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•	deferred consideration of replacement resources to the CPUC’s Integrated Resource Planning proceeding;

•	authorized rate recovery for up to $211.3 million (compared with the $352.1 million requested by the Utility) for an employee retention program;

•	authorized rate recovery for an employee retraining program of $11.3 million requested by the Utility;

•	rejected rate recovery of the proposed $85 million for the community impacts mitigation program on the grounds that rate recovery for such a program requires legislative authorization;

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authorized rate recovery of $18.6 million of the total Diablo Canyon license renewal cost of $53 million and rate recovery of canceled project costs equal to 100% of direct costs incurred prior to June 30, 2016, and 25% of direct costs incurred after June 30, 2016, based on a provision of the settlement agreement among the Utility, the Joint Parties, and certain other parties that the Utility filed with the CPUC in May 2017; and

•	approved the amortization of the book value for Diablo Canyon consistent with the Diablo Canyon closure schedule.

•	approving the community impact mitigation settlement of $85 million, originally proposed in the joint settlement agreement;

•	deferring implementation to its Integrated Resource Planning to ensure that there is no increase in GHG emissions as a result of the Diablo Canyon retirement; and

•	approving full funding of the $352.1 million Diablo Canyon employee retention program, originally proposed in the joint settlement agreement.

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•	the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility during the Chapter 11 Cases;

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the ability to develop and obtain applicable Bankruptcy Court, creditor, and regulatory approval of a successful plan of reorganization and the effect of any alternative proposals, views, and objections of official committees, creditors, state and federal regulators, and other stakeholders, which may make it difficult to develop and consummate a successful plan of reorganization in a timely manner;

•	the ability to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 Cases and the outcomes of Bankruptcy Court rulings and of the Chapter 11 Cases in general;

•	risks associated with third-party motions or adversary proceedings in the Chapter 11 Cases, which may interfere with business operations, including additional collateral requirements, or the ability to formulate and implement a plan of reorganization;

•	increased costs related to the Chapter 11 Cases and related litigation;

•	potential for an increase in general unsecured claims as a result of the rejection of any executory contracts or unexpired leases as permitted under the Bankruptcy Code;

•	the ability to maintain or obtain sufficient financing sources for ongoing operations during the pendency of the Chapter 11 Cases or thereafter or to fund a plan of reorganization and meet future obligations, including commitments outlined in the Utility's 2020 GRC and other regulatory proceedings;

•	the potential for a material decrease in the number of counterparties that are willing to engage in transactions, including commodity-related transactions, with PG&E Corporation or the Utility and a significant increase in the amount of collateral required to engage in any such transactions;

•	the potential for a loss of, or a disruption in the materials or services received from, suppliers, contractors or service providers with whom the Utility has commercial relationships or adverse developments in the commercial and financial terms on which such providers engage in such relationships with PG&E Corporation and the Utility;

•	risks associated with the potential that the Utility will not be able to comply with the capital structure requirements authorized by the CPUC, to the extent applicable, during the pendency of the Chapter 11 Cases or thereafter;

•	potential increased difficulty in retaining and motivating key employees and potential increased difficulty in attracting new employees during the pendency of the Chapter 11 Cases and thereafter;

•	the significant time and effort required to be spent by senior management in dealing with the Chapter 11 Cases and restructuring activities rather than focusing exclusively on business operations; and

•	the ability to continue as a going concern.

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•	sell assets outside the normal course of business;

•	make capital investments outside the normal course of business;

•	consolidate or merge or sell or otherwise dispose of assets outside the normal course of business;

•	grant liens; and

•	finance operations, investments or other capital needs or engage in other business activities, including the ability to achieve California’s renewable energy goals.

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•	the ability of PG&E Corporation and the Utility to raise additional capital;

•	PG&E Corporation’s and the Utility’s liquidity;

•	how PG&E Corporation’s and the Utility’s business is viewed by regulators, investors, lenders and credit ratings agencies;

•	PG&E Corporation’s and the Utility’s enterprise value; and

•	PG&E Corporation's and the Utility's ability to continue as a going concern.

