Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies

NOTE 15: COMMITMENTS AND CONTINGENCIES

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

Commitments

Third-Party Power Purchase Agreements

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

The table below shows the costs incurred for each type of third-party power purchase agreement for the following periods:

		000000000		000000000		000000000
	Payments
(in millions)	2011		2010		2009
Qualifying facilities(1)		$  1,069		$  1,164		$  1,210
Renewable energy contracts		622		573		362
Other power purchase agreements		690		657		701
(1) Payments include $297, $321, and $344 attributable to renewable energy contracts with qualifying facilities at December 31, 2011, 2010 and 2009, respectively.

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

As of December 31, 2011, the Utility had agreements with 217 QFs for approximately 3,400 megawatts ("MW") that are in operation. Agreements for approximately 3,100 MW expire at various dates between 2012 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with 72 inoperative QFs. The total operational QF agreements consist of approximately 2,200 MW from cogeneration projects and approximately 1,200 MW from renewable sources.

Renewable Energy Power Purchase Agreements – The Utility has entered into various contracts to purchase renewable energy to help the Utility meet the current renewable portfolio standard ("RPS") requirement. California law requires retail sellers of electricity to comply with the RPS by purchasing renewable energy so that the amount of electricity delivered from eligible renewable resources equals at least 33% of their total retail sales. In general, renewable contract payments consist primarily of per megawatt hour payments and either a small or no fixed capacity payment. The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities. As shown in the table below, the Utility's commitments for energy payments under these renewable energy agreements are expected to grow significantly, assuming that the facilities are developed timely.

Other Power Purchase Agreements – In accordance with the Utility's CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility's obligations under a portion of these agreements are contingent on the third parties' development of new generation facilities to provide the power to be purchased by the Utility under the agreements. The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power that require the Utility to make semi-annual fixed minimum payments. In addition, these agreements require the Utility to make variable payments based on the operating and maintenance costs incurred by the irrigation districts and water agencies.

At December 31, 2011, the undiscounted future expected payment obligations under power purchase agreements that have been approved by the CPUC and have completed major milestones for construction were as follows:

(in millions)	Qualifying Facility		Renewable (Other than  QF)		Other		Total Payments
2012		$  736		$  831		$  656		$  2,223
2013		781		1,058		807		2,646
2014		807		1,269		646		2,722
2015		725		1,352		614		2,691
2016		690		1,370		601		2,661
Thereafter		3,341		18,058		3,726		25,125
Total		$  7,080		$  23,938		$  7,050		$  38,068

The table above excludes $34 billion of future expected payments that were previously included in prior periods related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have not met certain contractual milestones with respect to construction. Based on the Utility's experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

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

	september 3000
(in millions)
2012	$  50
2013	50
2014	42
2015	38
2016	36
Thereafter	89
Total fixed capacity payments	305
Less: amount representing interest	57
Present value of fixed capacity payments	$  248

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

The present value of the fixed capacity payments due under these contracts is recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets. At December 31, 2011 and 2010, current liabilities – other included $36 million and $34 million, respectively, and noncurrent liabilities – other included $212 million and $248 million, respectively. The corresponding assets at December 31, 2011 and 2010 of $248 million and $282 million including accumulated amortization of $160 million and $126 million, respectively are included in property, plant, and equipment on PG&E Corporation's and the Utility's Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers' winter peak loads.

At December 31, 2011, the Utility's undiscounted future expected payment obligations were as follows:

	september 3000
(in millions)
2012	$  746
2013	249
2014	198
2015	188
2016	152
Thereafter	974
Total	$  2,507

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $1.8 billion in 2011, $1.6 billion in 2010, and $1.4 billion in 2009.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 14 years and are intended to ensure long-term nuclear fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At December 31, 2011, the undiscounted future expected payment obligations were as follows:

	september 3000
(in millions)
2012	$  88
2013	89
2014	130
2015	189
2016	141
Thereafter	909
Total	$  1,546

Payments for nuclear fuel amounted to $77 million in 2011, $144 million in 2010, and $141 million in 2009.

