Utility~~Distribution and Electricity Generation Operations	910
	~~2005 Natural Gas Deliveries~~ General Rate Cases	10
	Attrition Rate Adjustments	11
	~~Natural Gas Operating Statistics~~ Cost of Capital Proceedings	11
	~~Natural Gas Supplies~~ Baseline Allowance	11
	Public Purpose and Other Programs	11
	Energy Efficiency Programs	11
	Demand Response Programs	12
	Self-Generation Incentive Program and California Solar Initiative	12
	Low-Income Energy Efficiency Programs and California Alternate Rates for Energy	12
	~~Gas Gathering Facilities~~ClimateSmart™ Program	1213
	Rate Recovery of Costs of New Electricity Generation Resources	13
	Overview	13
	Costs Incurred Under New Power Purchase Agreements	13
	Costs of Utility-Owned Generation Resource Projects	14
	DWR Electricity and DWR Revenue Requirements	14
	Electricity Transmission	14
	Transmission Owner Rate Cases	14
	Natural Gas	15
	The Gas Accord	15
	Biennial Cost Allocation Proceeding	16
	Natural Gas Procurement	16
	Interstate and Canadian Natural Gas Transportation and Storage	16
	Electric Utility Operations	17
	Electricity Resources	17
	Owned Generation Facilities	17
	DWR Power Purchases	18
	Third-Party Power Purchase Agreements	19
	Future Long-Term Generation Resources	19
	Electricity Transmission	19
	Electricity Distribution Operations	20
	2007 Electricity Deliveries	21
	Electricity Distribution Operating Statistics	21
	Natural Gas Utility Operations	22
	2007 Natural Gas Deliveries	23
	Natural Gas Operating Statistics	23

1 Kilowatt (kW)	=	One thousand watts
1 Kilowatt-Hour (kWh)	=	One kilowatt continuously for one hour
1 Megawatt (MW)	=	One thousand kilowatts
1 Megawatt-Hour (MWh)	=	One megawatt continuously for one hour
1 Gigawatt (GW)	=	One million kilowatts
1 Gigawatt-Hour (GWh)	=	One gigawatt continuously for one hour
1 Kilovolt (kV)	=	One thousand volts
1 MVA	=	One megavolt ampere
1 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet
1 Bcf	=	One billion cubic feet
1 MDth	=	One thousand decatherms

·	the Utility’s ability to manage capital expenditures and operating costs within authorized levels and recover costs through rates in a timely manner;

·	the outcome of regulatory proceedings, including pending and future ratemaking proceedings at the CPUC and the FERC;

·	~~How the Utility manages its responsibility to procure electric capacity and energy for its customers;~~
·	~~The~~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 ~~market for its customers;~~markets;

·	~~Weather,~~the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards ~~that affect demand for electricity or natural gas, result in power outages, reduce generating output, disrupt natural gas supply, cause damage to~~on the ~~Utility's assets or generating~~Utility’s facilities ~~cause damage to the~~and operations, ~~or assets of~~its customers, and third parties on which the Utility ~~relies, or subject the Utility to third party claims for damage or injury;~~relies;

·	~~Unanticipated~~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, ~~all of which may affect customer demand for natural gas~~ or ~~electricity;~~other reasons;

·	~~Whether~~operating performance of the ~~Utility is required to cease operations temporarily or permanently at its~~Utility’s Diablo Canyon nuclear ~~power plant because~~generating facilities (“Diablo Canyon”), the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

·	whether the Utility ~~is unable~~can maintain the cost efficiencies it has recognized from its completed initiatives to ~~increase~~improve its ~~on-site spent nuclear fuel storage capacity, find another depositary for spent fuel, or timely complete~~business processes and customer service, improve its performance following the ~~replacement~~October 2007 implementation of new work processes and systems, and identify and successfully implement additional cost-saving measures

·	whether the ~~steam generators, or because~~Utility incurs substantial unanticipated expense to improve the safety and reliability of ~~mechanical breakdown, lack of nuclear fuel, environmental constraints, or for some other reason~~its electric and natural gas distribution systems;

·	whether the ~~risk that~~Utility achieves the CPUC’s energy efficiency targets and recognize any incentives the Utility may ~~be required to purchase electricity from more expensive sources; and~~earn in a timely manner;

·	~~Whether~~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 ~~is able~~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 and/or the Utility to ~~recognize~~ access capital markets and other sources of credit in a timely manner on favorable terms;

·	the ~~anticipated cost benefits~~impact of environmental laws and ~~savings expected to result from its efforts to improve customer service through implementation~~regulations and the costs of ~~specific initiatives to streamline business processes~~compliance and ~~deploy new technology.~~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.

