UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM10-Q
(Mark One)
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period endedMarch 31, 2020
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission
File
Number		Exact Name of
Registrant
as Specified
in its Charter		State or Other
Jurisdiction of
Incorporation		IRS Employer
Identification
Number
1-12609PG&E CorporationCalifornia94-3234914
1-2348Pacific Gas and Electric CompanyCalifornia94-0742640
PG&E CorporationPacific Gas and Electric Company
77 Beale Street77 Beale Street
P.O. Box 770000P.O. Box 770000
San Francisco,California94177San Francisco,California94177
Address of principal executive offices, including zip code
PG&E CorporationPacific Gas and Electric Company
415973-1000415973-7000
Registrant’s telephone number, including area code
  
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
  
      FORM10-Q      
(Mark One)            
☒ 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
  
   For the quarterly period ended
June 30, 2019
  
   OR  
☐ 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
  
For the transition period from ___________ to __________
Commission
File
Number
  
Exact Name of
Registrant
as Specified
in its Charter
  
State or Other
Jurisdiction of
Incorporation
 
IRS Employer
Identification
Number
1-12609  PG&E CorporationCalifornia 94-3234914
1-2348  Pacific Gas and Electric CompanyCalifornia 94-0742640
           
PG&E Corporation    Pacific Gas and Electric Company  
77 Beale Street    77 Beale Street  
P.O. Box 770000    P.O. Box 770000  
San Francisco,California94177    San Francisco,California94177  
Address of principal executive offices, including zip code
           
PG&E Corporation    Pacific Gas and Electric Company  
415973-1000      415973-7000  
Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common stock, no par valuePCGThe New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 5% series A redeemablePCG-PENYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemablePCG-PDNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemablePCG-PGNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemablePCG-PHNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemablePCG-PINYSE American LLC
First preferred stock, cumulative, par value $25 per share, 6% nonredeemablePCG-PANYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemablePCG-PBNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemablePCG-PCNYSE American LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
PG&E Corporation:☒Yes☐☒Yes☐No
Pacific Gas and Electric Company:☒Yes☐☒Yes☐No
1

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
PG&E Corporation:☒Yes☐No
Pacific Gas and Electric Company:☒Yes☐No


PG&E Corporation:☒Yes☐No
Pacific Gas and Electric Company:☒Yes☐No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:☒☒Large accelerated filer
☐
Accelerated filer
☐
Non-accelerated filer  
☐Smaller reporting company☐☐Emerging growth company
Pacific Gas and Electric Company:☐☐Large accelerated filer
☐
Accelerated filer
☒
Non-accelerated filer
☐Smaller reporting company☐☐Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PG&E Corporation:☐☐
Pacific Gas and Electric Company:☐☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:☐☐Yes
☒
No
Pacific Gas and Electric Company:☐☐Yes
☒
No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common stock outstanding as of August 2, 2019:April 27, 2020:
PG&E Corporation:529,223,793
529,785,896 
Pacific Gas and Electric Company:
264,374,809
264,374,809 


2

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY, DEBTORS-IN-POSSESSIONDEBTORS-IN-POSSESSION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2019MARCH 31, 2020
TABLE OF CONTENTS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
NOTE 2: BANKRUPTCY FILING
NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
NOTE 5: DEBT
NOTE 6: EQUITY
NOTE 7: EARNINGS PER SHARE
NOTE 8: DERIVATIVES
NOTE 9: FAIR VALUE MEASUREMENTS
NOTE 10: WILDFIRE-RELATED CONTINGENCIES
NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
RESULTS OF OPERATIONS
LIQUIDITY AND FINANCIAL RESOURCES
ENFORCEMENT AND LITIGATION MATTERS
REGULATORY MATTERS
LEGISLATIVE AND REGULATORY INITIATIVES
ENVIRONMENTAL MATTERS
CONTRACTUAL COMMITMENTS
RISK MANAGEMENT ACTIVITIES
RECENT DEVELOPMENTSCRITICAL ACCOUNTING POLICIES
CRITICAL ACCOUNTING POLICIES
ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



3
ITEM 6. EXHIBITS
SIGNATURES



GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
20182019 Form 10-KPG&E Corporation and Pacific Gas and Electric Company’s combined Annual Report on Form 10-K for the year ended December 31, 20182019
2019 Wildfire SafetyMitigation Planthe wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901, previously also referred to as the “2019 Wildfire Safety Plan”
ABAssembly Bill
ALJadministrative law judge
AROasset retirement obligation
ASUaccounting standard update issued by the FASB (see below)
Backstop Partya third-party investor party to a Backstop Commitment Letter
Bankruptcy Codethe United States Bankruptcy Code
Bankruptcy Courtthe U.S. Bankruptcy Court for the Northern District of California
CAISOCalifornia Independent System Operator
Cal FireCalifornia Department of Forestry and Fire Protection
CCACARBCalifornia Air Resources Board
CARECalifornia Alternate Rates for Energy
CCACommunity Choice Aggregator
CCPACEMACalifornia Consumer Privacy Act of 2018
CECCalifornia Energy Resources Conservation and Development Commission
CEMACatastrophic Event Memorandum Account
Chapter 11chapter 11 of title 11 of the U.S. Code
Chapter 11 Casesthe voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CPUCCHTCustomer Harm Threshold
CPUCCalifornia Public Utilities Commission
CRRscongestion revenue rights
CWSPCUECommunity Wildfire Safety ProgramCoalition of California Utility Employees
DACVADirect AccessClimate Vulnerability Assessment
DERDAdistributed energy resourcesDirect Access
Diablo CanyonDiablo Canyon nuclear power plant
DIP Credit AgreementSenior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent
DOGGRDTSCDivision of Oil, Gas, and Geothermal Resources of the California Department of Conservation
DRPDistribution Resource Plan
DTSCDepartment of Toxic Substances Control
EPSearnings per common share
EVFASBelectric vehicle
FASBFinancial Accounting Standards Board
FERCFEMAFederal Emergency Management Agency
FERCFederal Energy Regulatory Commission
FHPMAfire hazard prevention memorandum accountFire Hazard Prevention Memorandum Account
FRMMAfire risk mitigation memorandum accountFire Risk Mitigation Memorandum Account
GAAPFire Victim Trusttrust to be established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) is to be funded
GAAPU.S. Generally Accepted Accounting Principles
GHGGRCgreenhouse gas
GRCgeneral rate case
GT&Sgas transmission and storage
HSMhazardous substance memorandum accountHazardous Substance Memorandum Account
IOU(s)investor-owned utility(ies)
LIBORLondon Interbank Offered Rate
LSTCliabilities subject to compromise


4

MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q
MGP(s)manufactured gas plants
the Monitorthird-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAVnet asset value
NDCTPNuclear Decommissioning Cost Triennial Proceedings
NEILNuclear Electric Insurance Limited
NRCNuclear Regulatory Commission
OESState of California Office of Emergency Services
OIIorder instituting investigation
OIRorder instituting rulemaking
PAOPCIAPublic Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)
PCIAPower Charge Indifference Adjustment
PDPODproposed decisionPresiding Officer’s Decision
PDproposed decision
Petition DateJanuary 29, 2019
PFMpetition for modification
PSAplan support agreement
ROEPSPSPublic Safety Power Shutoff
ROEreturn on equity
ROU assetRSAright-of-use assetrestructuring support agreement (as amended)
SBSenate Bill
SECU.S. Securities and Exchange Commission
SEDSafety and Enforcement Division of the CPUC
Tax ActTax Cuts and Jobs Act of 2017
TCCOfficial Committee of Tort Claimants
TETOtransportation electrificationtransmission owner
TOTURNtransmission owner
TURNThe Utility Reform Network
UCCUtilityOfficial Committee of Unsecured Creditors
USAOUnited States Attorney’s Office for the Northern District of California
UtilityPacific Gas and Electric Company
VIE(s)variable interest entity(ies)
WEMAWildfire Expense Memorandum Account
Wildfire Assistance Fundprogram designed to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs
Wildfire Fundstatewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WPMAWildfires OIIwildfire plan memorandum accountOrder Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
WMPWildfire Mitigation Plan
WMPMAWildfire Mitigation Plan Memorandum Account


5

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to liabilities subject to compromise, insurance receivable, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances.  These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions.  PG&E Corporation and the Utility are not able to predict all the factors that may affect future results.  Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

•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 that satisfies all applicable legal requirements; the ability to obtain applicable Bankruptcy Court, creditor or state or federal 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 CPUC, and the FERC; increased costs related to the Chapter 11 Cases; the ability to obtain sufficient financing sources for ongoing and future operations and investment; the ability to satisfy the conditions precedent to financing under the Backstop Commitment Letters and the Debt Commitment Letters and the risk that such agreements may be terminated; the risk that the Noteholder RSA, the Subrogation RSA, the TCC RSA or the PSAs could be terminated; disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance;

•whether PG&E Corporation and the Utility will be able to emerge from Chapter 11 by June 30, 2020 with a plan of reorganization that is deemed to meet the requirements of AB 1054, and whether PG&E Corporation and the Utility will need to undertake significant changes in ownership, management and governance in connection therewith;

•if the Plan is determined not to meet the requirements of AB 1054 or the Utility does not otherwise participate in the Wildfire Fund under AB 1054, it could result in a significant delay in emergence from bankruptcy, as PG&E Corporation and the Utility may be required to make material modifications or amendments to their Plan, to develop and consummate a new consensual plan of reorganization or engage in a contested proceeding;

•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;

•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 and the potential financial and other restructuring currently contemplated by the Plan;

•the possibility that PG&E Corporation and the Utility will not be able to meet the conditions precedent to funding under the Backstop Commitment Letters and the Debt Commitment Letters, or that events or circumstances will occur that give rise to termination rights of the Backstop Parties or Commitment Parties under the Backstop Commitment Letters or Debt Commitment Letters, respectively, which could make raising funds to pay claims and exit Chapter 11 difficult or uneconomic;

•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 in order to exit Chapter 11 and to raise financing for operations and investment after emergence;

•the impact of AB 1054 on potential losses in connection with future wildfires, including the CPUC’s implementation of the procedures for recovering such losses;

6

•the impact of the 2018 Camp fire, 2017 Northern California wildfires and the 2015 Butte fire, including whether the Utility will be able to timely recover any costs incurred therewith in excess of insurance not disallowed from recovery in the Wildfire OII; 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, including, if the Plea Agreement is terminated, a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations (which actions could also adversely impact a timely emergence from Chapter 11);

•the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses with respect to claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise, which potential financings are not addressed by the Wildfire Fund as it only applies to wildfires occurring after July 12, 2019;

•the timing and outcome of any proceeding to recover 2015 Butte fire-related costs in excess of insurance through rates;

•the risks and uncertainties associated with the 2019 Kincade fire;

