NOTE 9: CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters.

Enforcement and Litigation Matters

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have been made or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a Commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in the CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On April 18, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility filed a joint Meet and Confer Process Report in advance of the prehearing conference that was held on April 20, 2016. The report included the proposed scope of the proceeding, including the number of communications at issue, a procedure for moving undisputed facts into the evidentiary record, a diligence process for providing additional factual information, and a procedural schedule. Subject to the CPUC’s approval, the parties have agreed that the scope of this proceeding may include a total of 159 communications (the 46 communications already included in the OII and 113 additional communications). The parties also recommended briefing on whether an additional 21 communications should be included in the proceeding. The Utility is expecting a ruling on these proposals in the second quarter of 2016.

The CPUC will determine whether the communications included within the scope of the proceeding were in violation of its rules and whether to impose penalties or other remedies. The CPUC can impose fines up to $50,000 for each violation, per day. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; 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 discretion in determining penalties.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, and whether the CPUC will consider additional communications in the OII, including those identified in a motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S rate case. It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that may have violated the CPUC’s ex parte rules.

Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.

CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping

On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014.

On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities.

On February 26, 2016, the Utility, the SED, TURN, and the City of Carmel, California (“Carmel”) filed their opening briefs. In its brief, the SED cited alleged record-keeping violations related to various natural gas distribution incidents, the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. The SED recommended that the CPUC impose a fine on the Utility of approximately $112 million for these alleged violations. The SED also recommended that the CPUC require the Utility to undertake various remedial actions with respect to its gas distribution system records and facilities and that the Utility be prohibited from recovering remedial-related costs from customers. Carmel recommended that the CPUC impose penalties on the Utility of up to approximately $652 million, including approximately $137 million for the natural gas explosion that occurred in Carmel on March 3, 2014 (for which the Utility has previously paid a CPUC-imposed fine of $10.85 million). Carmel also recommended various remedial measures. TURN recommended that the Utility be required to undertake remedial actions, fund annual SED audits of the Utility’s record-keeping practices for a period of ten years, and promptly correct any deficiencies identified in those audits.

On April 1, 2016, the Utility filed its reply brief in which the Utility indicated that it did not agree that any penalty was appropriate, but if the CPUC determined that a penalty should be imposed, such penalty should not exceed $33.6 million. The Utility recommended that such penalty, if imposed, should be invested in the safety of the Utility’s gas distribution system, for example for implementation of certain remedial measures. The Utility expects that the presiding officer’s decision will be issued within 60 days of the April 1, 2016 filing. Unless any party files an appeal of the presiding officer’s decision or a CPUC Commissioner requests a CPUC review of the presiding officer’s decision within 30 days, the decision will become final. The CPUC has the authority to extend the deadlines indicated above.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the form of fines or other remedies, including possible future unrecoverable costs to implement operational remedies. Remedies would be recorded in the period the expense is incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s discretion in imposing fines and other remedies.

Natural Gas Transmission Pipeline Rights-of-Way

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

Potential Safety Citations

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations of natural gas safety regulations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex Parte Communication Rules” above) in determining the number of violations and whether to impose daily fines for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

Federal Matters

Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014. The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13 remaining counts. Although the trial previously had been scheduled to begin on April 26, 2016, the court vacated the trial date and no new trial date has been set. The court stated that it will set a new trial date in due course.

The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 million. The government is also seeking fines under the Alternative Fines Act. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” On December 8, 2015, the court issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act. The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations. Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million. On February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges.

The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts are not considered to be probable.

Other Federal Matters

The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of March 31, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, of which $665 million was written off in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2016. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

Penalty Decision’s Disallowance of Natural Gas Capital Spend

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings pending against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”). (In January 2016, the CPUC closed the investigative proceedings.) The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine.