·	~~The outcome of the regulatory proceedings pending at the CPUC and the FERC and the impact of future ratemaking actions by the CPUC and the FERC;~~
·	The impact of the recently enacted Energy Policy Act of 2005 which, among other provisions, repeals the Public Utility Holding Company Act of 1935 making electric utility industry consolidation more likely; expands the FERC’s authority to review proposed mergers; changes the FERC regulatory scheme applicable to qualifying co-generation facilities, or QFs; authorizes the formation of an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards; and modifies certain other aspects of energy regulation and federal tax policies applicable to the Utility;
·	The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity or gas purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent, or for other reasons, resulting in write-offs of regulatory assets;
·	How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's past decisions permitting the establishment of holding companies for the California investor-owned electric utilities and the outcome of the CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates, which may include (1) establishing reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changing the CPUC's affiliate transaction rules;
·	Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, including tariffs related to the Utility’s billing and collection practices, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses, such as has been recommended with respect to the CPUC’s investigation into the Utility’s billing and collection practices; and
·	Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities, including the Utility’s natural gas compressor stations, to comply with existing and future environmental laws, regulations and policies.

·	~~The outcome of pending litigation; and~~
·	~~The timing and resolution of the pending appeal of the bankruptcy court order confirming the Utility's plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code.~~

~~Agricultural and Other Customers~~·	6%
~~Industrial Customers~~	~~18%~~
~~Residential Customers~~	~~36%~~
~~Commercial Customers~~	~~40%~~ the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;

~~Owned generation (nuclear, fossil fuel-fired~~·	the capital requirements of the Utility, as determined to be necessary and ~~hydroelectric facilities)~~	~~40%~~
~~DWR~~	~~27%~~
~~Qualifying Facilities/Renewables~~	~~22%~~
~~Irrigation Districts~~	5%
~~Other Power Purchases~~	6%prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and

Generation Type	County Location	Number of Units	Net Operating Capacity (MW)
Nuclear:
Diablo Canyon	San Luis Obispo	2	2,174
Hydroelectric:
Conventional	16 counties in northern and central California	107	2,684
Helms pumped storage	Fresno	3	1,212
Hydroelectric subtotal		110	3,896
Fossil fuel:
Humboldt Bay(1)	Humboldt	2	105
Hunters Point(2)	San Francisco	2	215
Mobile turbines	Humboldt	2	30
Fossil fuel subtotal		6	350
Total		118	6,420

	2006	2007	2008	2009	2010

Unit 1
Refueling	-	April	-	January	October
Duration (days)	-	35	-	80	35
Startup	-	June	-	April	November
Unit 2
Refueling	April	-	February	October	-
Duration (days)	45	-	80	35	-
Startup	June	-	April	November	-

~~Residential Customers~~	~~28%~~
~~Transport-only Customers (noncore)~~	~~60%~~
~~Commercial Customers~~	~~12%~~

Pipeline	Expiration Date		Quantity MDth per day	Demand Charges for the Year Ended December 31, 2005 (In millions)

TransCanada NOVA Gas Transmission, Ltd.	12/31/2007	^(a)	616	28.0
TransCanada PipeLines Ltd., B.C. System	10/31/2007		607	13.0
Gas Transmission Northwest Corporation	10/31/2007		610	54.8
Transwestern Pipeline Co.	03/31/2007		150	20.5
El Paso Natural Gas Company (b)	Various		202	19.2

·	The decision finds that the Utility's strategy of adding approximately 1,200 MW of capacity and new peaking generation in 2008 and approximately 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.

·	To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:

·	To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:

	Ø	~~procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,~~

	Ø	employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term and operational flexibility) associated with each bid, and

	Ø	employ a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the risk of future greenhouse gas emissions costs to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator).

·	The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ S&P’s method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%.

·	The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by a utility would be eligible for cost-of service ratemaking treatment.

·	Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third-party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility.

·	The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs.

·	The CPUC extended the mandatory rate adjustment mechanism provided under SB 1976 (which otherwise expired on January 1, 2006) to the length of a resource commitment or 10 years, whichever is longer. Under this rate adjustment mechanism, the CPUC has agreed to adjust retail electricity rates or order refunds, as appropriate, when the aggregate over-collections or under-collections exceed 5% of the utility's prior-year electricity procurement revenues, excluding amounts collected for the DWR allocated contracts.

·	With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five years or longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years.

Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(1)(2)(3)		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs

October 1 through October 31, 2005		-	$	-		-	$	-
November 1 through November 30, 2005		31,650,300	$	34.75		31,650,300	$	500,000,000
December 1 through December 31, 2005		-	$	-		-	$	-
Total		31,650,300	$	34.75		31,650,300	$	500,000,000

	Measure	2005 Results	2006 Target
1.	Customer Satisfaction (Residential & Business) ¹	94.0	96.0
2.	Timely bills (% issued within 35 days)	99.38%	99.51%
3.	Estimate of Outage Restoration Accuracy	47%	50%
4.	System Average Interruption Duration Index (SAIDI) ²	178.7	166
5.	System Average Interruption Frequency Index (SAIFI) ²	1.344	1.31
6.	Energy Availability (Generation and Procurement) ³	-- ³	-- ³
7.	Telephone Service Level ⁴	75/20	76/20
8.	Expense Per Customer	$278	$283⁵
9.	Diablo Canyon composite performance index⁶	98.2	98.2
10.	Employee survey (Premier) index	64.0%	68.0%
11.	Lost workday case rate⁷	1.04	0.878

Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	(b) Weighted Average Exercise Price of Outstanding Options, Warrants and Rights	(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
Equity compensation plans approved by shareholders	12,012,774	$23.26	8,952,785(1)
Equity compensation plans not approved by shareholders	—	$—	—
Total equity compensation plans	12,012,774	$23.26	8,952,785

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions⁽³⁾		Balance at End of Period
	(in millions)
Valuation and qualifying accounts deducted from assets:
2005
Allowance for uncollectible accounts⁽¹⁾	$	93	$	21	$	—	$	37	$	77
2004:
Allowance for uncollectible accounts⁽¹⁾⁽²⁾	$	68	$	85	$	—	$	60	$	93
2003:
Allowance for uncollectible accounts⁽¹⁾⁽²⁾	$	59	$	42	$	—	$	33	$	68

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions(3)		Balance at End of Period
(in millions)
Valuation and qualifying accounts deducted from assets:
2007:
Allowance for uncollectible accounts(1)(2)	$	50	$	20	$	-	$	12	$	58
2006:
Allowance for uncollectible accounts(1)(2)	$	77	$	2	$	-	$	29	$	50
2005:
Allowance for uncollectible accounts(1)(2)	$	93	$	21	$	-	$	37	$	77


(1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.”
(2) Allowance for uncollectible accounts does not include NEGT.
(3) Deductions consist principally of write-offs, net of collections of receivables previously written off.

	Exhibit Index
Exhibit Number	Exhibit Description
2.1	Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2	Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1	Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2	Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3	Bylaws of PG&E Corporation amended as of ~~January 1, 2006~~September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4	Text of the amendment to the Bylaws of PG&E Corporation effective May 14, 2008
3.5	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
~~3.5~~3.6	Bylaws of Pacific Gas and Electric Company amended as of January 1, ~~2006~~2008
3.7	Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3	Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4	Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
~~4.3~~4.5	Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
~~4.4~~	Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1	Amended and Restated Unsecured Revolving Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
~~10.2~~	~~First Amendment, dated as of November 30, 2005, to the Credit Agreement~~entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan ~~Chase Bank, N.A.~~Securities Inc., as syndication agent, ~~and a lender,~~ Barclays Bank ~~PLC~~Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and ~~the following~~ other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation.
~~10.3~~	~~Credit Agreement,~~lenders, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New YorkFebruary 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form ~~8-K filed December 15, 2004~~10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit ~~99)~~10.2)

57


~~10.4~~10.2	~~First Amendment, dated as of April 8, 2005, to the~~Amended and Restated Unsecured Revolving Credit Agreement ~~dated as of December 10, 2004,~~entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ~~and a lender,~~ ABN ~~Amro~~AMRO Bank, N.V., ~~Goldman Sachs Credit Partners L.P.~~Bank of America, N.A., and ~~Union~~Barclays Bank ~~of California, N.A.,~~Plc, as documentation agents and lenders, and ~~the following~~ other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New Yorklenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q ~~filed May 4, 2005~~for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
~~10.5~~	~~Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.~~
~~10.6~~10.3	Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
~~10.7~~	Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
~~10.8~~	Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
~~10.9~~	PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
~~10.10~~10.4	Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
~~10.11~~10.5	Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*~~10.12~~10.6	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*~~10.13~~10.7	PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*~~10.14~~	Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.1510.8	Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*~~10.16~~10.9	~~Letter regarding Compensation Arrangement~~Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10	Retention Agreement between PG&E Corporation and Thomas B. King dated ~~November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December~~August 31, ~~2000 (File No. 1-12609), Exhibit 10.6)~~
*10.17	~~Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003~~2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, ~~2003~~2006 (File No. 1-12609), Exhibit ~~10.3)~~10.2)
*~~10.18~~10.11	Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13	Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007

Expiration
Date

Quantity
MDth per day

Estimated Annual Charges
2009-2011 (In millions)