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•	the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines, that can cause explosions, fires, or other catastrophic events;

•	an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow;

•	the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;

•	a prolonged statewide electrical black-out that results in damage to the Utility’s equipment or damage to property owned by customers or other third parties;

•	the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage;

•	the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;

•	the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;

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•	the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wild land fire or natural gas explosion);

•	inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;

•	operator or other human error;

•	an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently;

•	construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines;

•	the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and

•	attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.

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prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires”,

•	“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and

•	at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

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The Outcome of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, PG&E Corporation’s and the Utility’s business is subject to the risks and uncertainties of bankruptcy. For example, the Chapter 11 Cases could adversely affect the Utility’s relationships with suppliers and employees which, in turn, could adversely affect the value of the business and assets of PG&E Corporation and the Utility. PG&E Corporation and the Utility also expect to incur increased legal and other professional costs associated with the Chapter 11 Cases and the reorganization. At this time, it is not possible to predict with certainty the effect of the Chapter 11 Cases on their business or various creditors, or whether or when PG&E Corporation and the Utility will emerge from bankruptcy. PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity and cash flows depend upon confirming, and successfully implementing, on a timely basis, a plan of reorganization.

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The Utility’s Ability to Fund Ongoing Operations and Other Capital Needs. In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available. The remainder of the DIP Facilities are unavailable for borrowing and will remain unavailable until and unless the Bankruptcy Court approves the availability thereof following a final hearing.  For the duration of the Chapter 11 Cases, PG&E Corporation and the Utility expect that the DIP Credit Agreement, together with cash on hand, cash flow from operations and distributions received from subsidiaries, will be the Utility’s primary source of capital to fund ongoing operations and other capital needs and that they will have limited, if any, access to additional financing. In the event that cash on hand, cash flow from operations, distributions received from subsidiaries, and availability under the DIP Credit Agreement are not sufficient to meet these liquidity needs, PG&E Corporation and the Utility may be required to seek additional financing, and can provide no assurance that additional financing would be available or, if available, offered on acceptable terms.  The amount of any such additional financing could be limited by negative covenants in the DIP Credit Agreement, which include restrictions on PG&E Corporation's and the Utility's ability to, among other things, incur additional indebtedness and create liens on assets.

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The Impact of Wildfires.  PG&E Corporation and the Utility face several uncertainties in connection with the 2018 Camp fire and 2017 Northern California wildfires, related to: the amount of possible loss related to third-party claims (in 2018, the Utility recorded total charges of $13.4 billion, which reflects the low end of the range of reasonably estimated losses and is subject to change based on additional information), which aggregate possible losses, if the Utility were found liable for certain or all of the costs, expenses and other losses in connection with the 2018 Camp fire and 2017 Northern California wildfires (other than potential punitive damages, fines and penalties or damages related to future claims), could exceed $30 billion; punitive damages, which could be material; fines or penalties, which could be material, if the CPUC or any law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations; the amount of damages in respect of future claims, which could be material; the applicability of the doctrine of inverse condemnation in the 2018 Camp fire and 2017 Northern California wildfires litigation, which the Utility intends to continue to challenge during the pendency of its Chapter 11 Case; the applicability of other theories of liability, including negligence, related to the 2018 Camp fire and 2017 Northern California wildfire claims; the recoverability of the above mentioned costs, even if a court decision imposes liability under the doctrine of inverse condemnation; the amount of the Customer Harm Threshold under SB 901 and the timing of any recovery by the Utility in excess of the Customer Harm Threshold in a proceeding before the CPUC; and recoverability of clean-up and repair costs (the Utility incurred costs of $681 million for clean-up and repair of the Utility’s facilities through December 31, 2018). (See Notes 3 and 13 of the Notes to the Consolidated Financial Statements in Item 8 and Item 1A. Risk Factors.)

