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 regulatory proceedings, nuclear operations, legal matters, environmental remediation, and guarantees.

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. 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.

Renewable Energy Power Purchase Agreements - The Utility has entered into various contracts to purchase renewable energy to help the Utility meet California's current renewable portfolio standard (“RPS”) requirement. California's RPS program gradually increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from an average of at least 20% of their total retail sales in the years 2011-2013 to 33% of their total retail sales in 2021 and thereafter. Generally these agreements include an energy payment based on the electrical output and a fixed price per Megawatt-hour. The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities. The table below includes arrangements that have been approved by the CPUC and have completed major milestones with respect to construction. 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 - The Utility has entered into several power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility's obligation under a portion of these agreements is contingent on the third parties' development of new generation facilities to provide capacity and energy products to the Utility under tolling agreements. The Utility also has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

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 agreements 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.

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 agreements that are treated as capital leases expire between April 2014 and September 2021.

The present value of the fixed capacity payments due under these agreements is recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets. At December 31, 2012 and 2011, current liabilities - other included $29 million and $36 million, respectively, and noncurrent liabilities - other included $96 million and $212 million, respectively. The corresponding assets at December 31, 2012 and 2011 of $125 million and $248 million including accumulated amortization of $148 million and $160 million, respectively are included in property, plant, and equipment on PG&E Corporation's and the Utility's Consolidated Balance Sheets.

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 more reliably meet customers' loads.

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 13 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 2020, 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.

Payments for other commitments relating to operating leases amounted to $32 million in 2012, $27 million in 2011, and $25 million in 2010. PG&E Corporation and the Utility had operating leases on office facilities expiring at various dates from 2013 to 2023. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2% to 5%. The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index. Most leases contain extension options ranging between one and five years.

At December 31, 2012, the Utility was committed to spending approximately $277 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 $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 that the amount of the capital expenditures will be recoverable from customers through rates.

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 the amounts related to 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 the third-party claims, litigation, and investigations related to natural gas matters that are discussed below) totaled $34 million at December 31, 2012 and $52 million at December 31, 2011 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.

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. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced. The Natural Transportation Safety Board, an independent review panel appointed by the CPUC, and the CPUC's Safety and Enforcement Division (“SED”) completed investigations into the causes of the accident, placing the blame primarily on the Utility.

The CPUC is conducting three investigations pertaining to the Utility's natural gas operations, which are described below. In 2012, the SED issued reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending that the CPUC impose penalties on the Utility. (See “Penalties Conclusion” below.) Although the Utility, the SED, and other parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement. PG&E Corporation and the Utility are uncertain whether or when any stipulated outcome might be reached. Any agreement regarding a stipulated outcome would be subject to CPUC approval.

The CPUC has concluded evidentiary hearings in each investigation. The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties' briefs must be submitted. The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separatley address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED. The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013. After briefing has been completed, the ALJs will issue one or more presiding officer's decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions. Based on the revised procedural schedule, one or more presiding officer's decisions will be issued by July 23, 2013. The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.

In February 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system. Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law. In March 2012, the SED submitted testimony alleging that the Utility committed numerous violations of applicable laws and regulations based on the findings of the SED's records management consultant and an engineering consultant. Among other findings, the consultants' reports concluded that: the Utility's recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program. The Utility submitted testimony to the CPUC that acknowledged that improvements are needed to its asset management system and recordkeeping practices, but disputed many of the SED's findings and allegations. The CPUC concluded evidentiary hearings in this investigation in January 2013. Briefing on the issue of alleged violations is scheduled to be completed on April 19, 2013.

In November 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 up to which a pipeline can be operated. In its May 2012 investigative report, the SED cited the Utility's admissions in previous reports to the CPUC that it had failed to classify pipeline segments properly and to document past patrols of transmission lines and concluded that these failures resulted in over three thousand violations of state and federal standards. On July 23, 2012, the Utility submitted testimony in response to the SED's report that acknowledged deficiencies in the Utility's past class location and patrol processes and described the efforts to improve those processes. The CPUC concluded evidentiary hearings in this investigation in September 2012 and briefing on the issue of alleged violations has been completed.