Other Commitments

The Utility has other commitments relating to operating leases. At December 31, 2011, the future minimum payments related to these commitments were as follows:

	september 3000
(in millions)
2012	$  30
2013	27
2014	20
2015	16
2016	15
Thereafter	81
Total	$  189

Payments for other commitments relating to operating leases amounted to $27 million in 2011, $25 million in 2010, and $22 million in 2009. PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2012 to 2022. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 1% to 4%. The rentals payable under these leases may increase by a fixed amount each year, a percentage of a base year, or the consumer price index. Most leases contain extension options ranging between one and five years.

Underground Electric Facilities

At December 31, 2011, the Utility was committed to spending approximately $292 million for the conversion of existing overhead electric facilities to underground electric facilities. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and communications utilities involved. The Utility expects to spend approximately $61 million to $86 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

Contingencies

PG&E Corporation

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

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy ("DOE") was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility's nuclear generating facility at Diablo Canyon and its retired facility at Humboldt Bay ("Humboldt Bay Unit 3"). As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024.

The Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. The DOE filed an appeal of this decision on May 28, 2010. The appeal was argued in the Federal Circuit Court of Appeals on March 10, 2011. The Utility is awaiting a decision on the appeal and has not recorded any receivable for the award.

Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred at least $205 million of such costs since 2005. Any amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear generating units at Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited ("NEIL"). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss, the Utility may be required to pay an additional premium of up to $40 million per one-year policy term. NRC regulations require that the Utility's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be "certified" by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator's facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier's and transporter's ("S&T") insurance policies. The Utility has a S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses (or reasonably possible losses in excess of the amounts accrued), are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, penalties, and other legal matters (other than third-party claims and penalties related to the San Bruno accident and natural gas matters) totaled $52 million at December 31, 2011 and $55 million at December 31, 2010 and are included in PG&E Corporation's and the Utility's current liabilities – other in the Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (Line 132) owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno, California (the "San Bruno accident"). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. The National Transportation Safety Board ("NTSB"), an independent review panel appointed by the CPUC, and the CPUC's Consumer Protection and Safety Division ("CPSD") completed investigations into the causes of the accident, placing the blame primarily on the Utility. In January 2012, the CPSD issued its report containing the findings of its investigation into the San Bruno accident and alleged that the Utility committed numerous violations of applicable laws and regulations.

The CPUC has issued three orders instituting investigations pertaining to the Utility's natural gas operations, including an investigation into the San Bruno accident to consider the CPSD's allegations. Additionally, under the CPUC's new citation program, the Utility has self-reported to the CPUC that the Utility failed to comply with various regulations and orders applicable to natural gas operating practices. The Utility believes it is probable that the CPUC will impose material penalties in connection with these pending investigations and self-reported violations. See "Pending CPUC Investigations and Enforcement Matters" below. It is reasonably possible that an investigation of the San Bruno accident by state and federal authorities could also result in the imposition of civil or criminal penalties on the Utility. See "Criminal Investigation" below.

Finally, various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. These lawsuits seek compensation for personal injury and property damage and other relief, including punitive damages. See "Third-Party Claims" below.

Pending CPUC Investigations and Enforcement Matters

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system. The Utility has provided extensive information to the CPUC, including information regarding its records, some of which date from 1955. The CPSD is scheduled to file its report on the Utility's recordkeeping practices on March 5, 2012. Hearings for the investigation are scheduled for September 2012 with a final decision expected in February 2013.

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure ("MAOP") up to which a pipeline can be operated. On January 17, 2012, the Utility reported that 162 miles of pipeline had a current class location designation that was higher than reflected in the Utility's Geographic Information System. Most of the misclassifications were attributable to the Utility's failure to correctly identify development or well-defined areas near the pipeline. The Utility determined that some segments had been incorrectly classified since 1971. The Utility also determined that it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. On February 2, 2012, the Utility filed an update reporting that approximately 10 miles had been operating at a MAOP higher than allowed for their current class location. A prehearing conference was held on February 3, 2012 at which the assigned administrative law judge ("ALJ") set April 2, 2012 as the date for the Utility to submit a second update reporting the final results of its validation of the class location data. The ALJ will set a second prehearing conference during the week of April 16, 2012.

