NOTE 13: 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. 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. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially 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 occurred 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 CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

On October 14, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility submitted a status report to the CPUC which proposed an update to the framework for resolving the proceeding. The revised framework includes a total of 164 communications in the scope of the proceeding. Throughout 2016, the parties jointly submitted stipulations on all of the communications, and on November 30, 2016, the parties began settlement discussions. In the event a settlement cannot be reached, the parties will brief the matter based upon the identified communications and some related discovery as well as factual stipulations and agreed upon issues of policy and law for CPUC resolution. The opening briefs are due on March 24, 2017, and reply briefs are due on April 14, 2017.

The Utility expects that the other parties may argue that the number of violations exceeds the 164 communications referenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications. The Utility expects to contest many of these assertions. If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules. The CPUC will also determine whether to impose penalties or other remedies, as a result of a potential settlement or otherwise. The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing. 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 broad discretion in determining whether violations are continuing and the amount of penalties to be imposed.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII. In light of recent CPUC decisions, such as the Penalty Decision and the decision in the 2015 GT&S rate case, the Utility expects that such penalties could include fines and future revenue requirement reductions. In accordance with accounting rules, revenue requirement reductions would be recorded in the period they are 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 because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations.

Finally, in 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. 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 required 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 cited 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 August 18, 2016, the CPUC approved a final decision in this investigation. The CPUC assessed a fine of $25.6 million. With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million. The remaining $25.6 million was paid in September 2016. The decision denied the appeals previously filed by the SED and Carmel from the presiding officer’s decision, and closed this proceeding but allowed the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties.

On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision. Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including those related to the missing De Anza records violations) and certain other findings, and requests that the CPUC adopt its recommendations. On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC. The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations.

On October 24, 2016 and November 30, 2016, the Utility held meet and confer sessions with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan. On December 16, 2016, the Utility submitted its Initial Gas Distribution Records Compliance Plan that includes feasible and cost-effective measures necessary to improve natural gas distribution system record-keeping.

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. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. 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. There is also an administrative limit of $8 million per citation issued.

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 penalties or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations, based on the SED’s investigations of incidents reported to the CPUC, or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits or investigations. 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 and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel. The Utility did not provide timely notification of such non-compliance to the CPUC. On December 23, 2016, the SED issued the Utility a citation with a $5.45 million fine related to this self-report. The citation included a $5.05 million fine for not ensuring that contractor inspectors were operator-qualified, a $350,000 fine for not completing inspections within 39 months from the previous inspections, and a $50,000 fine for not reporting the self-identified violations within ten days of discovery. The amount of the fine is conditioned upon the Utility implementing certain remedial measures. The Utility paid the fine in January 2017.

In February 2017, the Utility reported that it discovered in April 2014 that customer service representatives who handle gas emergency calls within the Utility’s call centers are not included in the drug and alcohol testing program as required by PHMSA regulations. The Utility did not provide timely notification of such non-compliance to the CPUC. The SED could impose fines on the Utility of $50,000 per violation, and also for failure to timely file a self-report in connection with the non-compliance. The SED has the authority to issue more than one citation for a series of related incidents and can impose daily fines for continuing violations, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding.

Federal Matters

Federal Criminal Trial

On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 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, and one felony count charging that the Utility obstructed the NTSB investigation into the cause of the San Bruno accident. On July 26, 2016, the court granted the government’s motion to dismiss one count alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 9, 2016, the jury returned its verdict. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.

On January 26, 2017, the court issued a judgment of conviction sentencing the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service. The Utility has decided not to appeal the convictions. The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility is required to retain a third-party monitor. The goal of the monitorship will be to prevent the criminal conduct with respect to gas pipeline transmission safety that gave rise to the conviction. To that end, the goal of the monitor will be to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of the gas transmission pipeline system, performs appropriate integrity management assessments on its gas transmission pipelines, and maintains an effective ethics and compliance program and safety related incentive program.

After an initial assessment is conducted and an initial report is prepared by the monitor, the monitor will prepare reports on a semi-annual basis setting forth the monitor’s continued assessment and making recommendations consistent with the goals and scope of the monitorship. The Utility expects that the monitor will be retained before the end of the second quarter of 2017.

At December 31, 2016, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $3 million accrual in connection with this matter. On February 1, 2017, the Utility paid the $3 million fine imposed by the court. The Utility could incur material costs, not recoverable through rates, in the event of non-compliance with the terms of probation and in connection with the monitorship (including but not limited to the monitor’s compensation or costs resulting from recommendations of the monitor).

Other Federal Matters

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

Other Matters

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. 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/or its vegetation management contractors, ACRT Inc. and Trees, Inc., 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.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2016, complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,950 individual plaintiffs representing approximately 950 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. The number of individual complaints and plaintiffs may increase in the future.

The Utility continues mediating and settling cases . The next case management conference is scheduled for March 2, 2017.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees 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. The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility. The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence.

The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Loss Accrual (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $27 million.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of $750 million accrued through December 31, 2016 but is currently unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. The Utility has recorded $625 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility is pursuing coverage under the insurance policies of its two vegetation management contractors, including under policies where the Utility is listed as an additional insured. Recoveries of any amounts under these policies are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Reimbursements		(50)
Balance at December 31, 2016	$	575

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.

Other Contingencies

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $45 million at December 31, 2016 and $63 million at December 31, 2015. These amounts are included in Other current liabilities in the 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.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operating and maintenance expenses in the Consolidated Statements of Income. Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision and December 1, 2016 final phase two decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below.