In January 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 SED. In its January investigative report, the SED 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, the Utility's 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 Utility submitted testimony to the CPUC that acknowledged its liability for the San Bruno accident and, based on testimony from an expert witness, stated that the likely root cause of the pipeline rupture was: (1) a missing interior weld on the pipe; (2) a ductile tear on the pipe likely caused by a hydrostatic test performed in 1956 at too low a pressure to cause the defective weld to fail; and (3) a fatigue crack on the pipe that grew over time. However, the Utility stated that many of the findings identified in the SED's reports are not deficiencies, or are much less severe than alleged, and do not constitute violations of applicable laws and regulations. The CPUC concluded evidentiary hearings in this investigation in January 2013. Briefing on the issue of alleged violations is scheduled to be completed on April 12, 2013.

California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations' natural gas operating practices. The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations. In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility's self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule. (The Utility has paid the penalty and completed all of the missed leak surveys.) As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports. The SED has not yet taken formal action with respect to the Utility's other self-reports. The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. (See “Penalties Conclusion” below.)

In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility's gas pipeline rights-of-way. The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period. PG&E Corporation and the Utility are uncertain how this matter will affect the above investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

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 gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this wide discretion in determining penalties. The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. In determining the amount of penalties the ALJs may consider the testimony of financial consultants engaged by the SED and the Utility. The SED's financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through equity issuances, in addition to equity PG&E Corporation had already forecasted it would issue in 2012, to fund CPUC-imposed penalties on the Utility. The Utility's financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts' expectations, which the consultant's report cited as a mean of $477 million, would make financing more difficult and expensive. The ALJs have scheduled a hearing to be held on March 4 and March 5, 2013 to consider the SED's and Utility's testimony. The SED and other parties are scheduled to file briefs to address potential monetary penalties and remedies in all three investigations by April 26, 2013.

PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their consolidated financial statements. PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount accrued due to the many variables that could affect the final outcome of these matters and the ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued. These variables include how the CPUC and the SED will exercise their discretion in calculating the amount of penalties, including how the total number of violations will be counted; how the duration of the violations will be determined; whether the amount of penalties in each investigation will be determined separately or in the aggregate; how the financial resources testimony submitted by the SED and the Utility will be considered; whether the Utility's costs to perform any required remedial actions will be considered; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered. (See “CPUC Gas Safety Rulemaking Proceeding” below.)

These estimates, and the assumptions on which they are based, are subject to change based on many factors, including rulings, orders, or decisions that may be issued by the ALJs; whether the outcome of the investigations is resolved through a fully litigated process or a stipulated outcome that is approved by the CPUC; whether the SED will take additional action with respect to the Utility's self-reports; and whether the CPUC or the SED takes any action with respect to the encroachment matter described above. Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms. On December 20, 2012, the CPUC approved the Utility's proposed pipeline safety enhancement plan (filed in August 2011) to modernize and upgrade its natural gas transmission system but disallowed the Utility's request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). The CPUC decision limited the Utility's recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested. Various parties have asked the CPUC to reconsider its decision, arguing that the Utility's cost recovery should be more limited. For 2012, the Utility recorded a $353 million charge to net income for plan-related capital expenditures incurred that are forecasted to exceed the CPUC's authorized levels or that were specifically disallowed. Future disallowed amounts will be charged to net income in the period incurred and could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

In June 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. Federal and state authorities have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. 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 as a consequence of this investigation.

In addition to the investigations and proceedings discussed above, at December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases were coordinated and assigned to one judge in the San Mateo County Superior Court. Many of the plaintiffs' claims have been resolved through settlements. The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings. On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court. The court has urged the parties to settle the remaining cases. As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs. It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.

At December 31, 2012, the Utility had recorded cumulative charges of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during 2012, primarily to reflect settlements and information exchanged by the parties during the settlement and discovery process. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. 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.

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 insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible. The Utility has recognized cumulative insurance recoveries for third-party claims of $284 million, which included $185 million for 2012 and $99 million for 2011. 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.

On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. To state their claims, the plaintiffs cited the SED's January 2012 investigative report of the San Bruno accident that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively. The SED recommended in that report that the Utility should use such amounts to fund future gas transmission expenditures and operations. Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities. Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106.

PG&E Corporation and the Utility contest the plaintiffs' allegations. In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs' allegations. In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded. The court has set a hearing on the motion for April 26, 2013. Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities. The DOE has been unable to meet its contractual obligation to the Utility to dispose of nuclear waste from the Utility's two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”). As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel.