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident as alleged by the CPSD. In its report, the CPSD alleged that the San Bruno accident was caused by the Utility's failure to follow accepted industry practice when installing the section of pipe that failed, the Utility's failure to comply with federal pipeline integrity management requirements, the Utility's inadequate record keeping practices, deficiencies in the Utility's data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility's deficient emergency response actions after the incident, and a systemic failure of the Utility's corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility's compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD's investigation is ongoing and that the CPSD could raise additional concerns that it could request the CPUC to consider.

Finally, in December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities' natural gas operating practices, including the authority to levy citations and impose penalties. The Utility has filed several self-reports to inform the CPUC of violations of various regulations and orders applicable to its natural gas operating practices. Recently, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million for certain self-reported violations for failing to conduct periodic surveys due to plat maps being misplaced. The Utility has appealed the penalty, in part, on the basis that the penalty amount is inappropriate in the circumstances and that the CPSD over-counted the number of violations. The CPSD may issue additional citations and impose penalties on the Utility for other violations the Utility has reported to the CPUC.

Penalties Conclusion

If the CPUC determines that the Utility violated applicable laws, rules or orders, in connection with these above matters, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has historically exercised this discretion in determing penalties. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility's policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose total penalties of at least $200 million on the Utility as a result of these investigations and the Utility's self-reported violations and have accrued this amount as of December 31, 2011. In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the reports recently issued by the CPSD; the Utility's self-reports to the CPUC that some of the Utility's past natural gas operating practices did not comply with applicable laws and regulations for a significant period of time; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. Among other factors, PG&E Corporation and the Utility are uncertain whether additional citations or violations will be identified; how the CPUC will exercise its discretion in calculating the ultimate amount of penalties; whether the ultimate amount of penalties will be determined separately for each matter above or in the aggregate; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility's results of operations, financial condition, and cash flows.

The Utility's estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes are likely to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Criminal Investigation

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation.

PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Third-Party Claims

Approximately 100 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The Utility recorded $220 million in 2010 and $155 million in 2011 for estimated third-party claims related to the San Bruno accident, for a cumulative provision of $375 million. The Utility estimates it is reasonably possible that it may incur as much as an additional $225 million for third-party claims, for a total loss of $600 million, increased from the $400 million total loss previously estimated in 2010. The Utility's change in estimate resulted primarily from new information regarding the nature of claims filed against the Utility, experience to date in resolving cases, and developments in the litigation and regulatory proceedings related to the San Bruno accident. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any punitive damages related to these matters. As more information becomes known, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows in the period during which they are recorded.

The following amounts were accrued for third-party claims in other current liabilities in PG&E Corporation's and the Utility's Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$	0
Loss accrued		220
Less: Payments		(6)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92)
Balance at December 31, 2011	$	277

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or "layers." Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $99 million for insurance recoveries during the year end December 31, 2011. As of December 31, 2011, $22 million was recorded as a receivable for insurance recoveries in PG&E Corporation's and the Utility's Consolidated Balance Sheets. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Environmental Remediation Contingencies

The Utility has been, and may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant ("MGP") sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. 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.

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The following table presents the changes in the environmental remediation liability from December 31, 2010:

(in millions)
Balance at December 31, 2010	$	612
Additional remediation costs accrued:
Transfer to regulatory account for recovery		169
Amounts not recoverable from customers		156
Less: Payments		(152)
Balance at December 31, 2011	$	785

The $785 million accrued at December 31, 2011 consisted of the following:

• $149 million for remediation at the Utility's natural gas compressor site located near Hinkley, California ("Hinkley natural gas compressor site"), as described below;

• $218 million for remediation at the Utility's natural gas compressor site located on the California border, near Topock, Arizona;

• $81 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

• $133 million related to remediation costs for the Utility's generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

• $154 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

• $50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor site located near Hinkley, California. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility's remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region ("Regional Board"). The Regional Board has issued several orders directing the Utility to implement interim remedial measures to both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume.

