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. 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. A gain contingency is recorded in the period in which all uncertainties have been resolved. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. 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

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 March 2017, the Utility received a demand from Cal Fire indicating that it will seek to recover firefighting costs of $87 million from the Utility, and on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover its costs on the theory that the Utility and its vegetation management contractors were negligent, among other claims. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. In addition, the Utility anticipates that other agencies, including the California Governor’s Office of Emergency Services and the County of Calaveras, may also submit claims against the Utility.

Also, on April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED’s investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. (See “Potential Safety Citations” below.)

As previously disclosed, 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 March 31, 2017, approximately 55 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 2,000 individual plaintiffs representing approximately 1,150 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 .

On April 14, 2017, the Superior Court of California for Sacramento County found that six “preference” households (households that include individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling) are entitled to a trial no later than August 11, 2017. The court did not decide on the venue of the preference trial.

The court also set a representative trial date for October 30, 2017 in Sacramento. A representative trial is a trial where the parties agree, or the court decides, on plaintiffs who are “representative” of broader groups of plaintiffs such that the trial may assist the parties in settling other cases after obtaining verdicts in the representative trial. The next case management conference is scheduled for May 11, 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 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 Condensed Consolidated Balance Sheets:

Loss Accrual (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690
Accrued losses		-
Payments		(44)
Balance at March 31, 2017	$	646

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $37 million. For the three months ended March 31, 2017, the Utility has incurred legal expenses of $10 million.

The Utility currently is 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. Through March 31, 2017, the Utility recorded $632 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 Condensed Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Insurance reimbursements		(50)
Balance at December 31, 2016	$	575
Accrued insurance recoveries		7
Insurance reimbursements		-
Balance at March 31, 2017	$	582

On April 28, 2017 the Utility received another $50 million in insurance reimbursements.

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.

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

On March 28, 2017, the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN (together, the “parties”) jointly submitted to the CPUC a settlement agreement in connection with the order instituting an investigation into the Utility’s compliance with the CPUC’s ex parte communication rules and jointly moved for its approval. As previously disclosed, the Utility has already incurred a disallowance of $72 million imposed by the CPUC in connection with certain ex parte communications in the Utility’s 2015 GT&S rate case. Of the $72 million total GT&S ex parte disallowance, $57 million was recognized in 2016 and the remaining $15 million was recognized in the first quarter of 2017.

Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $86.5 million comprised of: (1) a $1 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over its next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

The CPUC may accept, reject, or modify the terms of the settlement agreement, including imposing additional penalties on the Utility. On May 1, 2017, a PD was issued extending the statutory deadline for this proceeding from May 17, 2017 to December 29, 2017. The PD is on the CPUC’s May 11, 2017 meeting agenda. The Utility is unable to predict the outcome of this proceeding.

At March 31, 2017, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $13 million accrual for the portions of the settlement agreement that would be payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the periods in which they are incurred.

For more information about the proceeding, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

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 CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, that the SED has yet to act upon. This includes the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will impose penalties or take other enforcement action with respect to some of these violations. 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.

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, with an administrative limit of $8 million per citation issued. 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 also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED has historically exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even after the SED has issued a citation. 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.

On April 25, 2017, the SED issued two citations totaling $8.3 million to the Utility in connection with the Butte fire. The SED’s investigation found that neither the Utility nor its contractors took appropriate steps to remedy the condition and consequences when two gray pine trees in a stand were removed and that appropriate steps were not taken to prevent a remaining gray pine from leaning and contacting the Utility’s electric line. The SED concluded that this failure created an unsafe and dangerous condition that resulted in the remaining gray pine tree leaning and making contact with the electric line, thus causing a fire. The SED issued a first citation to the Utility for $8 million, for failing to maintain its electric line safely and properly. According to the citation, this violation began in January 2015, when the Utility and/or its contractors first failed to identify that the planned removal of the two nearby trees would allow the remaining gray pine tree to become hazardous and make contact with the Utility’s electric line. The SED also issued a second citation to the Utility for a total of $300,000 for two violations, including a $250,000 citation for failure to timely report to the CPUC that the Utility’s facilities may have been linked to the ignition of the Butte fire, and a $50,000 citation for failing to maintain the minimum required clearance of 18 inches between the electric line and the remaining gray pine tree. The Utility has 30 calendar days (until May 25, 2017) to pay or appeal the citations.