For the three months ended March 31, 2016, the Utility recorded additional charges in operating and maintenance expenses in the Condensed Consolidated Statements of Income of $87 million, as a result of the Penalty Decision. The cumulative charges at March 31, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:


	Three Months		Cumulative		Future
	Ended		Charges		Charges
		March 31,		March 31,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit		-		400		-		400
Charge for disallowed capital (1)		87		494		195		689
Disallowed revenue for pipeline safety
expenses (2)		-		-		161		161
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	87	$	1,194	$	356	$	1,600

(1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will identify in a final decision to be issued in the Utility’s 2015 GT&S rate case. The Penalty Decision requires that at least $689 million of the $850 million cost disallowance be allocated to capital expenditures. The Utility estimates that approximately $494 million of cumulative capital spending is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(2) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(3) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Other Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. A provision for a loss contingency is recorded 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. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.

Investigation of the Butte Fire

On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the “Butte fire,” the wildfire that ignited and spread in Amador and Calaveras Counties in Northern California in September 2015. Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and its vegetation management contractors to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

In connection with the Butte fire, approximately 32 complaints have been filed to date against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving approximately 1,300 individual plaintiffs and their insurance companies. In response to plaintiffs’ and the Utility’s requests, the California Judicial Council has authorized the coordination of all cases in the Superior Court of California, Sacramento County. Plaintiffs have begun to present to the Utility claims seeking early resolution of preference cases (individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The number of complaints may increase in the future. An initial case management conference was held on April 22, 2016 and the next case management conference is currently scheduled for May 24, 2016.

In connection with this matter, the Utility may be liable for property damages without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.

Based on the evidence described in the Cal Fire report that the Gray Pine tree contacted an electric line of the Utility, the Utility believes that it is probable that it will incur a loss of $350 million for property damages in connection with this matter, which corresponds to the lower end of the range of its reasonably estimated losses. This amount is based on estimates about the number, size, and type of structures damaged or destroyed, and assumptions about the contents of such structures and other property damage. The Utility currently is unable to reasonably estimate the upper end of the range. At March 31, 2016, the Condensed Consolidated Balance Sheets include $350 million in other current liabilities for the estimated property damages.

The Utility also believes that it is reasonably possible that it will incur a loss in excess of this amount, for additional costs related to fire suppression, personal injury damages, and other damages. The Utility believes that $90 million is a reasonable estimate of fire suppression costs. The Utility currently is unable to reasonably estimate other costs.

The Utility has insurance coverage for third party claims. If the amount of insurance is insufficient to cover the Utility’s liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected.

As a result of the Cal Fire report, additional investigations and proceedings may be opened, the outcome of which PG&E Corporation and the Utility are unable to predict.

Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC granted TURN’s and ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California IOUs for the 2006-2008 energy efficiency program cycle. Under the incentive ratemaking mechanism applicable to the 2006-2008 program cycle, the Utility could have earned incentive revenues up to a maximum of $180 million, depending on the extent to which the Utility achieved the energy savings targets. Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened proceeding, the CPUC will evaluate whether the incentive amounts awarded to the IOUs were just and reasonable, and whether any refunds are due.

On March 18, 2016, TURN and ORA submitted a joint proposal to require a refund of incentive awards that TURN and ORA argue were not calculated in accordance with the ratemaking mechanism rules and procedures the CPUC had previously adopted. TURN and ORA contended that the CPUC should order the Utility to refund $104 million, the entire incentive earnings award, plus interest, to customers as either (1) a revenue credit to customers’ distribution and gas transportation accounts or (2) as a line item to the customers’ first monthly bill following the issuance of a CPUC decision.

Additionally, on March 18, 2016, the IOUs submitted their proposals requesting that the CPUC reaffirm its prior decisions. The IOUs asserted that, given the many unresolved disputes about the data in the Energy Division’s 2010 Evaluation Report, the CPUC appropriately used different data to calculate the awards. The IOUs noted that under the incentive ratemaking mechanism, any refunds of prior incentive earnings should be deducted from future incentive earnings claims.

