NOTE 10: 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, environmental remediation, and tax matters.

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 gas or electricity at the date of purchase. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s development of new generation facilities to provide the power to be purchased by the Utility under these agreements. The table below excludes expected future payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility has 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.

At June 30, 2012, the undiscounted future expected payment obligations were as follows:


(in millions)
2012			$ 1,337
2013			2,987
2014			3,142
2015			3,105
2016			2,998
Thereafter			32,911

Total			$ 46,480

Costs incurred by the Utility under power purchase agreements amounted to $978 million and $1.1 billion for the six months ended June 30, 2012 and 2011, respectively.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities are treated as capital leases. During the six months ended June 30, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. The future minimum lease payments associated with the remaining capital leases were approximately $125 million.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the U.S. 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 U.S. Rocky Mountain supply area, and the southwestern U.S.) 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 June 30, 2012, the Utility’s undiscounted future expected payment obligations were as follows:


(in millions)
2012			$ 382
2013			426
2014			195
2015			185
2016			152
Thereafter			973

Total			$ 2,313

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $639 million and $929 million for the six months ended June 30, 2012 and 2011, respectively.

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 June 30, 2012, the undiscounted future expected payment obligations were as follows:


(in millions)
2012			$ 46
2013			86
2014			127
2015			193
2016			147
Thereafter			1,011

Total			$ 1,610

Payments for nuclear fuel amounted to $40 million and $47 million for the six months ended June 30, 2012 and 2011, respectively.

Other Commitments

In March 2012, the Utility entered into a 10-year facility lease agreement for 250,000 square feet of office space in San Ramon, California. As of June 30, 2012, the future minimum commitment for this operating lease was approximately $67 million.

Contingencies

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 natural gas matters discussed below) totaled $42 million at June 30, 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 Condensed 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. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.

Pending CPUC Investigations and Enforcement Matters

CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines

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. 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 CPUC’s Customer Protection and Safety Division (“CPSD”) filed testimony alleging that the Utility committed numerous violations of applicable laws and regulations based on the findings of the CPSD’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. On June 26, 2012, the Utility submitted testimony to the CPUC that disputed many of the CPSD’s findings and allegations, but acknowledged that improvements are needed to its asset management system and recordkeeping practices and outlined the steps being taken in these areas. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding Class Location Designations for Pipelines

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. In the CPSD’s May 25, 2012 investigative report, the CPSD cited the Utility’s admissions in previous reports to the CPUC that it had failed to classify pipeline segments properly and document past patrols of transmission lines and concluded that these failures resulted in a total of 3,062 violations of state and federal standards, the durations of which in total exceeded 15 million days. The report urged the CPUC to levy significant penalties on the Utility but did not recommend a specific penalty amount. On July 23, 2012, the Utility submitted testimony in response to the CPSD’s report that acknowledged deficiencies in the Utility’s past class location and patrol processes and described the efforts to improve those processes. The Utility also reported 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 property easements and that the Utility plans to undertake a multi-year effort to clear these encroachments. Evidentiary hearings are scheduled for August 2012 with a final decision expected in late 2012 or early 2013. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding San Bruno Accident

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 investigation report, the CPSD had 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 the CPSD could raise additional concerns that it could request the CPUC to consider.

On June 26, 2012, the Utility submitted testimony to the CPUC that disputed many of the CPSD’s findings and allegations. The Utility acknowledged its liability for the San Bruno accident and determined that the likely root cause of the pipeline rupture was (1) a missing interior weld on the pipe; (2) a ductile tear 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 that grew over time. However, the Utility stated that many of the findings identified in the CPSD’s reports are not deficiencies, or are much less severe than alleged, and do not constitute violations of applicable laws and regulations.

Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. (See “Penalties Conclusion” below.)

Other Natural Gas Compliance Matters

In December 2011, the CPUC delegated authority to the CPSD 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 issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. As of July 31, 2012, the Utility has submitted approximately 24 self-reports with the CPUC. In April 2012, the CPUC ordered the Utility to pay a $17 million penalty imposed by the CPSD for one of these self-reports in which the Utility failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD has not yet taken action with respect to the Utility’s other self-reports. The CPSD 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.)

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the penalties may be as high as $50,000 per day, per violation. (Under the CPUC’s delegation of authority described above, the CPSD is required to impose the maximum statutory penalty.) The CPUC and the CPSD have wide discretion to determine the number of violations and the length of time the violations existed. The calculation of penalties is generally based on the totality of the circumstances, including such factors as the severity of the violations; 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 stated that it is prepared to impose very significant penalties on the Utility 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 continue to believe it is probable that the Utility will incur total penalties of at least $200 million in connection with these investigations and the Utility’s self-reports. PG&E Corporation and the Utility have not recorded any additional charges during the six months ended June 30, 2012 and are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. These estimates, and the assumptions on which they are based, are subject to change as the CPUC investigations progress and more information becomes known regarding the number of violations found to have been committed by the Utility; whether penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD will issue additional citations based on the Utility’s self-reports; 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; and the terms of possible settlements (if any) that may be negotiated with the CPUC. Future changes in these estimates or assumptions could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Criminal Investigation

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 and 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.