In August 2010, the Utility filed a comprehensive feasibility study with the Regional Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and further information from the Regional Board. In September 2011, the Utility submitted a final remediation plan to the Regional Board that recommends a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated that it anticipates releasing a draft environmental impact report ("EIR") in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

On October 11, 2011, the Regional Board issued an amended cleanup and abatement order to require the Utility to provide an interim and permanent replacement water system for certain properties with domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion ("ppb") background level and to propose a method to evaluate individual wells with hexavalent chromium concentrations below 3.1 ppb in the affected area to determine if they have been impacted by the Utility's past operations. The order requires the Utility to provide evidence to prove that the provided water meets primary and secondary drinking water standards and contains hexavalent chromium in concentrations no greater than 0.02 ppb. The order notes that for purposes of this standard, drinking water must test below the reporting limit of 0.06 ppb due to the limitation of laboratory analysis of low levels of chromium. On October 25, 2011, the Utility filed a stay request and petition with the California State Water Resources Control Board ("State Board") and requested that the State Board determine that the Utility is not required to comply with these provisions of the order, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law. The Regional Board's response to the petition is due by February 20, 2012.

As of December 31, 2011 and December 31, 2010, $149 million and $45 million, respectively, were accrued in PG&E Corporation's and the Utility's Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. During 2011, the Utility increased its provision for environmental remediation liabilities by $140 million due to changes in cost estimates and assumptions associated with the developments described above. During 2011, the Utility spent $36 million for remediation costs at Hinkley. Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the scope of requirements to provide a permanent water replacement system to affected residents. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility's provision for its remediation liability will impact PG&E Corporation's and the Utility's financial results.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility's undiscounted future costs could increase to as much as $1.5 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $393 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $68 million from other ratemaking mechanisms. Finally, the Utility also recovers these 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.

Pacific Gas And Electric Company [Member]

Commitments And Contingencies

NOTE 15: COMMITMENTS AND CONTINGENCIES

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

Commitments

Third-Party Power Purchase Agreements

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

The table below shows the costs incurred for each type of third-party power purchase agreement for the following periods:

		000000000		000000000		000000000
	Payments
(in millions)	2011		2010		2009
Qualifying facilities(1)		$  1,069		$  1,164		$  1,210
Renewable energy contracts		622		573		362
Other power purchase agreements		690		657		701
(1) Payments include $297, $321, and $344 attributable to renewable energy contracts with qualifying facilities at December 31, 2011, 2010 and 2009, respectively.

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

As of December 31, 2011, the Utility had agreements with 217 QFs for approximately 3,400 megawatts ("MW") that are in operation. Agreements for approximately 3,100 MW expire at various dates between 2012 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with 72 inoperative QFs. The total operational QF agreements consist of approximately 2,200 MW from cogeneration projects and approximately 1,200 MW from renewable sources.

Renewable Energy Power Purchase Agreements – The Utility has entered into various contracts to purchase renewable energy to help the Utility meet the current renewable portfolio standard ("RPS") requirement. California law requires retail sellers of electricity to comply with the RPS by purchasing renewable energy so that the amount of electricity delivered from eligible renewable resources equals at least 33% of their total retail sales. In general, renewable contract payments consist primarily of per megawatt hour payments and either a small or no fixed capacity payment. The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities. As shown in the table below, the Utility's commitments for energy payments under these renewable energy agreements are expected to grow significantly, assuming that the facilities are developed timely.

Other Power Purchase Agreements – In accordance with the Utility's CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility's obligations under a portion of these agreements are contingent on the third parties' development of new generation facilities to provide the power to be purchased by the Utility under the agreements. The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power that require the Utility to make semi-annual fixed minimum payments. In addition, these agreements require the Utility to make variable payments based on the operating and maintenance costs incurred by the irrigation districts and water agencies.