On April 8, 2016, the IOUs, TURN and ORA filed comments on the proposals, in which the parties reiterated their requests. The Utility currently expects that evidentiary hearings, if ordered by the CPUC, would be held in July 2016. It is uncertain how the CPUC will resolve this matter and when the CPUC will issue a decision.

PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts previously awarded or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations. If the Utility were required to make a refund as TURN and ORA propose, PG&E Corporation’s and the Utility’s financial results would be affected by the amount of any refund-related charges.

Residential Rate Reform Rate Change

On February 17, 2016, the Utility filed a proposed rate change for rates to be billed to customers effective March 1, 2016. On February 29, 2016, the CPUC rejected the Utility’s proposed rate change, stating that the rate design failed to comply with the requirements adopted in the Decision on Residential Rate Reform issued on July 3, 2015, that set a specific rate change “glidepath” for the Utility. The Utility began billing customers based on its proposed rates on March 1, 2016. On March 9, 2016, the assigned ALJ issued a ruling directing the Utility to show cause why the CPUC should not order sanctions and other remedies in response to the Utility charging rates not authorized by the CPUC. On March 14, 2016, the assigned ALJ issued an additional ruling that (1) acknowledged that utilities might not be able to follow the exact “glidepath” set forth in the decision because it had been based on forecast data and (2) indicated a new process to be followed before the CPUC if the new rates do not exactly match the “glidepath.” On March 24, 2016, the Utility temporarily reverted back to billing customers based on rates generally similar to those in place prior to March 1, 2016. Also, on March 24, 2016, the Utility filed an additional advice letter proposing a new, three-tiered rate structure. The proposed new rate structure is subject to the CPUC approval. On April 20, 2016, the Energy Division of the CPUC issued a draft resolution that approves the Utility’s proposed solution, but does not address the ruling to show cause. The Utility believes it is reasonably possible it may be subject to penalties or shareholder reparations for charging rates not authorized by the CPUC between March 1, 2016 and March 24, 2016. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred.

Other Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled $55 million at March 31, 2016 and $63 million at December 31, 2015. These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following:

	Balance at
	March 31,		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	302	$	300
Hinkley natural gas compressor station (1)		140		140
Former manufactured gas plant sites owned by the Utility or third parties		283		271
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		136		164
Fossil fuel-fired generation facilities and sites		103		94
Total environmental remediation liability	$	964	$	969

(1) See “Natural Gas Compressor Station Sites” below.

At March 31, 2016, the Utility expected to recover $680 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility also is required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the Regional Board. On November 4, 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets.

The Utility’s environmental remediation liability at March 31, 2016 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to be performed to implement the final remediation plan and the Utility’s required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016. After the Utility modifies its design in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017.

The Utility’s environmental remediation liability at March 31, 2016 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility’s required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

Reasonably Possible Environmental Contingencies

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 $1.9 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. 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 results of operations, future financial condition, and cash flows during the period in which they are recorded.

Nuclear Insurance

In addition to the nuclear insurance the Utility maintains through the NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non- nuclear event were to occur at Diablo Canyon.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of April 1, 2016, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $60 million. EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $2.1 million, as of April 1, 2016. For more information about the Utility’s NEIL coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.

Resolution of Remaining Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers.

At December 31, 2015, the Consolidated Balance Sheets reflected $454 million in net claims, within Disputed claims and customer refunds, and $228 million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash. There were no significant changes to these balances during the three months ended March 31, 2016. However, on April 14, 2016, PG&E filed a Joint Offer of Settlement with the FERC requesting approval of a $256 million settlement agreement which, if approved, would result in a reduction to PG&E’s net disputed claims liability.

Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of March 31, 2016, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

Purchase Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2015 the Utility had undiscounted future expected obligations of approximately $50 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.) The Utility has not entered into any new material commitments during the three months ended March 31, 2016.