Federal Investigations

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

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 $48 million at March 31, 2017 and $45 million at December 31, 2016. 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.

Disallowance of Plant Costs

The Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. 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 related to its 2015 GT&S rate case. PG&E Corporation and the Utility would 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 Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

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)	2017		2016
Topock natural gas compressor station (1)	$	296	$	299
Hinkley natural gas compressor station (1)		132		135
Former manufactured gas plant sites owned by the Utility or third parties		308		285
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		133		131
Fossil fuel-fired generation facilities and sites		111		108
Total environmental remediation liability	$	980	$	958

(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 March 31, 2017 reflects its best estimate of probable future costs associated with its final remediation plans. 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 March 31, 2017, the Utility expected to recover $696 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 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 by as much as $1 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 maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non- nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. 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, 2017, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $58 million. EMANI provides $200 million for any one accident and in the annual aggregate the 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 $3.3 million, as of April 1, 2017. For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 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. 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. 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.

At March 31, 2017 and December 31, 2016, the Condensed Consolidated Balance Sheets reflected $236 million, respectively, in net claims within Disputed claims and customer refunds. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.

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 audits. As of March 31, 2017, it is reasonably possible that unrecognized tax benefits will decrease by approximately $60 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

Gain Contingencies

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of March 31, 2017, there were seven shareholder derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by certain current and former officers and directors (the “Individual Defendants”), among other claims. Four of the cases were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo (the “Court”). The remaining three cases are Tellardin v. Anthony F. Earley, Jr., et al., Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo, et al. (the “Additional Derivative Cases”).

On March 15, 2017, the parties in the San Bruno Fire Derivative Cases filed with the Court a settlement that they reached to resolve the consolidated shareholder derivative lawsuit and certain additional claims against the Individual Defendants. Pursuant to the settlement stipulation, subject to certain conditions: (1) the Individual Defendants’ directors and officers liability insurance carriers will pay $90 million to PG&E Corporation within 11 business days of the entry of the judgment approving settlement in the San Bruno Fire Derivative Cases, (2) PG&E Corporation and the Utility will implement certain corporate governance therapeutics for five years, and (3) the Utility will implement certain gas operations therapeutics and maintain certain of them for three years, at an estimated cost of up to approximately $32 million.

In addition, PG&E Corporation agreed to pay any fee and expense award that the Court may grant to counsel for the plaintiffs in the San Bruno Fire Derivative Cases in an amount not to exceed $25 million for fees and $500,000 for expenses. PG&E Corporation and the Utility also agreed, under their indemnification obligations to the Individual Defendants, to pay $18.3 million of the Individual Defendants’ costs, fees, and expenses incurred in connection with responding to, defending and settling the San Bruno Fire Derivative Cases and the Additional Derivative Cases, including certain fees and expenses for investigating these claims. The $18.3 million has been paid, with the majority reflected in PG&E Corporation’s and the Utility’s financial statements through December 31, 2016.

The settlement is expressly conditioned on, among other things, the Additional Derivative Cases being dismissed with prejudice, which condition can only be waived by PG&E Corporation and a majority of the Individual Defendants.

The settlement is subject to the Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing took place on April 21, 2017. At this hearing, PG&E Corporation and the Utility agreed that notwithstanding the expiration of the five-year and three-year periods applicable to the corporate and gas operations therapeutics described above, neither entity will make any material changes to such therapeutics unless those changes are reported in PG&E Corporation’s Corporate Responsibility and Sustainability Report or another suitable report at least three months prior to their taking effect. With this modification, the Court preliminarily approved the settlement, preliminarily finding it fair, reasonable, adequate, and in the best interests of PG&E Corporation, the Utility, and the shareholders of PG&E Corporation.

The final approval hearing has been set for July 18, 2017. If the Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.

There was no impact on PG&E Corporation or the Utility’s Condensed Consolidated Financial Statements in the quarter ended March 31, 2017. If the settlement is approved, PG&E Corporation estimates it will record $64.5 million in insurance proceeds in the period the settlement becomes effective.

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, 2016, the Utility had undiscounted future expected obligations of approximately $47 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.) The Utility has not entered into any new material commitments during the three months ended March 31, 2017.