At December 31, 2011, the undiscounted future expected payment obligations under power purchase agreements that have been approved by the CPUC and have completed major milestones for construction were as follows:

(in millions)	Qualifying Facility		Renewable (Other than  QF)		Other		Total Payments
2012		$  736		$  831		$  656		$  2,223
2013		781		1,058		807		2,646
2014		807		1,269		646		2,722
2015		725		1,352		614		2,691
2016		690		1,370		601		2,661
Thereafter		3,341		18,058		3,726		25,125
Total		$  7,080		$  23,938		$  7,050		$  38,068

The table above excludes $34 billion of future expected payments that were previously included in prior periods related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have not met certain contractual milestones with respect to construction. Based on the Utility's experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

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

	september 3000
(in millions)
2012	$  50
2013	50
2014	42
2015	38
2016	36
Thereafter	89
Total fixed capacity payments	305
Less: amount representing interest	57
Present value of fixed capacity payments	$  248

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

The present value of the fixed capacity payments due under these contracts is recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets. At December 31, 2011 and 2010, current liabilities – other included $36 million and $34 million, respectively, and noncurrent liabilities – other included $212 million and $248 million, respectively. The corresponding assets at December 31, 2011 and 2010 of $248 million and $282 million including accumulated amortization of $160 million and $126 million, respectively are included in property, plant, and equipment on PG&E Corporation's and the Utility's Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers' winter peak loads.

At December 31, 2011, the Utility's undiscounted future expected payment obligations were as follows:

	september 3000
(in millions)
2012	$  746
2013	249
2014	198
2015	188
2016	152
Thereafter	974
Total	$  2,507

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $1.8 billion in 2011, $1.6 billion in 2010, and $1.4 billion in 2009.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 14 years and are intended to ensure long-term nuclear fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At December 31, 2011, the undiscounted future expected payment obligations were as follows:

	september 3000
(in millions)
2012	$  88
2013	89
2014	130
2015	189
2016	141
Thereafter	909
Total	$  1,546

Payments for nuclear fuel amounted to $77 million in 2011, $144 million in 2010, and $141 million in 2009.

Other Commitments

The Utility has other commitments relating to operating leases. At December 31, 2011, the future minimum payments related to these commitments were as follows:

	september 3000
(in millions)
2012	$  30
2013	27
2014	20
2015	16
2016	15
Thereafter	81
Total	$  189

Payments for other commitments relating to operating leases amounted to $27 million in 2011, $25 million in 2010, and $22 million in 2009. PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2012 to 2022. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 1% to 4%. The rentals payable under these leases may increase by a fixed amount each year, a percentage of a base year, or the consumer price index. Most leases contain extension options ranging between one and five years.

Underground Electric Facilities

At December 31, 2011, the Utility was committed to spending approximately $292 million for the conversion of existing overhead electric facilities to underground electric facilities. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and communications utilities involved. The Utility expects to spend approximately $61 million to $86 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

Contingencies

PG&E Corporation

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

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy ("DOE") was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility's nuclear generating facility at Diablo Canyon and its retired facility at Humboldt Bay ("Humboldt Bay Unit 3"). As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024.

The Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. The DOE filed an appeal of this decision on May 28, 2010. The appeal was argued in the Federal Circuit Court of Appeals on March 10, 2011. The Utility is awaiting a decision on the appeal and has not recorded any receivable for the award.

Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred at least $205 million of such costs since 2005. Any amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear generating units at Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited ("NEIL"). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss, the Utility may be required to pay an additional premium of up to $40 million per one-year policy term. NRC regulations require that the Utility's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be "certified" by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator's facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier's and transporter's ("S&T") insurance policies. The Utility has a S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses (or reasonably possible losses in excess of the amounts accrued), are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, penalties, and other legal matters (other than third-party claims and penalties related to the San Bruno accident and natural gas matters) totaled $52 million at December 31, 2011 and $55 million at December 31, 2010 and are included in PG&E Corporation's and the Utility's current liabilities – other in the Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (Line 132) owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno, California (the "San Bruno accident"). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. The National Transportation Safety Board ("NTSB"), an independent review panel appointed by the CPUC, and the CPUC's Consumer Protection and Safety Division ("CPSD") completed investigations into the causes of the accident, placing the blame primarily on the Utility. In January 2012, the CPSD issued its report containing the findings of its investigation into the San Bruno accident and alleged that the Utility committed numerous violations of applicable laws and regulations.