•the timing and outcome of future regulatory and legislative developments in connection with SB 901, including future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility or its industry;

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, as well as on energy demand in the Utility’s service territory, the ability of the Utility to collect on customer invoices, the ability of the Utility to offset these effects with spending reductions and the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic through cost recovery, and the impact of workforce disruptions, if any;

•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, including the Utility’s ability to comply with the targets and metrics set forth in the 2020-2022 Wildfire Mitigation Plan; 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;

•increased employee attrition as a result of the filing of the Chapter 11 Cases and the challenging political and operating environment facing the company;

•the impact of the Utility’s implementation of its PSPS program, including the timing and outcome of the PSPS OII and order to show cause, and whether any fines or penalties or civil liability for damages will be imposed on the Utility as a result; the costs in connection with PSPS events, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 and 2019 CEMA applications, WEMA application, future applications for FHPMA, FRMMA, and WMPMA, future cost of capital proceedings, and other ratemaking and regulatory proceedings;

7

•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, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes including the costs of complying with any additional conditions of probation imposed in connection with the Utility’s federal criminal proceeding, such as expenses associated with any material expansion of the Utility’s vegetation management program, including as a result of the probation proceedings before the U.S. District Court, as well as the impact of additional conditions of probation on PG&E Corporation’s and the Utility’s ability to make distributions to shareholders;

•the effects on PG&E Corporation’s and the Utility’s reputations caused by matters such as the CPUC’s investigations and enforcement proceedings;

•the outcome of the Safety Culture OII 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 transfer ownership of the Utility’s assets to municipalities or other public entities, or implement corporate governance changes;

•whether the Utility can control its operating 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;

•the timing and outcome in the Court of Appeals of the appeal of FERC’s order denying rehearing on September 19, 2019 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 outcome of FERC’s Order on Remand on July 18, 2019 granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO;

•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 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, signed into law on September 10, 2018, which increased 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 renewable portfolio standard-eligible or carbon-free resources by 2045;

•how the CPUC and the CARB implement state environmental laws relating to greenhouse gas, renewable energy targets, energy efficiency standards, distributed energy resources, electric vehicles, 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;
8


•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;

•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;

•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;

•the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs and DA providers, 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, and changing customer demand for its natural gas and electric services;

•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;

•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 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.

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained in Item 2. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
9


PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “PG&E Progress,” “Chapter 11,” “Wildfire Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

10

PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF INCOME


 (Unaudited)
Three Months Ended March 31,
(in millions, except per share amounts)20202019
Operating Revenues  
Electric$3,040  $2,792  
Natural gas1,266  1,219  
Total operating revenues4,306  4,011  
Operating Expenses
Cost of electricity545  599  
Cost of natural gas284  339  
Operating and maintenance1,967  2,087  
Depreciation, amortization, and decommissioning855  797  
Total operating expenses3,651  3,822  
Operating Income655  189  
Interest income16  22  
Interest expense(254) (103) 
Other income, net97  71  
Reorganization items, net(176) (127) 
Income Before Income Taxes338  52  
Income tax benefit(36) (84) 
Net Income374  136  
Preferred stock dividend requirement of subsidiary3  —  
Income Available for Common Shareholders$371  $136  
Weighted Average Common Shares Outstanding, Basic529  526  
Weighted Average Common Shares Outstanding, Diluted648  527  
Net Income Per Common Share, Basic$0.70  $0.25  
Net Income Per Common Share, Diluted$0.57  $0.25  
See accompanying Notes to the Condensed Consolidated Financial Statements.


11
 (Unaudited)
 Three Months Ended June 30, Six Months Ended June 30,
(in millions, except per share amounts)2019 2018 2019 2018
Operating Revenues       
Electric$2,946
 $3,312
 $5,738
 $6,263
Natural gas997
 922
 2,216
 2,027
Total operating revenues3,943
 4,234
 7,954
 8,290
Operating Expenses       
Cost of electricity837
 963
 1,436
 1,782
Cost of natural gas108
 79
 447
 368
Operating and maintenance1,942
 1,786
 4,029
 3,390
Wildfire-related claims, net of insurance recoveries3,900
 2,125
 3,900
 2,118
Depreciation, amortization, and decommissioning796
 746
 1,593
 1,498
Total operating expenses7,583
 5,699
 11,405
 9,156
Operating Loss(3,640) (1,465) (3,451) (866)
Interest income22
 12
 44
 21
Interest expense(60) (226) (163) (446)
Other income, net66
 106
 137
 214
Reorganization items, net(56) —
 (183) —
Loss Before Income Taxes(3,668) (1,573) (3,616) (1,077)
Income tax benefit(1,119) (593) (1,203) (542)
Net Loss(2,549) (980) (2,413) (535)
Preferred stock dividend requirement of subsidiary4
 4
 7
 7
Loss Attributable to Common Shareholders$(2,553) $(984) $(2,420) $(542)
Weighted Average Common Shares Outstanding, Basic529
 516
 528
 516
Weighted Average Common Shares Outstanding, Diluted529
 516
 528
 517
Net Loss Per Common Share, Basic$(4.83) $(1.91) $(4.58) $(1.05)
Net Loss Per Common Share, Diluted$(4.83) $(1.91) $(4.58) $(1.05)
        
See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (Unaudited)
Three Months Ended March 31,
(in millions)20202019
Net Income$374  $136  
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)—  —  
Total other comprehensive income—  —  
Comprehensive Income374  136  
Preferred stock dividend requirement of subsidiary3  —  
Comprehensive Income Available for Common Shareholders$371  $136  
See accompanying Notes to the Condensed Consolidated Financial Statements.

12
 (Unaudited)
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Net Loss$(2,549) $(980) $(2,413) $(535)
Other Comprehensive Income       
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)—
 —
 —
 —
Total other comprehensive income—
 —
 —
 —
Comprehensive Loss(2,549) (980) (2,413) (535)
Preferred stock dividend requirement of subsidiary4
 4
 7
 7
Comprehensive Loss Attributable to Common Shareholders$(2,553) $(984) $(2,420) $(542)
        
See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED BALANCE SHEETS
 (Unaudited)
 Balance At
(in millions)March 31, 2020December 31, 2019
ASSETS  
Current Assets    
Cash and cash equivalents$1,960  $1,570  
Accounts receivable:
Customers (net of allowance for doubtful accounts of $46 and $43
at respective dates)
1,319  1,287  
Accrued unbilled revenue946  969  
Regulatory balancing accounts2,102  2,114  
Other2,613  2,617  
Regulatory assets373  315  
Inventories:
Gas stored underground and fuel oil77  97  
Materials and supplies567  550  
Other601  646  
Total current assets10,558  10,165  
Property, Plant, and Equipment
Electric63,750  62,707  
Gas23,045  22,688  
Construction work in progress2,670  2,675  
Other20  20  
Total property, plant, and equipment89,485  88,090  
Accumulated depreciation(26,987) (26,455) 
Net property, plant, and equipment62,498  61,635  
Other Noncurrent Assets
Regulatory assets6,604  6,066  
Nuclear decommissioning trusts2,911  3,173  
Operating lease right of use asset2,209  2,286  
Income taxes receivable67  67  
Other1,841  1,804  
Total other noncurrent assets13,632  13,396  
TOTAL ASSETS$86,688  $85,196  
See accompanying Notes to the Condensed Consolidated Financial Statements.

13
 (Unaudited)
 Balance At
(in millions)June 30,
2019		 December 31,
2018
ASSETS 
  
Current Assets 
  
Cash and cash equivalents$3,459
 $1,668
Accounts receivable:   
Customers (net of allowance for doubtful accounts of $39 and $56
at respective dates)
1,260
 1,148
Accrued unbilled revenue991
 1,000
Regulatory balancing accounts1,884
 1,435
Other2,610
 2,686
Regulatory assets212
 233
Inventories:   
Gas stored underground and fuel oil99
 111
Materials and supplies509
 443
Income taxes receivable18

23
Other535
 448
Total current assets11,577
 9,195
Property, Plant, and Equipment   
Electric60,967
 59,150
Gas22,428
 21,556
Construction work in progress2,563
 2,564
Other20
 2
Total property, plant, and equipment85,978
 83,272
Accumulated depreciation(25,727) (24,715)
Net property, plant, and equipment60,251
 58,557
Other Noncurrent Assets   
Regulatory assets5,349
 4,964
Nuclear decommissioning trusts3,016
 2,730
Operating lease right of use asset2,662
 —
Income taxes receivable67
 69
Other1,465
 1,480
Total other noncurrent assets12,559
 9,243
TOTAL ASSETS$84,387
 $76,995
    
See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 		(Unaudited)
 Balance At
(in millions, except share amounts)March 31, 2020December 31, 2019
LIABILITIES AND EQUITY  
Current Liabilities
  
Debtor-in-possession financing, classified as current$2,000  $1,500  
Accounts payable:
Trade creditors1,851  1,954  
Regulatory balancing accounts1,845  1,797  
Other699  566  
Operating lease liabilities554  556  
Interest payable4  4  
Other1,300  1,254  
Total current liabilities8,253  7,631  
Noncurrent Liabilities
Regulatory liabilities9,251  9,270  
Pension and other post-retirement benefits1,855  1,884  
Asset retirement obligations5,902  5,854  
Deferred income taxes505  320  
Operating lease liabilities1,655  1,730  
Other2,757  2,573  
Total noncurrent liabilities21,925  21,631  
Liabilities Subject to Compromise50,751  50,546  
Equity
Shareholders’ Equity
Common stock, 0 par value, authorized 800,000,000 shares;
529,785,896 and 529,236,741 shares outstanding at respective dates
13,035  13,038  
Reinvested earnings(7,518) (7,892) 
Accumulated other comprehensive loss(10) (10) 
Total shareholders’ equity
5,507  5,136  
Noncontrolling Interest - Preferred Stock of Subsidiary252  252  
Total equity5,759  5,388  
TOTAL LIABILITIES AND EQUITY$86,688  $85,196  
See accompanying Notes to the Condensed Consolidated Financial Statements.