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The Outcome of Other Enforcement, Litigation, and Regulatory Matters. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation (to the extent not stayed as a result of the Chapter 11 Cases), and regulatory matters, including the outcome of the Locate and Mark OII, phase two of the Safety Culture OII, the outcome of phase two of the ex parte OII, the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, including the oversight of the Utility’s probation and the potential recommendations by the third-party monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Notes 13 and 14 of the Notes to the Consolidated Financial Statements in Item 8.)

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The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, future cost of capital proceedings, and its ability to timely recover costs not in rates already incurred and to be incurred in the future, including those tracked in its CEMA, WEMA, FHPMA and the Utility's 2019 Wildfire Safety Plan. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors. (See Notes 3 and 14 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below.)

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The Utility’s Compliance with the CPUC Capital Structure. The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more. The CPUC’s decisions state that the Utility shall not be considered in violation of these conditions during the period the waiver application is pending resolution. Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility intends to submit to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval. The Utility is unable to predict the timing and outcome of its waiver application.

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•	the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see Note 13 and “Enforcement and Litigation Matters” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. and Item 3. Legal Proceedings for more information);

•	the timing and amount of premium payments related to wildfire insurance (see “Wildfire Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information);

•	the Tax Act, which may accelerate the timing of federal tax payments and reduce revenue requirements, resulting in lower operating cash flows depending on the timing of wildfire payments (see Note 8 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below for more information);

•	the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2018 CEMA filing, 2020 Cost of Capital, NDCTP, and other ratemaking and regulatory proceedings; and

•	the timing and amount of substantially increasing costs in connection with the 2019 Wildfire Safety Plan (see “Overview” above and “Regulatory Matters” below for more information).

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•	a two-way electric and gas Risk Transfer Balancing Account to record the difference between the amounts adopted for liability insurance premiums and the Utility's actual costs; this two-way account would allow the Utility to pass-through actual insurance costs for up to $2 billion in coverage and return to customers any overcollection if forecast costs exceed actuals costs; and

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a two-way Wildfire Safety Balancing Account to track and record actual incremental expenses and capital revenue requirements associated with the incremental costs of fire risk mitigation work that are not already addressed and recorded in another account; this would include the costs associated with overhead system hardening, enhanced vegetation management, and other incremental costs of wildfire mitigations that are approved by the CPUC in the Utility's annual wildfire mitigation plan. In accordance with SB 901, the Utility submitted its first Wildfire Safety Plan to the CPUC on February 6, 2019.

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•	Installing nearly 600 new, high-definition cameras, made available to Cal Fire and local fire officials, in high fire-threat areas by 2022, increasing coverage across high fire-threat areas to more than 90%;

•	Adding approximately 1,300 additional new weather stations by 2022, at a density of one station roughly every 20 circuit miles in high fire-threat areas;

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•	Conducting enhanced safety inspections of electric infrastructure in high-fire threat areas, including approximately 735,000 electric towers and poles across approximately 5,700 transmission line miles and 25,200 distribution line miles;

•	Further enhancing vegetation management efforts across high and extreme fire-threat areas to address vegetation that poses higher potential for wildfire risk, such as removing or trimming trees from particular 'at-risk' tree species that have exhibited a higher pattern of failing;

•	Continuing to disable automatic reclosing in high fire-threat areas during wildfire season and periods of high fire-risk and upgrading more reclosers and circuit breakers in high fire-threat areas with remote control capabilities

•	Installing stronger and more resilient poles and covered power lines, including targeted undergrounding, starting in areas with the highest fire risk, ultimately upgrading and strengthening approximately 7,100 miles over the next 10 years; and

•	Partnering with additional communities in high fire-threat areas to create new resilience zones that can power central community resources during a Public Safety Power Shutoff.