The CPUC has issued three orders instituting investigations pertaining to the Utility's natural gas operations, including an investigation into the San Bruno accident to consider the CPSD's allegations. Additionally, under the CPUC's new citation program, the Utility has self-reported to the CPUC that the Utility failed to comply with various regulations and orders applicable to natural gas operating practices. The Utility believes it is probable that the CPUC will impose material penalties in connection with these pending investigations and self-reported violations. See "Pending CPUC Investigations and Enforcement Matters" below. It is reasonably possible that an investigation of the San Bruno accident by state and federal authorities could also result in the imposition of civil or criminal penalties on the Utility. See "Criminal Investigation" below.

Finally, various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. These lawsuits seek compensation for personal injury and property damage and other relief, including punitive damages. See "Third-Party Claims" below.

Pending CPUC Investigations and Enforcement Matters

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system. The Utility has provided extensive information to the CPUC, including information regarding its records, some of which date from 1955. The CPSD is scheduled to file its report on the Utility's recordkeeping practices on March 5, 2012. Hearings for the investigation are scheduled for September 2012 with a final decision expected in February 2013.

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure ("MAOP") up to which a pipeline can be operated. On January 17, 2012, the Utility reported that 162 miles of pipeline had a current class location designation that was higher than reflected in the Utility's Geographic Information System. Most of the misclassifications were attributable to the Utility's failure to correctly identify development or well-defined areas near the pipeline. The Utility determined that some segments had been incorrectly classified since 1971. The Utility also determined that it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. On February 2, 2012, the Utility filed an update reporting that approximately 10 miles had been operating at a MAOP higher than allowed for their current class location. A prehearing conference was held on February 3, 2012 at which the assigned administrative law judge ("ALJ") set April 2, 2012 as the date for the Utility to submit a second update reporting the final results of its validation of the class location data. The ALJ will set a second prehearing conference during the week of April 16, 2012.

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident as alleged by the CPSD. In its report, the CPSD alleged that the San Bruno accident was caused by the Utility's failure to follow accepted industry practice when installing the section of pipe that failed, the Utility's failure to comply with federal pipeline integrity management requirements, the Utility's inadequate record keeping practices, deficiencies in the Utility's data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility's deficient emergency response actions after the incident, and a systemic failure of the Utility's corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility's compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD's investigation is ongoing and that the CPSD could raise additional concerns that it could request the CPUC to consider.

Finally, in December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities' natural gas operating practices, including the authority to levy citations and impose penalties. The Utility has filed several self-reports to inform the CPUC of violations of various regulations and orders applicable to its natural gas operating practices. Recently, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million for certain self-reported violations for failing to conduct periodic surveys due to plat maps being misplaced. The Utility has appealed the penalty, in part, on the basis that the penalty amount is inappropriate in the circumstances and that the CPSD over-counted the number of violations. The CPSD may issue additional citations and impose penalties on the Utility for other violations the Utility has reported to the CPUC.

Penalties Conclusion

If the CPUC determines that the Utility violated applicable laws, rules or orders, in connection with these above matters, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has historically exercised this discretion in determing penalties. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility's policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose total penalties of at least $200 million on the Utility as a result of these investigations and the Utility's self-reported violations and have accrued this amount as of December 31, 2011. In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the reports recently issued by the CPSD; the Utility's self-reports to the CPUC that some of the Utility's past natural gas transmission operating and recordkeeping practices did not comply with applicable laws and regulations for a significant period of time; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. Among other factors, PG&E Corporation and the Utility are uncertain whether additional citations or violations will be identified; how the CPUC will exercise its discretion in calculating the ultimate amount of penalties; whether the ultimate amount of penalties will be determined separately for each matter above or in the aggregate; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility's results of operations, financial condition, and cash flows.