2015 GT&S Rate Case Disallowance of Capital Expenditures

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts. As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.

Penalty Decision’s Disallowance of Natural Gas Capital Expenditures

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings 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 pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures. The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty.

For the twelve months ended December 31, 2016, the Utility recorded charges for disallowed capital spending of $283 million as a result of the Penalty Decision. The cumulative charges at December 31, 2016, and the additional future charges that will be recognized in the first quarter of 2017 are shown in the following table:


	Twelve Months		Cumulative		Future
	Ended		Charges		Charges
		December 31,		December 31,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		283		689		-		689
Disallowed revenue for pipeline safety
expenses (2)		129		129		32		161
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	412	$	1,518	$	32	$	1,600

(1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs. On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate case which allocates $689 million of the $850 million penalty to capital expenditures.

(2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first quarter of 2017.

(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. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated future remedy-related costs.

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 December 31, 2016, the Utility has spent $1.35 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2017. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

Environmental Remediation Contingencies

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

	Balance at
	December 31		December 31,
(in millions)	2016		2015
Topock natural gas compressor station (1)	$	299	$	300
Hinkley natural gas compressor station (1)		135		140
Former manufactured gas plant sites owned by the Utility or third parties		285		271
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		131		164
Fossil fuel-fired generation facilities and sites		108		94
Total environmental remediation liability	$	958	$	969

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

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 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 implement final remediation plans 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.

At December 31, 2016 the Utility expected to recover $671 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review. The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

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 Needles, California and is referred to below as the “Topock site.” Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI.

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 conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in mid-2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in late 2017 or early 2018.

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. In November 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.

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 Topock and Hinkley 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, financial condition and cash flows during the period in which they are recorded.

Nuclear Insurance

The Utility is a member of 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 if a nuclear event were to occur 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 and $2.6 billion per non-nuclear incident for Diablo Canyon. Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides 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.

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 December 31, 2016, the current maximum aggregate annual retrospective premium obligation for the Utility would be 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 million, as of December 31, 2016.

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 $13.5 billion. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $13.5 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 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 September 10, 2018.

The Price-Anderson Act does not apply to 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. The Utility has a separate 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 liability insurance.

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. While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. 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. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. In connection with the CPUC approved settlement agreement, on April 12, 2004, the Utility deposited approximately $1.7 billion into escrow for the payment of certain disputed claims, previously collected from customers through rates. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

On October 13, 2016, the Utility received approval from the bankruptcy court to release the remaining cash held in escrow to unrestricted cash for use by the Utility. The approval resulted in a $161 million reduction to the cash in escrow within the Restricted cash balance on the Consolidated Balance Sheets.

On September 2, 2016, the Utility’s settlement became effective resolving, among other matters, the Utility’s claim against the CAISO for $165 million, which includes receivables and interest. Additionally, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange. The settlement resulted in a $231 million reduction to the Disputed claims and customer refunds balance on the Consolidated Balance Sheets.

At December 31, 2016 and December 31, 2015, respectively, the Consolidated Balance Sheets reflected $236 million and $454 million in net claims within Disputed claims and customer refunds. The cash held in escrow within Restricted cash was zero as of December 31, 2016 and $228 million as of December 31, 2015. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2016:

	Power Purchase Agreements
	Renewable		Conventional				Natural		Nuclear
(in millions)	Energy		Energy		Other		Gas		Fuel		Total
2017	$	2,233	$	815	$	369	$	536	$	97	$	4,050
2018		2,108		716		284		169		93		3,370
2019		2,144		698		225		160		95		3,322
2020		2,139		677		179		148		130		3,273
2021		2,117		585		147		93		49		2,991
Thereafter		27,685		1,168		653		455		136		30,097
Total purchase
commitments	$	38,426	$	4,659	$	1,857	$	1,561	$	600	$	47,103

Third-Party Power Purchase Agreements

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

Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2016, renewable energy contracts expire at various dates between 2017 and 2043.

Conventional Energy Power Purchase Agreements. The Utility has entered into many 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. As of December 31, 2016, these power purchase agreements expire at various dates between 2017 and 2033.

Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. Several of these agreements are treated as capital leases. At December 31, 2016 and 2015, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $35 million and $54 million including accumulated amortization of $148 million and $147 million, respectively. The present value of the future minimum lease payments due under these agreements included $17 million and $19 million in Current Liabilities and $18 million and $35 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2016, QF contracts in operation expire at various dates between 2017 and 2028. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The costs incurred for all power purchases and electric capacity amounted to $3.5 billion in 2016, $3.5 billion in 2015, and $3.6 billion in 2014.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2017 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.7 billion in 2016, $0.9 billion in 2015, and $1.4 billion in 2014.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2017 and 2025 and are intended to ensure long-term nuclear fuel supply. 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 nuclear fuel amounted to $100 million in 2016, $128 million in 2015, and $105 million in 2014.

Other Commitments

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2017 and 2052. At December 31, 2016, the future minimum payments related to these commitments were as follows:

(in millions)	Operating Leases
2017	$	44
2018		41
2019		39
2020		39
2021		36
Thereafter		168
Total minimum lease payments	$	367

Payments for other commitments related to operating leases amounted to $43 million in 2016, $41 million in 2015, and $42 million in 2014. Certain leases on office facilities contain escalation clauses requiring annual increases in rent. 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 operations ranging between one and five years.