14
 
 
(Unaudited)
 Balance At
(in millions, except share amounts)June 30,
2019		 December 31,
2018
LIABILITIES AND EQUITY 
  
Current Liabilities
 
  
Short-term borrowings$—
 $3,435
Long-term debt, classified as current—
 18,559
Accounts payable:   
Trade creditors1,679
 1,975
Regulatory balancing accounts1,370
 1,076
Other593
 464
Operating lease liabilities546
 —
Disputed claims and customer refunds—
 220
Interest payable5
 228
Wildfire-related claims100
 14,226
Other1,418
 1,512
Total current liabilities5,711
 41,695
Noncurrent Liabilities   
Debtor-in-possession financing1,500
 —
Regulatory liabilities9,038
 8,539
Pension and other post-retirement benefits1,996
 2,119
Asset retirement obligations6,111
 5,994
Deferred income taxes2,354
 3,281
Operating lease liabilities2,116
 —
Other2,357
 2,464
Total noncurrent liabilities25,472
 22,397
Liabilities Subject to Compromise42,610
 —
Equity   
Shareholders’ Equity   
Common stock, no par value, authorized 800,000,000 shares;
529,223,793 and 520,338,710 shares outstanding at respective dates
13,014
 12,910
Reinvested earnings(2,663) (250)
Accumulated other comprehensive loss(9) (9)
Total shareholders’ equity
10,342
 12,651
Noncontrolling Interest - Preferred Stock of Subsidiary252
 252
Total equity10,594
 12,903
TOTAL LIABILITIES AND EQUITY$84,387
 $76,995
    
See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)
 Three Months Ended March 31,
(in millions)20202019
Cash Flows from Operating Activities  
Net income$374  $136  
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning855  797  
Allowance for equity funds used during construction(10) (25) 
Deferred income taxes and tax credits, net197  4  
Reorganization items, net (Note 2)50  19  
Other35  16  
Effect of changes in operating assets and liabilities:
Accounts receivable(22) (31) 
Wildfire-related insurance receivable—  25  
Inventories3  18  
Accounts payable245  (180) 
Wildfire-related claims—  (14) 
Income taxes receivable/payable—  23  
Other current assets and liabilities(123) 150  
Regulatory assets, liabilities, and balancing accounts, net(310) 343  
Liabilities subject to compromise208  833  
Other noncurrent assets and liabilities103  130  
Net cash provided by operating activities1,605  2,244  
Cash Flows from Investing Activities  
Capital expenditures(1,641) (1,224) 
Proceeds from sales and maturities of nuclear decommissioning trust investments533  346  
Purchases of nuclear decommissioning trust investments(552) (372) 
Other5  3  
Net cash used in investing activities
(1,655) (1,247) 
Cash Flows from Financing Activities  
Proceeds from debtor-in-possession credit facility500  350  
Debtor-in-possession credit facility debt issuance costs(3) (111) 
Bridge facility financing fees(66) —  
Common stock issued—  85  
Other9  (24) 
Net cash provided by financing activities440  300  
Net change in cash, cash equivalents, and restricted cash390  1,297  
Cash, cash equivalents, and restricted cash at January 11,577  1,675  
Cash, cash equivalents, and restricted cash at March 31$1,967  $2,972  
Less: Restricted cash and restricted cash equivalents included in other current assets(7) (8) 
Cash and cash equivalents at March 31$1,960  $2,964  

15

 (Unaudited)
 Six Months Ended June 30,
(in millions)2019 2018
Cash Flows from Operating Activities   
Net loss$(2,413) $(535)
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, amortization, and decommissioning1,593
 1,498
Allowance for equity funds used during construction(45) (63)
Deferred income taxes and tax credits, net(915) (145)
Reorganization items, net (Note 2)90
 —
Other53
 104
Effect of changes in operating assets and liabilities:   
Accounts receivable(54) (11)
Wildfire-related insurance receivable35
 (144)
Inventories(41) (6)
Accounts payable159
 39
Wildfire-related claims(14) 2,299
Income taxes receivable/payable5
 —
Other current assets and liabilities(15) (103)
Regulatory assets, liabilities, and balancing accounts, net(34) (12)
Liabilities subject to compromise4,221
 —
Other noncurrent assets and liabilities132
 (168)
Net cash provided by operating activities2,757
 2,753
Cash Flows from Investing Activities 
  
Capital expenditures(2,410) (2,897)
Proceeds from sales and maturities of nuclear decommissioning trust investments517
 802
Purchases of nuclear decommissioning trust investments(547) (815)
Other6
 15
Net cash used in investing activities
(2,434) (2,895)
Cash Flows from Financing Activities 
  
Proceeds from debtor-in-possession credit facility1,850
 —
Repayments of debtor-in-possession credit facility(350) —
Debtor-in-possession credit facility debt issuance costs(111) —
Borrowings under revolving credit facilities—
 700
Net repayments of commercial paper, net of discount of $1—
 (182)
Short-term debt financing—
 250
Short-term debt matured—
 (250)
Proceeds from issuance of long-term debt, net of discount and issuance costs—
 350
Long-term debt matured or repurchased—
 (750)
Common stock issued85
 82
Other(6) 10
Net cash provided by financing activities1,468
 210
Net change in cash, cash equivalents, and restricted cash1,791
 68
Cash, cash equivalents, and restricted cash at January 11,675
 456
Cash, cash equivalents, and restricted cash at June 30$3,466
 $524
Less: Restricted cash and restricted cash equivalents included in other current assets(7) $(7)
Cash and cash equivalents at June 30$3,459
 $517
Supplemental disclosures of cash flow information  
Cash paid for:  
Interest, net of amounts capitalized$—  $(10) 
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable$326  $242  
Operating lease liabilities arising from obtaining right-of-use assets13  2,816  
See accompanying Notes to the Condensed Consolidated Financial Statements.



16
Supplemental disclosures of cash flow information 
  
Cash paid for: 
  
Interest, net of amounts capitalized$(21) $(394)
Supplemental disclosures of noncash operating activities   
Operating lease liabilities arising from obtaining ROU assets$2,816
 $—
Supplemental disclosures of noncash investing and financing activities
   
Capital expenditures financed through accounts payable$836
 $317
    
See accompanying Notes to the Condensed Consolidated Financial Statements.




PG&E CORPORATION
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except share amounts)Common
Stock
Shares		Common
Stock
Amount		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income
(Loss)		Total
Shareholders’
Equity		Non
controlling
Interest -
Preferred
Stock of
Subsidiary		Total
Equity
Balance at December 31, 2019529,236,741  $13,038  $(7,892) $(10) $5,136  $252  $5,388  
Net income—  —  374  —  374  —  374  
Other comprehensive loss—  —  —  —  —  —  —  
Common stock issued, net549,155  —  —  —  —  —  —  
Stock-based compensation amortization—  (3) —  —  (3) —  (3) 
Balance at March 31, 2020529,785,896  $13,035  $(7,518) $(10) $5,507  $252  $5,759  
(in millions, except share amounts)
Common
Stock
Shares
 
Common
Stock
Amount
 
Reinvested
Earnings
 
Accumulated
Other
Comprehensive
Income
(Loss)
 
Total
Shareholders’
Equity
 
Non
controlling
Interest -
Preferred
Stock of
Subsidiary
 
Total
Equity
Balance at December 31, 2018520,338,710
 $12,910
 $(250) $(9) $12,651
 $252
 $12,903
Net income—
 —
 136
 —
 136
 —
 136
Other comprehensive loss—
 —
 —
 —
 —
 —
 —
Common stock issued, net8,871,568
 85
 —
 —
 85
 —
 85
Stock-based compensation amortization—
 5
 —
 —
 5
 —
 5
Balance at March 31, 2019529,210,278
 $13,000
 $(114) $(9) $12,877
 $252
 $13,129
Net loss—
 —
 (2,549) —
 (2,549) —
 (2,549)
Other comprehensive loss—
 —
 —
 —
 —
 —
 —
Common stock issued, net13,515
 —
 —
 —
 —
 —
 —
Stock-based compensation amortization—
 14
 —
 —
 14
 —
 14
Balance at June 30, 2019529,223,793
 $13,014
 $(2,663) $(9) $10,342
 $252
 $10,594

(in millions, except share amounts)Common
Stock
Shares		Common
Stock
Amount		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income
(Loss)		Total
Shareholders’
Equity		Non
controlling
Interest -
Preferred
Stock of
Subsidiary		Total
Equity
Balance at December 31, 2018520,338,710  $12,910  $(250) $(9) $12,651  $252  $12,903  
Net income—  —  136  —  136  —  136  
Other comprehensive loss—  —  —  —  —  —  —  
Common stock issued, net8,871,568  85  —  —  85  —  85  
Stock-based compensation amortization—  5  —  —  5  —  5  
Balance at March 31, 2019529,210,278  $13,000  $(114) $(9) $12,877  $252  $13,129  
(in millions, except share amounts)
Common
Stock
Shares
 
Common
Stock
Amount
 
Reinvested
Earnings
 
Accumulated
Other
Comprehensive
Income
(Loss)
 
Total
Shareholders’
Equity
 
Non
controlling
Interest -
Preferred
Stock of
Subsidiary
 
Total
Equity
Balance at December 31, 2017514,755,845
 $12,632
 $6,596
 $(8) $19,220
 $252
 $19,472
Net income—
 —
 445
 —
 445
 —
 445
Other comprehensive income—
 —
 5
 (5) —
 —
 —
Common stock issued, net1,248,112
 35
 —
 —
 35
 —
 35
Stock-based compensation amortization—
 34
 —
 —
 34
 —
 34
Preferred stock dividend requirement of
    subsidiary
—
 —
 (3) —
 (3) —
 (3)
Balance at March 31, 2018516,003,957
 12,701
 7,043
 (13) 19,731
 252
 19,983
Net loss—
 —
 (980) —
 (980) —
 (980)
Other comprehensive income—
 —
 —
 —
 —
 —
 —
Common stock issued, net1,099,026
 47
 —
 —
 47
 —
 47
Stock-based compensation amortization—
 15
 —
 —
 15
 —
 15
Preferred stock dividend requirement of
subsidiary		—
 —
 (4) —
 (4) —
 (4)
Balance at June 30, 2018517,102,983
 $12,763
 $6,059
 $(13) $18,809
 $252
 $19,061

See accompanying Notes to the Condensed Consolidated Financial Statements.


17

PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF INCOME


 (Unaudited)
Three Months Ended March 31,
(in millions)20202019
Operating Revenues  
Electric$3,040  $2,792  
Natural gas1,266  1,219  
Total operating revenues4,306  4,011  
Operating Expenses
Cost of electricity545  599  
Cost of natural gas284  339  
Operating and maintenance1,965  2,104  
Depreciation, amortization, and decommissioning855  797  
Total operating expenses3,649  3,839  
Operating Income657  172  
Interest income16  21  
Interest expense(252) (101) 
Other income, net93  66  
Reorganization items, net
(93) (111) 
Income Before Income Taxes421  47  
Income tax benefit(30) (86) 
Net Income451  133  
Preferred stock dividend requirement3  —  
Income Available for Common Stock$448  $133  
See accompanying Notes to the Condensed Consolidated Financial Statements.