Third-Party Claims

In addition to the investigations and proceedings discussed above, at June 30, 2012, approximately 120 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 400 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The trial date for the first of these cases has been rescheduled from July 23, 2012 to October 9, 2012. The court also postponed until September 4, 2012 the hearing on various motions filed by PG&E Corporation and the Utility to request that the court dismiss certain claims, including the plaintiffs’ claims for punitive damages, based upon a lack of evidence to support such claims.

At June 30, 2012, the Utility has recorded a cumulative charge of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during the three and six months ended June 30, 2012, primarily to reflect recent 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.

The following table presents the changes in third-party claims liability since the San Bruno accident in 2010, which is included in other current liabilities in PG&E Corporation’s and the Utility’s Condensed 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
Additional loss accrued			80
Less: Payments			(47)

Balance at June 30, 2012			$ 310

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 $25 million and $36 million for insurance recoveries during the three and six months ended June 30, 2012. This is in addition to the $99 million recognized for insurance recoveries during 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 future insurance recoveries.

Spent Nuclear Fuel Storage Proceeding

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (“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 with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”). 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. Since 2004, the Utility has filed several complaints in the U.S. Court of Federal Claims to recover $92 million of costs that it incurred through 2004 and to recover all costs incurred in periods thereafter. The Utility estimates that it has incurred costs at least $205 million since 2005. The Utility’s complaints have been similar to those filed by other utilities with nuclear facilities.

On June 6, 2012, the Utility and the DOJ requested that the U.S. Attorney General approve a proposed settlement agreement that would award the Utility $266 million for spent fuel storage costs incurred through December 31, 2010. The proposed agreement also would allow the Utility to submit annual claims to recover costs incurred in 2011, 2012 and 2013, which the Utility estimates to be $25 million per year. 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 fuel.

At June 30, 2012, no receivable related to the proposed settlement was recorded in the Utility’s Condensed Consolidated Financial Statements. The Utility expects that the proposed settlement will be approved in the third quarter of 2012 and that the Utility will receive the payment during the same quarter. Amounts recovered from the DOJ will be refunded to customers through rates in future periods.

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 $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 (“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.

Guarantees

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.

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 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 following table presents the changes in the environmental remediation liability from December 31, 2011:


(in millions)
Balance at December 31, 2011			$ 785
Additional remediation costs accrued:
Transfer to regulatory account for recovery			100
Amounts not recoverable in customer rates			96
Less: Payments			(61)

Balance at June 30, 2012			$ 920

The environmental remediation liability is composed of the following:


	Balance At
(in millions)	June 30, 2012		December 31, 2011
Utility-owned natural gas compressor site near Hinkley, California ⁽¹⁾		$ 210		$ 149
Utility-owned natural gas compressor site near Topock, Arizona		240		218
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		165		133
Former MGP sites owned by the Utility or third parties		178		154
Fossil fuel-fired generation facilities formerly owned by the Utility		88		81
Decommissioning fossil fuel-fired generation facilities and sites		39		50

Total environmental remediation liability		$ 920		$ 785



(1) See “Hinkley Natural Gas Compressor Site” below.

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 June 30, 2012, the Utility expected to recover $573 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.

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 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 reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

In June 2012, the Regional Board issued an amended cleanup and abatement order that accepted the Utility’s proposed program to provide whole house replacement systems for approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility has begun implementing this program and is required to complete implementation 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.

The Regional Board is also evaluating final remediation alternatives submitted by the Utility using 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 it anticipates releasing a draft environmental impact report (“EIR”) in the second half of 2012 and the Utility expects that it will consider certification of the final EIR, which will include the final approved remediation plan, in early 2013.

At June 30, 2012, $210 million was accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility’s best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

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 number of eligible residents who participate in the Utility’s program or choose to have the Utility purchase their properties, as described above. 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.

Reasonably Possible Environmental Remediation Contingencies

Although the Utility has provided for known environmental remediation 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 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. 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.

Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time Internal Revenue Service (“IRS”) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. In December 2010, the IRS accepted the 2009 tax return without change. In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review. The IRS has not completed the CAP audit for 2011.

The most significant of the matters withheld for further review relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In the fourth quarter 2011, the IRS agreed to allow PG&E Corporation to file claims for 2008-2010 for the repairs method change. The IRS has not completed its review of these claims.

The audits of PG&E Corporation’s tax returns for the 2005 through 2007 tax years are in the final stages of IRS appeal. PG&E Corporation expects to complete the appeals process in 2012.

The IRS is continuing to work with the utility industry to provide consistent repairs deduction guidance for natural gas transmission, natural gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance in 2012.

PG&E Corporation and the Utility are unable to determine a range of reasonably possible impact of future changes to the unrecognized tax benefits at this time.