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•	how to define climate change adaption for the IOUs;

•	the climate-driven risks facing the IOUs;

•	data, tools, resources, and guidance to instruct utilities on how to incorporate adaption in their existing planning and operational processes; and

•	strategies to address climate change in CPUC proceedings, including impacts on disadvantaged communities.

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•	adopting benchmark values used to set the PCIA rate that more closely resemble actual market prices for resource adequacy and renewable energy credits;

•	continuing to allow legacy utility-owned generation costs to be recovered from CCA customers;

•	eliminating the 10-year limit on PCIA cost recovery for post-2002 utility owned generation and certain storage costs; and

•	adding an annual true-up to the PCIA rate based on market sales.

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the risks and uncertainties associated with the Chapter 11 Cases, including, but not limited to, the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility, the ability to develop and obtain applicable Bankruptcy Court, creditor or regulatory approvals, the effect of any alternative proposals, views or objections related to the plan of reorganization, potential complexities that may arise in connection with concurrent proceedings involving the Bankruptcy Court, the U.S. District Court, the CPUC, and the FERC, increased costs related to the Chapter 11 Cases, the ability to obtain sufficient financing sources for ongoing and future operations, disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance;

•	restrictions on PG&E Corporation’s and the Utility’s ability to pursue strategic and operational initiatives for the duration of the Chapter 11 Cases;

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•	increased employee attrition as a result of the filing of the Chapter 11 Cases;

•	PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases;

•	the potential delay in emergence from bankruptcy if PG&E Corporation and the Utility are not able to develop and consummate a consensual plan of reorganization and are forced to engage in a contested proceeding;

•	the possibility that the DIP Credit Agreement is not sufficient to fund PG&E Corporation’s and the Utility’s cash requirements through their emergence from bankruptcy;

•	the possibility that PG&E Corporation and the Utility may not be able to obtain exit financing on favorable terms or at all;

•	the outcome of the U.S. District Court matters and probation;

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the impact of the 2018 Camp fire and the 2017 Northern California wildfires, including whether the Utility will be able to timely recover costs incurred in connection with the wildfires in excess of the Utility’s currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liability associated with these fires; the timing and amount of insurance recoveries; and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action and determined that the Utility failed to comply with applicable laws and regulations;

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the timing and outcome of claims arising from the 2015 Butte fire and the timing and outcome of any proceeding to recover related costs in excess of insurance through rates; the effect, if any, that the SED’s $8.3 million citations issued in connection with the 2015 Butte fire may have on the claims arising from the 2015 Butte fire; and whether additional investigations and proceedings in connection with the 2015 Butte fire will be opened and any additional fines or penalties imposed on the Utility;

•	the timing and outcome of issuance of recovery bonds ("securitization") of 2017 Northern California wildfires costs that the CPUC finds just and reasonable;

•	whether PG&E Corporation and the Utility are able to successfully challenge the application of the doctrine of inverse condemnation to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire;

•	the timing and outcome of future regulatory and legislative developments in connection with SB 901, including the Customer Harm Threshold in connection with the 2017 Northern California wildfires, future wildfire reforms, inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures or other reforms targeted at the Utility;

•	the outcome of the Utility’s community wildfire safety program that the Utility has developed in coordination with first responders, civic and community leaders, and customers, to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather; and the cost of the program, and the timing and outcome of any proceeding to recover such cost through rates;

•	whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery;

•	whether the Utility can obtain wildfire insurance at a reasonable cost in the future, or at all, and whether insurance coverage is adequate for future losses or claims;

•	the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, future applications for WEMA and FHPMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings;

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the outcome of the probation and the monitorship imposed by the federal court after the Utility’s conviction in the federal criminal trial in 2017, the timing and outcomes of the debarment proceeding, potential reliability penalties or sanctions from the North American Electric Reliability Corporation, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

•	the effects on PG&E Corporation’s and the Utility’s reputations caused by the CPUC’s investigations of natural gas and electric incidents, the 2018 Camp fire and 2017 Northern California wildfires, locate and mark, improper communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