18
 (Unaudited)
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Operating Revenues 
  
    
Electric$2,946
 $3,312
 $5,738
 $6,263
Natural gas997
 922
 2,216
 2,027
Total operating revenues3,943
 4,234
 7,954
 8,290
Operating Expenses       
Cost of electricity837
 963
 1,436
 1,782
Cost of natural gas108
 79
 447
 368
Operating and maintenance1,940
 1,786
 4,044
 3,390
Wildfire-related claims, net of insurance recoveries3,900
 2,125
 3,900
 2,118
Depreciation, amortization, and decommissioning796
 746
 1,593
 1,498
Total operating expenses7,581
 5,699
 11,420
 9,156
Operating Loss(3,638) (1,465) (3,466) (866)
Interest income22
 11
 43
 20
Interest expense(60) (222) (161) (439)
Other income, net64
 108
 130
 217
Reorganization items, net(57) —
 (168) —
Loss Before Income Taxes(3,669) (1,568) (3,622) (1,068)
Income tax benefit(1,119) (592) (1,205) (544)
Net Loss(2,550) (976) (2,417) (524)
Preferred stock dividend requirement4
 4
 7
 7
Loss Attributable to Common Stock$(2,554) $(980) $(2,424) $(531)
        
See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (Unaudited)
Three Months Ended March 31,
(in millions)20202019
Net Income$451  $133  
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)—  —  
Total other comprehensive income—  —  
Comprehensive Income$451  $133  
See accompanying Notes to the Condensed Consolidated Financial Statements.


19
 (Unaudited)
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Net Loss$(2,550) $(976) $(2,417) $(524)
Other Comprehensive Income       
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates )—
 1
 —
 1
Total other comprehensive income—
 1
 —
 1
Comprehensive Loss$(2,550) $(975) $(2,417) $(523)
        
See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED BALANCE SHEETS
 (Unaudited)
 Balance At
(in millions)March 31, 2020December 31, 2019
ASSETS  
Current Assets  
Cash and cash equivalents$1,555  $1,122  
Accounts receivable:
Customers (net of allowance for doubtful accounts of $46 and $43
at respective date
1,319  1,287  
Accrued unbilled revenue946  969  
Regulatory balancing accounts2,102  2,114  
Other2,651  2,647  
Regulatory assets373  315  
Inventories:
Gas stored underground and fuel oil77  97  
Materials and supplies567  550  
Other588  635  
Total current assets10,178  9,736  
Property, Plant, and Equipment
Electric63,750  62,707  
Gas23,045  22,688  
Construction work in progress2,670  2,675  
Other18  18  
Total property, plant, and equipment89,483  88,088  
Accumulated depreciation(26,985) (26,453) 
Net property, plant, and equipment62,498  61,635  
Other Noncurrent Assets
Regulatory assets6,604  6,066  
Nuclear decommissioning trusts2,911  3,173  
Operating lease right of use asset2,202  2,279  
Income taxes receivable66  66  
Other1,692  1,659  
Total other noncurrent assets13,475  13,243  
TOTAL ASSETS$86,151  $84,614  
See accompanying Notes to the Condensed Consolidated Financial Statements.

20
 (Unaudited)
 Balance At
(in millions)June 30,
2019		 December 31,
2018
ASSETS 
  
Current Assets 
  
Cash and cash equivalents$3,036
 $1,295
Accounts receivable:   
Customers (net of allowance for doubtful accounts of $39 and $56
at respective dates)
1,260
 1,148
Accrued unbilled revenue991
 1,000
Regulatory balancing accounts1,884
 1,435
Other2,621
 2,688
Regulatory assets212
 233
Inventories:   
Gas stored underground and fuel oil99
 111
Materials and supplies509
 443
Income taxes receivable1
 5
Other535
 448
Total current assets11,148
 8,806
Property, Plant, and Equipment   
Electric60,967
 59,150
Gas22,428
 21,556
Construction work in progress2,563
 2,564
Other18
 —
Total property, plant, and equipment85,976
 83,270
Accumulated depreciation(25,725) (24,713)
Net property, plant, and equipment60,251
 58,557
Other Noncurrent Assets   
Regulatory assets5,349
 4,964
Nuclear decommissioning trusts3,016
 2,730
Operating lease right of use asset2,653
 —
Income taxes receivable66
 66
Other1,325
 1,348
Total other noncurrent assets12,409
 9,108
TOTAL ASSETS$83,808
 $76,471
    
See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED BALANCE SHEETS
 (Unaudited)
 Balance At
(in millions. except share amounts)March 31, 2020December 31, 2019
LIABILITIES AND EQUITY
Current Liabilities  
Debtor-in-possession financing, classified as current$2,000  $1,500  
Accounts payable:
Trade creditors1,819  1,949  
Regulatory balancing accounts1,845  1,797  
Other786  675  
Operating lease liabilities551  553  
Interest payable4  4  
Other1,310  1,263  
Total current liabilities8,315  7,741  
Noncurrent Liabilities
Regulatory liabilities9,251  9,270  
Pension and other post-retirement benefits1,855  1,884  
Asset retirement obligations5,902  5,854  
Deferred income taxes633  442  
Operating lease liabilities1,651  1,726  
Other2,817  2,626  
Total noncurrent liabilities22,109  21,802  
Liabilities Subject to Compromise49,941  49,736  
Shareholders’ Equity
Preferred stock258  258  
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates1,322  1,322  
Additional paid-in capital8,550  8,550  
Reinvested earnings(4,345) (4,796) 
Accumulated other comprehensive income1  1  
Total shareholders’ equity5,786  5,335  
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY$86,151  $84,614  
See accompanying Notes to the Condensed Consolidated Financial Statements.

21
 (Unaudited)
 Balance At
(in millions. except share amounts)June 30,
2019		 December 31,
2018
LIABILITIES AND EQUITY   
Current Liabilities 
  
Short-term borrowings$—
 $3,135
Long-term debt, classified as current—
 18,209
Accounts payable:   
Trade creditors1,678
 1,972
Regulatory balancing accounts1,370
 1,076
Other688
 498
Operating lease liabilities543
 —
Disputed claims and customer refunds—
 220
Interest payable5
 227
Wildfire-related claims100
 14,226
Other1,420
 1,497
Total current liabilities5,804
 41,060
Noncurrent Liabilities   
Debtor-in-possession financing1,500
 —
Regulatory liabilities9,038
 8,539
Pension and other post-retirement benefits1,996
 2,026
Asset retirement obligations6,111
 5,994
Deferred income taxes2,474
 3,405
Operating lease liabilities2,110
 —
Other2,408
 2,492
Total noncurrent liabilities25,637
 22,456
Liabilities Subject to Compromise41,829
 —
Shareholders’ Equity   
Preferred stock258
 258
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates1,322
 1,322
Additional paid-in capital8,550
 8,550
Reinvested earnings409
 2,826
Accumulated other comprehensive income(1) (1)
Total shareholders’ equity10,538
 12,955
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY$83,808
 $76,471
    
See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)
 Three Months Ended March 31,
(in millions)20202019
Cash Flows from Operating Activities  
Net income$451  $133  
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning855  797  
Allowance for equity funds used during construction(10) (25) 
Deferred income taxes and tax credits, net202  2  
Reorganization items, net (Note 2)(11) 20  
Other40  12  
Effect of changes in operating assets and liabilities:
Accounts receivable(30) (51) 
Wildfire-related insurance receivable—  25  
Inventories3  18  
Accounts payable221  (132) 
Wildfire-related claims—  (14) 
Income taxes receivable/payable—  5  
Other current assets and liabilities(121) 171  
Regulatory assets, liabilities, and balancing accounts, net(310) 343  
Liabilities subject to compromise208  833  
Other noncurrent assets and liabilities114  137  
Net cash provided by operating activities1,612  2,274  
Cash Flows from Investing Activities
Capital expenditures(1,641) (1,224) 
Proceeds from sales and maturities of nuclear decommissioning trust investments533  346  
Purchases of nuclear decommissioning trust investments(552) (372) 
Other5  3  
Net cash used in investing activities
(1,655) (1,247) 
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility500  350  
Debtor-in-possession credit facility debt issuance costs(3) (95) 
Bridge facility financing fees(30) —  
Other9  (24) 
Net cash provided by financing activities476  231  
Net change in cash, cash equivalents, and restricted cash433  1,258  
Cash, cash equivalents, and restricted cash at January 11,129  1,302  
Cash, cash equivalents, and restricted cash at March 31$1,562  $2,560  
Less: Restricted cash and restricted cash equivalents included in other current assets(7) (8) 
Cash and cash equivalents at March 31$1,555  $2,552  


22

 (Unaudited)
 Six Months Ended June 30,
(in millions)2019 2018
Cash Flows from Operating Activities 
  
Net loss$(2,417) $(524)
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, amortization, and decommissioning1,593
 1,498
Allowance for equity funds used during construction(45) (63)
Deferred income taxes and tax credits, net(920) (149)
Reorganization items, net (Note 2)91
 —
Other34
 57
Effect of changes in operating assets and liabilities:   
Accounts receivable(64) (11)
Wildfire-related insurance receivable35
 (144)
Inventories(41) (6)
Accounts payable206
 40
Wildfire-related claims(14) 2,299
Income taxes receivable/payable4
 —
Other current assets and liabilities(8) (95)
Regulatory assets, liabilities, and balancing accounts, net(34) (12)
Liabilities subject to compromise4,215
 —
Other noncurrent assets and liabilities141
 (168)
Net cash provided by operating activities2,776
 2,722
Cash Flows from Investing Activities   
Capital expenditures(2,410) (2,897)
Proceeds from sales and maturities of nuclear decommissioning trust investments517
 802
Purchases of nuclear decommissioning trust investments(547) (815)
Other6
 15
Net cash used in investing activities
(2,434) (2,895)
Cash Flows from Financing Activities   
Proceeds from debtor-in-possession credit facility1,850
 —
Repayments of debtor-in-possession credit facility(350) —
Debtor-in-possession credit facility debt issuance costs(95) —
Borrowings under revolving credit facility—
 650
Net repayments of commercial paper, net of discount—
 (50)
Short-term debt financing—
 250
Short-term debt matured—
 (250)
Long-term debt matured or repurchased—
 (400)
Other(6) 10
Net cash provided by financing activities1,399
 210
Net change in cash, cash equivalents, and restricted cash1,741
 37
Cash, cash equivalents, and restricted cash at January 11,302
 454
Cash, cash equivalents, and restricted cash at June 30$3,043
 $491
Less: Restricted cash and restricted cash equivalents included in other current assets(7) (7)
Cash and cash equivalents at June 30$3,036
 $484


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized$—  $(8) 
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable$326  $242  
Operating lease liabilities arising from obtaining right-of-use assets13  2,807  
See accompanying Notes to the Condensed Consolidated Financial Statements.