The Utility's estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes are likely to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Criminal Investigation

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that may be imposed on the Utility in connection with the investigation given it is in the early stages.

Third-Party Claims

Approximately 100 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The Utility recorded $220 million in 2010 and $155 million in 2011 for estimated third-party claims related to the San Bruno accident, for a cumulative provision of $375 million. The Utility estimates it is reasonably possible that it may incur as much as an additional $225 million for third-party claims, for a total loss of $600 million, increased from the $400 million total loss previously estimated in 2010. The Utility's change in estimate resulted primarily from new information regarding the nature of claims filed against the Utility, experience to date in resolving cases, and developments in the litigation and regulatory proceedings related to the San Bruno accident. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any punitive damages related to these matters. As more information becomes known, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows in the period during which they are recorded.

The following amounts were accrued for third-party claims in other current liabilities in PG&E Corporation's and the Utility's Consolidated Balance Sheets:

(in millions)
Balance at September 30, 2010	$	220
Less: Payments		(6)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92)
Balance at December 31, 2011	$	277

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or "layers." Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $99 million for insurance recoveries during the year end December 31, 2011. As of December 31, 2011, $22 million was recorded as a receivable for insurance recoveries in PG&E Corporation's and the Utility's Consolidated Balance Sheets. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Environmental Remediation Contingencies

The Utility has been, and may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant ("MGP") sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. 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.

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The following table presents the changes in the environmental remediation liability from December 31, 2010:

(in millions)
Balance at December 31, 2010	$	612
Additional remediation costs accrued:
Transfer to regulatory account for recovery		169
Amounts not recoverable from customers		156
Less: Payments		(152)
Balance at December 31, 2011	$	785

The $785 million accrued at December 31, 2011 consisted of the following:

• $149 million for remediation at the Utility's natural gas compressor site located near Hinkley, California ("Hinkley natural gas compressor site"), as described below;

• $218 million for remediation at the Utility's natural gas compressor site located on the California border, near Topock, Arizona;

• $81 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

• $133 million related to remediation costs for the Utility's generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

• $154 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

• $50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor site located near Hinkley, California. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility's remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region ("Regional Board"). The Regional Board has issued several orders directing the Utility to implement interim remedial measures to both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume.

In August 2010, the Utility filed a comprehensive feasibility study with the Regional Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and further information from the Regional Board. In September 2011, the Utility submitted a final remediation plan to the Regional Board that recommends a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated that it anticipates releasing a draft environmental impact report ("EIR") in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

On October 11, 2011, the Regional Board issued an amended cleanup and abatement order to require the Utility to provide an interim and permanent replacement water system for certain properties with domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion ("ppb") background level and to propose a method to evaluate individual wells with hexavalent chromium concentrations below 3.1 ppb in the affected area to determine if they have been impacted by the Utility's past operations. The order requires the Utility to provide evidence to prove that the provided water meets primary and secondary drinking water standards and contains hexavalent chromium in concentrations no greater than 0.02 ppb. The order notes that for purposes of this standard, drinking water must test below the reporting limit of 0.06 ppb due to the limitation of laboratory analysis of low levels of chromium. On October 25, 2011, the Utility filed a stay request and petition with the California State Water Resources Control Board ("State Board") and requested that the State Board determine that the Utility is not required to comply with these provisions of the order, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law. The Regional Board's response to the petition is due by February 20, 2012.

As of December 31, 2011 and December 31, 2010, $149 million and $45 million, respectively, were accrued in PG&E Corporation's and the Utility's Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. During 2011, the Utility increased its provision for environmental remediation liabilities by $140 million due to changes in cost estimates and assumptions associated with the developments described above. During 2011, the Utility spent $36 million for remediation costs at Hinkley. Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the scope of requirements to provide a permanent water replacement system to affected residents. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility's provision for its remediation liability will impact PG&E Corporation's and the Utility's financial results.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility's undiscounted future costs could increase to as much as $1.5 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $393 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $68 million from other ratemaking mechanisms. Finally, the Utility also recovers these 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.