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the implementation of the Safety Culture OII decision approved on November 29, 2018, and the outcome of its phase two proceeding, and future legislative or regulatory actions that may be taken, such as requiring the Utility to separate its electric and natural gas businesses, or restructure into separate entities, or undertake some other corporate restructuring, or implement corporate governance changes;

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whether the Utility can control its costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve project savings, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

•	whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and information technology systems from cyber- and physical attacks, or other internal or external hazards;

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the timing and outcome of the October 1, 2018 request for rehearing of FERC’s denial of the complaint filed by the CPUC and certain other parties that the Utility provide an open and transparent planning process for its capital transmission projects that do not go through the CAISO’s Transmission Planning Process to allow for greater participation and input from interested parties; and the timing and ultimate outcome of the Ninth Circuit Court of Appeals decision on January 8, 2018, to reverse FERC’s decision granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO and remanding the case to FERC for further proceedings;

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the outcome of current and future self-reports, investigations, or other enforcement proceedings that could be commenced or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion, or replacement of its electric and gas facilities, electric grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations;

•	the timing and outcome of any CPUC action in connection with the Utility’s SmartMeter™ Upgrade cost-benefit analysis;

•	the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources;

•	the impact of SB 100, which was signed into law on September 10, 2018, that increases the percentage from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and establishes state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045;

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how the CPUC and the California Air Resources Board implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;

•	the impact of the California governor’s executive order issued on January 26, 2018, to implement a new target of five million zero-emission vehicles on the road in California by 2030;

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•	the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

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the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of potential actions, such as legislation, taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

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the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

•	whether the Utility’s climate change adaptation strategies are successful;

•	the breakdown or failure of equipment that can cause damages, including fires, and unplanned outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;

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the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural gas and electric services, and an increasing number of customers departing the Utility’s procurement service for CCAs;

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the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

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the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

•	the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner and on acceptable terms;

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the impact of the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the uncertainty in connection with the 2018 Camp fire and the 2017 Northern California wildfires, the ultimate outcomes of the CPUC’s pending investigations, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation;

•	the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation;

•	changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the current federal administration; and

•	the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

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•	Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

•	Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•	Level 3 – Unobservable inputs which are supported by little or no market activities.

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•	On Cal Fire’s website, Cal Fire has identified coordinates for the 2018 Camp fire near Tower :27/222 on the Utility’s Caribou-Palermo 115 kV Transmission Line and has identified the start time of the 2018 Camp fire as 6:33 a.m. on November 8, 2018.

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On November 8, 2018, at approximately 6:15 a.m., the Utility’s Caribou-Palermo 115kV Transmission Line relayed and deenergized. At approximately 6:30 a.m. that day, a Utility employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by Utility employees. In the afternoon of November 8, the Utility observed damage on the line at Tower :27/222. Specifically, an aerial patrol identified that a suspension insulator supporting a transposition jumper had separated from an arm on Tower :27/222.

•	On November 14, 2018, the Utility observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point. In addition, the Utility observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator.

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In addition to the events on the Caribou-Palermo 115kV Transmission Line, on November 8, 2018, at approximately 6:45 a.m., the Utility’s Big Bend 1101 12 kV Circuit experienced an outage. On November 9, 2018, a Utility employee on patrol arrived at the location of the pole with Line Recloser (“LR”) 1704 on the Big Bend 1101 Circuit and observed that the pole and other equipment were on the ground with bullets and bullet holes at the break point of the pole and on the equipment. On November 12, 2018, a Utility employee was patrolling Concow Road north of LR 1704 when he observed wires down and damaged and downed poles at the intersection of Concow Road and Rim Road. At this location, the employee observed several snapped trees, with some on top of the downed wires.

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prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires”,

•	“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and

•	at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

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1.	The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:

2.	The following financial statement schedules are filed as part of this report:

3.	Exhibits required by Item 601 of Regulation S-K

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