23
Supplemental disclosures of cash flow information   
Cash paid for:   
Interest, net of amounts capitalized$(19) $(387)
Supplemental disclosures of noncash operating activities   
Operating lease liabilities arising from obtaining ROU assets$2,807
 $—
Supplemental disclosures of noncash investing and financing activities   
Capital expenditures financed through accounts payable$836
 $317
    
See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY
(DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
(in millions)Preferred
Stock		Common
Stock
Amount		Additional
Paid-in
Capital		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Shareholders’
Equity
Balance at December 31, 2019$258  $1,322  $8,550  $(4,796) $1  $5,335  
Net income—  —  —  451  —  451  
Balance at March 31, 2020$258  $1,322  $8,550  $(4,345) $1  $5,786  
(in millions)
Preferred
Stock
 Common
Stock
Amount		 
Additional
Paid-in
Capital
 
Reinvested
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
Balance at December 31, 2018$258
 $1,322
 $8,550
 $2,826
 $(1) $12,955
Net income—
 —
 —
 133
 —
 133
Other comprehensive loss—
 —
 —
 —
 —
 —
Equity contribution—
 —
 —
 —
 —
 —
Balance at March 31, 2019$258
 $1,322
 $8,550
 $2,959
 $(1) $13,088
Net loss—
 —
 —
 (2,550) —
 (2,550)
Other comprehensive loss—
 —
 —
 —
 —
 —
Equity contribution—
 —
 —
 —
 —
 —
Balance at June 30, 2019$258
 $1,322
 $8,550
 $409
 $(1) $10,538

(in millions)Preferred
Stock		Common
Stock
Amount		Additional
Paid-in
Capital		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Shareholders’
Equity
Balance at December 31, 2018$258  $1,322  $8,550  $2,826  $(1) $12,955  
Net income—  —  —  133  —  133  
Balance at March 31, 2019$258  $1,322  $8,550  $2,959  $(1) $13,088  
(in millions)
Preferred
Stock
 Common
Stock
Amount		 
Additional
Paid-in
Capital
 
Reinvested
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
Balance at December 31, 2017$258
 $1,322
 $8,505
 $9,656
 $6
 $19,747
Net income—
 —
 —
 452
 —
 452
Other comprehensive income (loss)—
 —
 —
 2
 (2) —
Equity contribution—
 —
 —
 —
 —
 —
Preferred stock dividend—
 —
 —
 (3) —
 (3)
Balance at March 31, 2018$258
 $1,322
 $8,505
 $10,107
 $4
 $20,196
Net loss—
 —
 —
 (976) —
 (976)
Other comprehensive income—
 —
 —
 —
 1
 1
Equity contribution—
 —
 —
 —
 —
 —
Preferred stock dividend—
 —
 —
 (4) —
 (4)
Balance at June 30, 2018$258
 $1,322
 $8,505
 $9,127
 $5
 $19,217

See accompanying Notes to the Condensed Consolidated Financial Statements.






24

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  The Utility is primarily regulated by the CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated in consolidation.  The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate as onein 1 segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 20182019 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 20182019 Form 10-K.  This quarterly report should be read in conjunction with the 20182019 Form 10-K. 

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s wildfire-related liabilities, regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries,receivables, environmental remediation liabilities, AROs, pension and other post-retirement benefit plan obligations, and the valuation of pre-petition liabilities.LSTC. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable.  A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, and results of operations, liquidity, and cash flows during the period in which such change occurred.

Chapter 11 Filing and Going Concern

The accompanying Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility are facing extraordinary challenges relating tosuffered material losses as a seriesresult of catastrophic wildfires that occurred inthe 2017 Northern California in 2017wildfires and 2018.the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection. See Note 10 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. PG&E Corporation and the Utility have determined that commencing reorganization cases under Chapter 11 was necessary to restore PG&E Corporation’s and the Utility’s financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation’s and the Utility’s financial stability.

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. The Condensed Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns.

25

Pursuant to Chapter 11,sections 1107(a) and 1108 of the Bankruptcy Code, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors-in-possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation’s and the Utility’s DIP Credit Agreement (see Note 5 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Condensed Consolidated Financial Statements.  Any such actions occurring during the Chapter 11 Cases authorized by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. (For more information regarding the Chapter 11 Cases, see Note 2 below.)




NOTE 2: BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility filedcommenced the Chapter 11 Cases with the Bankruptcy Court. PG&E Corporation and the Utility continue to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 10 below) as of the Petition Date, are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be administeredresolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and other stakeholders,interest holders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings generally are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continuehave been continuing during the pendency of the Chapter 11 Cases.

Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation'sCorporation’s and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests.

Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this quarterly report on Form 10-Q, or in the 20182019 Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code.

Significant Bankruptcy Court Actions

First Day Motions

On January 31, 2019, the Bankruptcy Court approved, on an interim basis, certain motions (the “First Day Motions”) authorizing, but not directing, PG&E Corporation and the Utility to, among other things, (a) secure $5.5 billion of debtor-in-possession financing; (b) continue to use PG&E Corporation’s and the Utility’s cash management system; and (c) pay certain pre-petition claims relating to (i) certain safety, reliability, outage, and nuclear facility suppliers; (ii) shippers, warehousemen, and other lien claimants; (iii) taxes; (iv) employee wages, salaries, and other compensation and benefits; and (v) customer programs, including public purpose programs. The First Day Motions were subsequently approved by the Bankruptcy Court on a final basis at hearings on February 27, 2019, March 12, 2019, March 13, 2019, and March 27, 2019.

On May 23, 2019, the Bankruptcy Court entered an order (the “Exclusivity Order”) pursuant to section 1121(d) of the Bankruptcy Code, extending PG&E Corporation’s and the Utility’s exclusive periods in which to file a Chapter 11 plan of reorganization (the “Exclusive Filing Period”) and solicit acceptances thereof (the “Exclusive Solicitation Period”). Pursuant to the Exclusivity Order, PG&E Corporation’s and the Utility’s Exclusive Filing Period is extended to, and including, September
26 2019, and PG&E Corporation’s and the Utility’s Exclusive Solicitation Period is extended to, and including, November 26, 2019.


Bar Date


On June 25, 2019, the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility (the “Ad Hoc Noteholder Committee”) submitted a motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, for the entry of an order terminating the Exclusive Filing Period and the Exclusive Solicitation Period.  The Ad Hoc Noteholder Committee annexed to its motion a “Term Sheet for Plan of Reorganization.”  On July 17, 2019, the Ad Hoc Noteholder Committee filed with the Bankruptcy Court an amended version of the term sheet, along with a commitment letter with respect to certain financings described therein.  Certain third parties have filed joinders and statements in support with the Bankruptcy Court with respect to the Ad Hoc Noteholder Committee’s motion, but such parties have not taken any position on the plan construct described by the term sheet.  These third parties include TURN, two collective bargaining units representing the Utility’s employees, and the UCC. On July 18, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court, requesting that the motion be denied.  Also on July 18, 2019, the Ad Hoc Group of Subrogation Claim Holders (the “Ad Hoc Subrogation Group”), the TCC, and certain owners of common stock of PG&E Corporation (the “Shareholder Group”) filed objections to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court. At a hearing on July 24, 2019, the Bankruptcy Court granted an oral motion of the CPUC and the Governor’s office to adjourn the hearing on the Ad Hoc Noteholder Committee’s motion from July 24, 2019 to August 13, 2019, to allow PG&E Corporation and the Utility, the CPUC, the Governor’s office, and other parties in interest time to engage in discussions regarding the formulation of a potential protocol for the efficient submission and consideration of Chapter 11 plan proposals. The parties are due to provide a status update on these discussions to the Bankruptcy Court on August 9, 2019. On August 7, 2019, the Ad Hoc Noteholder Committee submitted a statement with the Bankruptcy Court, criticizing the protocol proposed by the CPUC and including as an exhibit its own proposed “Alternative Protocol” to govern a competitive plan process. In addition, the Ad Hoc Noteholder Committee annexed to its statement a second amended version of the term sheet and a revised version of the commitment letter.

On July 23, 2019, the Ad Hoc Subrogation Group submitted its own motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, to terminate the Exclusive Filing Period and the Exclusive Solicitation Period, which included as an exhibit a “Restructuring Term Sheet.” The hearing before the Bankruptcy Court on the Ad Hoc Subrogation Group’s motion is scheduled for August 13, 2019. On August 6, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Subrogation Group’s motion with the Bankruptcy Court, requesting that the motion be denied. Also on August 6, 2019, the UCC filed a statement in opposition with respect to the Ad Hoc Subrogation Group’s motion, and the Shareholder Group filed an objection to the Ad Hoc Subrogation Group’s motion, both requesting that the motion be denied.

On July 1, 2019, the Bankruptcy Court entered an order approving a deadline of October 21, 2019, at 5:00 p.m. (Pacific Time) (the “Bar Date”) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the bar date for which occurred on April 22, 2019. The Bankruptcy Court also approved PG&E Corporation’s and the Utility’s plan to provide notice of the Bar Date to parties-in-interest,parties in interest, including potential wildfire-related claimants and other potential creditors. On November 11, 2019, the Bankruptcy Court entered an order approving a stipulation between PG&E Corporation and the Utility and the TCC to extend the Bar Date for unfiled, non-governmental fire claimants to December 31, 2019, at 5:00 p.m. (Pacific Time). By order dated February 27, 2020, the Court extended the Bar Date through and including April 16, 2020, for certain persons or entities that purchased or acquired the PG&E Corporation’s and the Utility’s publicly traded debt or equity securities and who may have claims under the securities laws against the Debtors for rescission or damages.

Other Significant Actions Related to the Chapter 11 Cases

Other significant actions and developments related to the Chapter 11 Cases, including the Tubbs Lift Stay Decision, the Tubbs Trial and the Estimation Proceeding are described in Note 10 (including under the headings “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” and “Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California”).

Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters

On September 9, 2019, PG&E Corporation and the Utility filed with the Bankruptcy Court their Joint Chapter 11 Plan of Reorganization for the resolution of the outstanding pre-petition claims against and interests in PG&E Corporation and the Utility, which was thereafter amended on September 23, 2019 and November 4, 2019. On December 12, 2019, PG&E Corporation and the Utility, certain funds and accounts managed or advised by Abrams Capital Management, LP (“Abrams”), and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (“Knighthead” and, together with Abrams, the “Shareholder Proponents”) filed the Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization dated December 19, 2019 with the Bankruptcy Court (as thereafter amended on January 31, 2020, March 9, 2020 and March 16, 2020, and as may be further amended, modified or supplemented from time to time, the “Plan”).

On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”). On September 22, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors entered into an amended and restated Restructuring Support Agreement, which was subsequently amended on November 1, 2019, (as amended, the “Subrogation RSA”). The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to settle all insurance subrogation claims (the “Subrogation Claims”) relating to the 2017 Northern California wildfires and the 2018 Camp fire (the “Subrogation Claims Settlement”), upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also have agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the Subrogation RSA. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approval of the Subrogation Claims Settlement. Hearings on PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA were held on October 23, 2019, December 4, 2019 and December 17, 2019. On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the Subrogation RSA.