On September 5, 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010. As of December 31, 2012, the Utility has collected the settlement proceeds from the U.S. Treasury and recorded the amount as a regulatory balancing account. The proceeds will be refunded to customers through rates in future periods. The agreement also allows the Utility to submit annual claims to recover costs incurred in 2011, 2012 and 2013, which the Utility estimates to be approximately $25 million per year. These amounts will also be refunded to customers in future periods. At December 31, 2012, PG&E Corporation and the Utility have not recorded any receivables for annual claims in their Consolidated Balance Sheets. The agreement does not address costs incurred for spent fuel storage after 2013 and such costs could be the subject of future litigation. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent nuclear fuel.

The Utility is a member of Nuclear Electric Insurance Limited (“NEIL”) which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility due to a nuclear event (meaning that nuclear material is released) that occurs at the Utility's two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon. In addition, NEIL provides $131 million of coverage for nuclear and non-nuclear property damages at Humboldt Bay Unit 3. (NEIL also provides insurance coverage to the Utility for non-nuclear property damages and business interruption losses at Diablo Canyon, though with significantly lower limits beginning in April 2013.) 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 $44 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 insurance policies. The Utility has a separate supplier's and transporter's policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

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 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 the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable 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 CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility. At December 31, 2012, the Utility expected to recover $548 million through these ratemaking mechanisms. The Utility also recovers environmental remediation costs from insurance carriers and from other third parties whenever possible. Amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers through rates.

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor sites near Hinkley, California (“Hinkley site”) and Topock, Arizona (“Topock site”). 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 at the Hinkley site 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 reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

The Utility submitted its proposed final remediation plan to the Regional Board in September 2011 recommending a combination of remedial methods to clean up groundwater contamination, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. In August 2012, the Regional Board issued a draft environmental impact report (“EIR”) that evaluated the Utility's proposed methods and the potential environmental impacts. The Utility expects that the Regional Board will consider certification of the final EIR in the second quarter of 2013. Upon certification of the EIR, the Regional Board is expected to issue the final cleanup standards in late 2013.

The Regional Board ordered the Utility in October 2011 to provide an interim and permanent replacement water system for resident households located near the chromium plume that have domestic wells containing hexavalent chromium in concentrations greater than 0.02 parts per billion. The Utility filed a petition with the California State Water Resources Control Board to contest certain provisions of the order. In June 2012, the Regional Board issued an amended order to allow the Utility to implement a whole house water replacement program for resident households located near the chromium plume boundary. Eligible residents may decide whether to accept a replacement water supply or have the Utility purchase their properties, or alternatively not participate in the program. As of January 31, 2013, approximately 350 residential households are covered by the program and the majority have opted to accept the Utility's offer to purchase their properties. The Utility is required to complete implementation of the whole house water replacement systems by August 31, 2013. The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

At December 31, 2012 and 2011, $226 million and $149 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. The increase primarily reflects the Utility's best estimate of costs associated with the developments described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers through rates. Future costs will depend on many factors, including the Regional Board's certification of the final EIR, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility's required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California, as mentioned above. As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation's and the Utility's future financial condition, results of operations, and cash flows.

The Utility's remediation and abatement efforts are subject to the regulatory authority of the Department of Toxic Substances Control (“DTSC”) and the U.S. Department of the Interior (“DOI”). As directed by the DTSC, the Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River. The DTSC has certified the final EIR and approved the Utility's final remediation plan for the groundwater plume, under which the Utility will implement an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility has completed the preliminary design stage for implementing the final groundwater remedy and is required to submit its intermediate design plan to the DTSC and DOI by April 5, 2013 and a final plan for approval in 2014. In developing its intermediate plan, the Utility is currently evaluating input received from regulatory agencies and other stakeholders, exploring potential sources of fresh water to be used as part of the remedy, and performing other engineering activities necessary to complete the remedial design.

At December 31, 2012 and 2011, $239 million and $218 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 Topock site. The CPUC has authorized the Utility to recover 90% of its remediation costs for the Topock site from customers through rates without a reasonableness review. As the Utility completes its remedial design plan and more information becomes known regarding the extent of work to be performed to implement the final groundwater remedy, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to change. Future changes in estimates or assumptions could have a material impact on PG&E Corporation's and the Utility's future financial condition.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley and Topock sites described above) 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. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation's and the Utility's results of operations during the period in which they are recorded.