27

On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019 (as amended, the “TCC RSA”), with the TCC, the attorneys and other advisors and agents for holders of Fire Victim Claims (as defined below) that are signatories to the TCC RSA (each a “Consenting Fire Claimant Professional”), and the Shareholder Proponents. The TCC RSA provides for, among other things, an aggregate of $13.5 billion in value to be provided by PG&E Corporation and the Utility pursuant to the Plan in order to settle and discharge all claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and the Public Entity Wildfire Claims) (the “Fire Victim Claims”), upon the terms and conditions set forth in the TCC RSA and the Plan. On December 9, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the TCC RSA. A hearing on PG&E Corporation’s and the Utility’s motion to approve the TCC RSA was held on December 17, 2019. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 10 for further information on the TCC RSA.

Plan of Reorganization

The Plan proposes the following:

•compensation of wildfire victims and certain public entities from a trust funded for their benefit in an aggregate value of approximately $13.5 billion (as further described under the heading “Restructuring Support Agreement with the TCC” in Note 10);

•compensation of insurance subrogation claimants from a trust funded for their benefit in the amount of $11.0 billion in cash (as further described under the heading “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10);

•payment of $1.0 billion in cash in full settlement of the claims of the settling public entities relating to the wildfires (as further described under the heading “Plan Support Agreements with Public Entities” in Note 10);

•entitlement for the holders of claims related to the 2016 Ghost Ship fire to pursue their claims after the Effective Date, with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies;

•refinancing of Utility Short-Term Notes, Utility Long-Term Notes and Utility Funded Debt (except Pollution Control Bonds Series 2008F and 2010E, which will be repaid in cash) with the issuance of new notes, reinstatement of Utility Reinstated Notes and reimbursement of the holders of Utility Long-Term Senior Notes for debt placement fees and the members of the Ad Hoc Noteholder Committee for professional fees of up to $99 million (as further described under the heading “Restructuring Support Agreement with the Ad Hoc Noteholder Committee”);

•payment in full of all pre-petition funded debt obligations of PG&E Corporation, all pre-petition trade claims and all pre-petition employee-related unsecured claims;

•assumption of all power purchase agreements and community choice aggregation servicing agreements;

•assumption of all pension obligations, other employee obligations, and collective bargaining agreements with labor;

•future participation in the state wildfire fund established by AB 1054; and

•satisfaction of the requirements of AB 1054.

The Plan proposes the following key financing sources:

•one or more equity offerings of up to $9.0 billion, in accordance with the Backstop Commitment Letters, although the Backstop Commitment Letters (as described below) permit PG&E Corporation to draw up to $12.0 billion;

•the issuance of $6.75 billion of new equity to the Fire Victim Trust;

•the issuance of $4.75 billion of new PG&E Corporation debt;

•the reinstatement of $9.575 billion of pre-petition debt of the Utility;
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•the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of New Utility Long-Term Notes to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (ii) $1.75 billion of New Utility Short-Term Notes to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (iii) $3.9 billion of Utility Funded Debt Exchange Notes to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date);

•approximately $2.2 billion in proceeds of PG&E Corporation’s and the Utility’s liability insurance proceeds for wildfire events; and

•cash available to PG&E Corporation or the Utility immediately prior to the Effective Date.

On October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications of the Plan.

The Plan has not been approved and is subject to regulatory review by the CPUC and FERC, as and to the extent required by law, including as potentially causing a change in control under Section 203 of the Federal Power Act. The Plan may be further amended, modified, or supplemented as necessary or desired by PG&E Corporation and the Utility or as required by the Bankruptcy Court or the CPUC. PG&E Corporation and the Utility expect that the CPUC and FERC will issue decisions in advance of the June 30, 2020 deadline for Plan confirmation.

On March 20, 2020, the Debtors filed a motion with the Bankruptcy Court for entry of an order approving a case resolution contingency process to address the circumstance in which the Plan is not confirmed or fails to become effective in accordance with certain required dates (the “Case Resolution Contingency Process”). As further described in the motion, the Case Resolution Contingency Process contemplates a process for the sale of PG&E Corporation or the Utility in the event that the Plan is not confirmed or fails to become effective in accordance with certain required dates. In addition, the motion sets forth certain other commitments by the Debtors in connection with the confirmation process and implementation of the Plan, including among other things, limitations on the ability of PG&E Corporation to pay dividends; commitments by the Utility with respect to cost recovery of amounts paid in respect of “Fire Claims” under the Plan; the terms of a purchase option in favor of the state of California (which would be exercisable only in limited circumstances); and commitments with respect to the Utility’s utilization of the cash benefits associated with wildfire-related net operating losses. Also on March 20, 2020, the California Governor filed a responsive pleading in the Bankruptcy Court stating that, assuming the Bankruptcy Court grants the Motion and the California Public Utilities Commission (“CPUC”) approves the Plan with the governance, financial and operational provisions submitted to the CPUC by the Utility or otherwise agreed by the Utility, with any modifications the CPUC believes appropriate or necessary, the Plan “will, in the Governor’s judgment, be compliant with AB 1054.” The Governor’s pleading also states that “a rate neutral securitization pursuant to Senate Bill 901...would, in [the Governor’s] judgment, be in the public interest...” Following a hearing held on April 7, 2020, the Bankruptcy Court indicated that it would approve the Debtors’ motion and the Case Resolution Contingency Process, subject to certain reservations of rights, and directed the Debtors to submit an order to that effect. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

Disclosure Statement

On February 7, 2020, pursuant to section 1125 of the Bankruptcy Code, PG&E Corporation and the Utility filed a proposed disclosure statement (as updated, the “Proposed Disclosure Statement”), with all schedules and exhibits thereto, for the Plan. On February 18, 2020, PG&E Corporation and the Utility filed certain projections with the Bankruptcy Court as an exhibit to the Proposed Disclosure Statement, and on March 9, 2020, PG&E Corporation and the Utility filed an updated Proposed Disclosure Statement with revised financial projections as an exhibit with the Bankruptcy Court. PG&E Corporation and the Utility filed on February 18, 2020, a motion requesting that the Court (i) establish Plan solicitation and voting procedures, and (ii) approve the forms of Ballots, Solicitation Packages, and related notices to be sent to the various creditors and interest holders in connection with confirmation of the Plan (the “Solicitation Procedures Motion”). By order dated March 17, 2020, the Bankruptcy Court approved the Proposed Disclosure Statement and the Solicitation Procedures Motion. Pursuant to the Solicitation Procedures Motion, PG&E Corporation and the Utility mailed the Ballots, Solicitation Packages and related notices by March 31, 2020, and votes are due by May 15, 2020. A hearing to consider confirmation of the Plan is scheduled for May 27, 2020.

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Restructuring Support Agreement with the Ad Hoc Noteholder Committee

On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” below and the Shareholder Proponents. The Noteholder RSA provides for, among other things, (i) the refinancing of the Utility’s senior unsecured debt in satisfaction of all claims arising out of the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt, each as defined below, and (ii) the reinstatement of the Utility Reinstated Senior Notes, as defined below (together with the Utility Short-Term Senior Notes and Utility Long-Term Senior Notes, the “Utility Senior Note Claims”), in each case pursuant to the Plan and upon the terms and conditions set forth in the Noteholder RSA. Under the Noteholder RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Utility Long-Term Senior Notes for debt placement fees and the members of the Ad Hoc Noteholder Committee for professional fees of up to $99 million upon the terms and conditions set forth in the Noteholder RSA. The following holders of Utility Senior Notes Claims are party to the Noteholder RSA as “Consenting Noteholders” as of the date hereof: Apollo Global Management LLC, Elliott Management Corporation, Oaktree Capital Management L.P., Farallon Capital Management LLC, Capital Group, Värde Partners Inc., Davidson Kempner Capital Management LP, Canyon Capital Advisors LLC, Third Point LLC, Pacific Investment Management Company LLC, Citadel Advisors LLC and Sculptor Capital Investments, LLC. Any holder of Utility Senior Note Claims or Utility Funded Debt can become a party to the Noteholder RSA by executing the joinder attached to the Noteholder RSA.

The Noteholder RSA provides for the following treatment of Utility Senior Note Claims and Utility Funded Debt which treatment has been incorporated into the Plan:

•Utility Short-Term Senior Notes: Currently outstanding Utility notes maturing through 2022 in an aggregate principal amount of $1.75 billion (the “Utility Short-Term Senior Notes”) will receive new Utility secured notes in the following aggregate principal amounts: $875 million of new Utility 3.45% secured notes due 2025 and $875 million of new Utility 3.75% secured notes due 2028 (together, the “New Utility Short-Term Notes”). The New Utility Short-Term Notes will otherwise have substantially similar terms and conditions as the Utility’s 6.05% Senior Notes due March 1, 2034. Additionally, holders of claims arising out of the Utility Short-Term Senior Notes will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Short-Term Senior Notes calculated using the applicable non-default contract rate and (2) interest calculated using the Federal Judgment Rate on the sum of (A) the applicable principal amount of the Utility Short-Term Senior Notes and (B) the amount in clause (1) for the period commencing on the day after the Petition Date and ending on the Effective Date.

•Utility Long-Term Senior Notes: All long-term Utility notes bearing an interest rate greater than 5.00%, of which there is an aggregate principal amount outstanding of $6.2 billion (the “Utility Long-Term Senior Notes”), will receive new Utility secured notes in the following aggregate principal amounts: $3.1 billion of new Utility 4.55% secured notes due 2030 and $3.1 billion of new Utility 4.95% secured notes due 2050 (together, the “New Utility Long-Term Notes”). The New Utility Long-Term Notes will otherwise have substantially similar terms and conditions as the Utility’s 3.95% Senior Notes due December 1, 2047. Additionally, holders of claims arising out of the Utility Long-Term Senior Notes will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Long-Term Senior Notes calculated using the applicable non-default contract rate and (2) interest calculated using the federal judgment rate on the sum of (A) the applicable principal amount of the Utility Long-Term Senior Notes and (B) the amount in clause (1) for the period commencing on the Petition Date and ending on the Effective Date.

•Utility Reinstated Senior Notes: The remaining outstanding $9.575 billion aggregate principal amount of Utility notes (the “Utility Reinstated Senior Notes”) will be reinstated on their contractual terms, including being secured equally and ratably with the New Utility Short-Term Notes and the New Utility Long-Term Notes.

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•Utility Funded Debt: Holders of the Utility’s pre-petition credit facilities and Pollution Control bonds (collectively, the “Utility Funded Debt”) will receive new Utility secured notes in the following aggregate principal amounts: $1.949 billion in new Utility 3.15% senior secured notes due 2025, and $1.949 billion in new Utility 4.50% senior secured notes due 2040 (the “New Utility Funded Debt Exchange Notes”). The New Utility Funded Debt Exchange Notes will otherwise have substantially similar terms and conditions as the Utility’s 6.05% Senior Notes due March 1, 2034. Additionally, holders of claims arising out of the Utility Funded Debt will receive cash in an amount equal to the sum of (1) the amount of pre-petition interest outstanding on the Utility Funded Debt calculated using the applicable non-default contract rate, (2) fees and charges and other obligations owed as of the Petition Date in respect of the Utility Funded Debt, (3) reasonable attorney’s fees and expenses of counsel, subject a maximum of $6 million and (4) interest calculated using the federal judgment rate on the sum of (A) the applicable principal amount of the Utility Funded Debt and (B) the amount in clauses (1) and (2) for the period commencing on the Petition Date and ending on the Effective Date.

On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA.For more information regarding the terms of the Noteholder RSA, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

Equity Backstop Commitments

As of March 6, 2020, PG&E Corporation has entered into Chapter 11 Plan Backstop Commitment Letters (collectively, the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). The price at which any such new shares would be issued to the Backstop Parties would be equal to (a) 10 (subject to adjustment as provided in the Backstop Commitment Letters), times (b) PG&E Corporation’s consolidated Normalized Estimated Net Income (as defined in the Backstop Commitment Letters) for the estimated year 2021, divided by (c) the number of fully diluted shares of PG&E Corporation that will be outstanding on the effective date of the Plan (the “Effective Date”) (assuming that all equity is raised by funding the Backstop Commitments).

The Backstop Commitment Letters provide that, under certain circumstances, PG&E Corporation and the Utility will be permitted to issue new shares of common stock of PG&E Corporation for up to $12.0 billion of proceeds to finance the transactions contemplated by the Plan through one or more equity offerings that, under certain circumstances, must include a rights offering (the “Rights Offering”). The structure, terms and conditions of any such equity offering (including a Rights Offering) are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. This may include terms and conditions that are designed to preserve the ability of PG&E Corporation or the Utility to utilize their net operating loss carryforwards. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $12.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Plan, subject to the satisfaction or waiver by the Backstop Parties of the conditions set forth therein. Although the Backstop Commitment Letters permit PG&E Corporation to draw up to $12.0 billion in equity under specified circumstances, the Plan contemplates an equity raise of only $9.0 billion, the maximum available under these circumstances, which equity will be raised in accordance with the terms of the Backstop Commitment Letters.

Under the Backstop Commitment Letters, PG&E Corporation agrees that if the Backstop Commitments are drawn, and PG&E Corporation does not expect to conduct a third-party transaction based upon or related to the utilization or monetization of any net operating losses or tax deductions resulting from the payment of pre-petition wildfire-related claims (a “Tax Benefits Monetization Transaction”) on the Effective Date, no later than five business days prior to the Effective Date, PG&E Corporation and the Utility must form a trust which would provide for periodic distributions of cash to the Backstop Parties in amounts equal to (i) all tax benefits arising from the payment of wildfire-related claims in excess of (ii) the first $1.35 billion of tax benefits, starting with fiscal year 2020. PG&E Corporation intends to explore a Tax Benefits Monetization Transaction. If PG&E Corporation and the Utility implement the capital structure outlined in the Debtors’ Plan of Reorganization OII Prepared Testimony filed with the California Public Utilities Commission on January 31, 2020, such capital structure will be deemed to include a $6.0 billion “Tax Benefits Monetization Transaction” for the purposes of the Backstop Commitment Letter.

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The Backstop Parties’ funding obligations under the Backstop Commitment Letters are subject to numerous conditions, including, among others, that (a) the Backstop Commitment Letters have been approved by the Bankruptcy Court, (b) the conditions precedent to the Effective Date set forth in the Plan have been satisfied or waived in accordance with the Plan, (c) the Bankruptcy Court has entered an order confirming the Plan and approving the transactions contemplated thereunder, which shall confirm the Plan with such amendments, modifications, changes and consents as are approved by holders of a majority of the aggregate Backstop Commitments (the “Confirmation Order”), (d) PG&E Corporation’s and the Utility’s weighted average earning rate base for 2021 is no less than 95% of $48 billion, and (e) there has been no event, occurrence or other circumstance that would have or would reasonably be expected to have a material adverse effect on the business of PG&E Corporation and the Utility or their ability to consummate the transactions contemplated by the Backstop Commitment Letters and the Plan.

In addition, the Backstop Parties have certain termination rights under the Backstop Commitment Letters, including, among others, if:

•the Plan (including as may be amended, modified or otherwise changed) does not include Abrams and Knighthead as plan proponents and is not in a form acceptable to each of Abrams and Knighthead,

•PG&E Corporation’s and the Utility’s aggregate liability with respect to pre-petition wildfire-related claims exceeds $25.5 billion,

•the Plan is amended without the consent of the holders of a majority of the aggregate Backstop Commitments,

•the Confirmation Order has not been entered by the Bankruptcy Court by June 30, 2020,

•the Effective Date has not occurred within 60 days of entry of the Confirmation Order,

•a material adverse effect (as described above) occurs,

•the CPUC fails to issue all necessary approvals, authorizations and final orders to implement the Plan prior to June 30, 2020, including approvals related to the Utility’s capital structure and authorized rate of return and the resolution of the CPUC’s claims against the Utility for fines or penalties, all of which must be satisfactory to the holders of a majority of the aggregate Backstop Commitments,

•the amount of asserted administrative expense claims or the amount of administrative expense claims PG&E Corporation and the Utility have reserved for and/or paid in the aggregate exceeds $250 million, net of insurance, in each case excluding administrative expense claims that are ordinary course, professional fee claims, claims that are disallowed in the Chapter 11 Cases and the portion of an administrative expense claim that is covered by insurance,

•one or more wildfires occur in the Utility’s service area on or after January 1, 2020 that damage or destroy at least 500 dwellings or commercial structures in the aggregate at a time when the portion of the Utility’s system at the location of such wildfire was not successfully de-energized,

•as of the Effective Date, the Utility has not elected and received Bankruptcy Court approval, or satisfied the other required conditions, to participate in the statewide wildfire fund established by AB 1054,

•at any time the Bankruptcy Court determines that PG&E Corporation and the Utility are insolvent,

•PG&E Corporation and the Utility enter into any Tax Benefit Monetization Transaction and the net cash proceeds thereof are less than $3.0 billion, excluding the $1.35 billion of tax benefits to be utilized in the Plan, and

•the Plan or any supplements to or other documents in connection with the Plan has been amended, modified or changed, without the consent of the holders of at least 66 2/3% of the aggregate Backstop Commitments, to include a process for transferring the license and operating assets of the Utility to the State of California or a third party (a “Transfer”) or PG&E Corporation and the Utility effect a Transfer other than pursuant to the Plan. There can be no assurance that the conditions precedent set forth in the Backstop Commitment Letters will be satisfied or waived, nor that events or circumstances will not occur that give rise to termination rights of the Backstop Parties.

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The commitment premium for the Backstop Commitments is paid in shares of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119.0 million shares of the Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12 billion).This aggregate 119 million share amount will be adjusted through the issuance of additional shares in the event that the aggregate value of the 119 million shares paid as the Backstop Commitment premium is less than $764 million based on the market price of the Corporation’s common stock following the Effective Date, subject to a cap of 19,909,091 additional shares in total. Such commitment premium was earned in full upon Bankruptcy Court approval of the Backstop Commitment Letters, subject to clawback under certain circumstances set forth in the Backstop Commitment Letters. In the event that a plan of reorganization for PG&E Corporation that is not the Plan is confirmed by the Bankruptcy Court, then the Backstop Commitment premium will be payable in cash if elected by the applicable Backstop Party. Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters.

On March 16, 2020, the Bankruptcy Court approved the Backstop Commitment Letters. As of March 31, 2020, PG&E Corporation expects to record approximately $1 billion of expense related to the Backstop Commitment premium in Reorganization items, net for the year ended December 31, 2020. The total annual expense will be determined based on the price of PG&E Corporation’s common stock as of the Effective Date.

Debt Commitment Letters

On October 11, 2019, PG&E Corporation and the Utility entered into debt commitment letters, which were subsequently amended on November 18, 2019, December 20, 2019, January 30, 2020, and February 14, 2020 (as amended, the “Debt Commitment Letters”) with JPMorgan Chase Bank, N.A., Bank of America, N.A., BofA Securities, Inc., Barclays Bank PLC, Citigroup Global Markets Inc., Goldman Sachs Bank USA, Goldman Sachs Lending Partners LLC and the other lenders that may become parties to the Debt Commitment Letters as additional “Commitment Parties” as provided therein (the foregoing parties, collectively, the “Commitment Parties”), pursuant to which the Commitment Parties committed to provide $10.825 billion in bridge financing in the form of (a) a $5.825 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy (the Utility or any such entity, the “OpCo Borrower”) as borrower thereunder and (b) a $5.0 billion senior unsecured bridge loan facility (together with the OpCo Facility, the “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy (the Corporation or any such entity, the “HoldCo Borrower”) as borrower thereunder, subject to the terms and conditions set forth therein. The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights described below.

Borrowings under the OpCo Facility would be senior secured obligations of the OpCo Borrower, secured by substantially all of the assets of the OpCo Borrower. Borrowings under the HoldCo Facility would be senior unsecured obligations of the HoldCo Borrower. The OpCo Borrower’s obligations under the OpCo Facility, and the HoldCo Borrower’s obligations under the HoldCo Facility, would not be guaranteed by any other entity. The scheduled maturity of each of the Facilities would be 364 days following the date the Facilities are funded. PG&E Corporation and the Utility will pay customary fees and expenses in connection with obtaining the Facilities (including commitment fees and ticking fees but excluding any fees related to the funding of the Facilities). If the entire $10.825 billion of bridge commitments remain outstanding as of June 30, 2020, the aggregate fees payable (including commitment fees and ticking fees, but excluding any fees related to the funding of the Facilities) by PG&E Corporation and the Utility would be approximately $75 million.

In connection with the anticipated funding for the Plan and the anticipated amount of debt and equity to be used for funding thereunder, on February 14, 2020, the Debt Commitment Letters were amended to, among other things, (1) adjust the maximum amount of any roll-over, “take-back” or reinstated debt permitted under the Facilities from $30 billion to $33.35 billion at the Utility and from $7.0 billion to $5.0 billion at PG&E Corporation and (2) increase the amount of proceeds from the issuance of debt securities or other debt for borrowed money as a condition to funding from $2.0 billion at PG&E Corporation to $6.0 billion at the Utility.

The Commitment Parties’ funding obligations under the Debt Commitment Letters are subject to numerous conditions and termination rights, including, among others, certain conditions and termination rights similar to those included in the Backstop Commitment Letters, in addition to conditions that are not in the Backstop Commitment Letters, including (a) the delivery of specified financial information, (b) PG&E Corporation’s receipt of at least $9.0 billion of proceeds from the issuance of equity, (c) the execution of definitive documentation for the Facilities and (d) that the Utility shall have received investment grade senior secured debt ratings. The Utility’s ability to borrow under the OpCo Facility is subject to approval by the CPUC.

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In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the foregoing.

On March 16, 2020, the Bankruptcy Court approved the Debt Commitment Letters as amended through February 28, 2020. During the three months ended March 31, 2020, PG&E Corporation and the Utility recorded facility fees of $36 million and $14 million, respectively, reflected in Reorganization items, net on the Condensed Consolidated Income Statements. In addition, the Utility recorded $18 million to a regulatory asset for fees that are deemed probable of recovery.

The timing and outcome of the Chapter 11 Cases is uncertain. Although PG&E Corporation, the Utility, the Bankruptcy Court, the CPUC and many other stakeholders have stated that they are working towards confirming a plan of reorganization by June 30, 2020, it is possible that the Chapter 11 process could extend beyond the June 30, 2020 deadline and take a number of years to resolve.

Ad Hoc Noteholder Plan of Reorganization

On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed the Ad Hoc Noteholder Plan. On December 19, 2019, pursuant to the TCC RSA (described below), the TCC filed a notice of withdrawal as a plan proponent of the Ad Hoc Noteholder Plan with the Bankruptcy Court. The Ad Hoc Noteholder Plan differed from the Plan in a number of respects, including, but not limited to, its treatment of equity interests, its treatment of holders of claims in respect of debt of PG&E Corporation and the Utility and its financing sources.

On January 22, 2020, the Ad Hoc Noteholder Committee entered into the Noteholder RSA with PG&E Corporation and the Utility, under which it agreed, upon entry of the order of the Bankruptcy Court approving the Noteholder RSA, to withdraw any participation in and support for the Ad Hoc Noteholder Plan, including by taking certain actions to defer further action on the make-whole and post-petition interest issues. On February 4, 2020, the Noteholder RSA was approved by the Bankruptcy Court, and on February 5, 2020, the Ad Hoc Noteholder Committee withdrew the Ad Hoc Noteholder Plan. It is possible that, if the Noteholder RSA is terminated, the Ad Hoc Noteholder Committee could re-file a competing plan with similar or different terms.

Debtor-In-Possession Financing

See Note 5 for further discussion of the DIP Facilities, which provide up to $5.5 billion in financing.

Financial Reporting in Reorganization

Effective on the Petition Date, PG&E Corporation and the Utility began to apply accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that are directly associated with reorganization proceedings must be reported separately as reorganization items, net in the Condensed Consolidated Statements of Income. In addition, the balance sheet must distinguish pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that are not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that are not debtors in the Chapter 11 Cases in the Condensed Consolidated Balance Sheets. LSTC are pre-petition obligations that are not fully secured and have at least a possibility of not being repaid at the full claim amount. Where there is uncertainty about whether a secured claim will be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility have classified the entire amount of the claim as LSTC.



Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date are stayed while PG&E Corporation and the Utility continue business operations as debtors-in-possession. These claims are reflected as LSTC in the Condensed Consolidated Balance Sheets at June 30, 2019.March 31, 2020. Additional claims (which could be LSTC) may arise after the Petition Date resulting from the rejection of executory contracts, including leases, and from the determination by the Bankruptcy Court (or agreement by parties-in-interest) of allowed claims for contingencies and other disputed amounts.

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PG&E Corporation’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

The Utility’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

Liabilities Subject to Compromise

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities is subject to compromise or other treatment pursuant to a plan of reorganization. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are stayed. Although payment of pre-petition claims generally is not permitted, the Bankruptcy Court granted PG&E Corporation and the Utility authority to pay certain pre-petition claims in designated categories and subject to certain terms and conditions. This relief generally was designed to preserve the value of PG&E Corporation’s and the Utility’s business and assets. As described above, among other things, the Bankruptcy Court authorized, but did not require, PG&E Corporation and the Utility to pay certain pre-petition claims relating to employee wages and benefits, taxes, and amounts owed to certain vendors.

The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. GAAP requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for different amounts. The amounts currently classified as LSTC are preliminary and may be subject to future adjustments depending on Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events.

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The following table presents LSTC as reported in the Condensed Consolidated Balance Sheets at June 30, 2019:March 31, 2020:
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Financing debt (2)
$22,627  $671  $23,298  
Wildfire-related claims (3)
25,548  —  25,548  
Trade creditors1,200  5  1,205  
Non-qualified benefit plan20  132  152  
2001 bankruptcy disputed claims (4)
238  —  238  
Customer deposits & advances78  —  78  
Other230  2  232  
Total Liabilities Subject to Compromise$49,941  $810  $50,751  
(in millions)Utility 
PG&E Corporation (1)
 PG&E Corporation Consolidated
Financing debt (2)
$21,811
 $650
 $22,461
Wildfire-related claims (3)
18,012
 —
 18,012
Trade creditors1,325
 4
 1,329
Non-qualified benefit plan18
 125
 143
2001 bankruptcy disputed claims221
 —
 221
Customer deposits & advances278
 —
 278
Other164
 2
 166
Total Liabilities Subject to Compromise$41,829
 $781
 $42,610
      
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) At June 30,March 31, 2020, PG&E Corporation and the Utility had $650 million and $21,526 million in aggregate principal amount of pre-petition indebtedness, respectively. Pre-petition financing debt includes accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, respectively, to the Petition Date. Financing debt also includes post-petition interest of $20 million and $815 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of the Noteholder RSA. See Note 5 for details of pre-petition debt reported as LSTC.
(3) See “Pre-petition Wildfire-related claims” in Note 10 for information regarding pre-petition wildfire-related claims reported as LSTC.
(4) 2001 bankruptcy disputed claims includes $17 million of interest recorded at the interest rate specified by FERC in accordance with S35.19a of the Commission’s regulations.

The following table presents LSTC as reported in the Consolidated Balance Sheets at December 31, 2019:

(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Financing debt (2)
$22,450  $666  $23,116  
Wildfire-related claims (3)
25,548  —  25,548  
Trade creditors1,183  5  1,188  
Non-qualified benefit plan20  137  157  
2001 bankruptcy disputed claims (4)
234  —  234  
Customer deposits & advances71  —  71  
Other230  2  232  
Total Liabilities Subject to Compromise$49,736  $810  $50,546  
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) At December 31, 2019, PG&E Corporation and the Utility had $650 million and $21,526 million in aggregate principal amount of pre-petition indebtedness, respectively. Pre-petition financing debt includes accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, pre-petition financingrespectively, to the Petition Date. Financing debt also includes $285post-petition interest of $15 million and $638 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of accrued contractual interest to the Petition Date.Noteholder RSA. See Note 5 for details of pre-petition debt reported as LSTC.
(3) See “Pre-petition Wildfire-related claims” in Note 10 for information regarding pre-petition wildfire-related claims reported as LSTC. As described
(4) 2001 bankruptcy disputed claims includes $14 million of interest recorded at the interest rate specified by FERC in Note 10 underaccordance with S35.19a of the heading “Plan Support AgreementsCommission’s regulations.

Interest on Debt Subject to Compromise

On December 30, 2019, the Bankruptcy Court issued a memorandum decision in which it ruled that the Official Committee of Unsecured Creditors is entitled to post-petition interest at the Federal Judgment Rate of 2.59%. Pursuant to the Noteholder RSA, holders of $11.9 billion in aggregate principal amount of Utility Short-Term Senior Notes, Utility Long-Term Senior Notes and Utility Funded Debt will receive interest at the contractual rate for accrued and unpaid pre-petition interest plus interest at the Federal Judgment Rate on the sum of the applicable principal plus the amount of accrued and unpaid interest for the period commencing the day after the Petition Date and ending on the Effective Date. The $9.58 billion in aggregate principal of Utility Reinstated Senior notes will accrue interest at the contractual rate in accordance with Public Entities,” on June 18, 2019, PG&E Corporation andthe terms of the Noteholder RSA. From the Petition Date through March 31, 2020, the Utility entered into agreementsconcluded that interest was probable of being an allowed claim and resumed recording interest on pre-petition debt subject to compromise in accordance with certain local public entitiesthe Noteholder RSA. The interest rate on trade payables subject to potentially resolve their wildfire-related claimscontracts that will remain in effect through the Chapter 11 process.Cases will be charged at the contractual rate or at the State of California statutory rate of 10%.
36



Chapter 11 Claims Process


Potential Claims

PG&E Corporation and the Utility have filed withreceived over 100,000 proofs of claim since the Bankruptcy Court schedules and statements of financial affairs setting forth, among other things, the assets and liabilities ofPetition Date. PG&E Corporation and the Utility continue their review and analysis of certain claims including litigation claims, trade creditor claims, non-qualified benefit plan claims, claims arising from the Utility’s 2001 Chapter 11 case and customer deposits and advances, along with other tax and regulatory claims and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amount recorded in liabilities subject to compromise. To the assumptions filed in connection therewith. On July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims againstextent that PG&E Corporation and the Utility relating to the period prior to the Petition Date. The Bar Date is subject to certain exceptions, including forbelieve that such claims arising under section 503(b)(9) ofwill be allowed by the Bankruptcy Code, the bar date for which occurred on April 22, 2019.

Numerous claims have been filed with the Bankruptcy Court, against PG&E Corporation and the Utility relating to the period prior to the Petition Date and it is expected that new and amended claims will continue to be filed untilrecord the Bar Date,expected allowed amounts of such claims as liabilities subject to compromise. The determination of the expected allowed amount of a claim is based on many factors, including whether PG&E Corporation or the Utility is party to a settlement agreement with applicable claimholders or their representatives, and is necessarily limited to information available to PG&E Corporation and the Utility. Claims covered by a settlement agreement include wildfire-related claims amendedand Utility debt claims. See “Restructuring Support Agreement with the TCC,” “Restructuring Support Agreements with Holders of Subrogation Claims,” and “Plan Support Agreements with Public Entities” in Note 10 of the Notes to assign valuethe Condensed Consolidated Financial Statements for more information on settlement of wildfire-related claims, and “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2 of the Notes to claims originally filed with no designated value. Through the claims resolution process, differences in amounts scheduled byCondensed Consolidated Financial Statements for more information on settlement of Utility debt claims. As PG&E Corporation and the Utility continue to resolve claims, differences between those final allowed claims and claims filed by creditorsthe liabilities recorded in the Condensed Consolidated Balance Sheet will be investigatedrecognized in PG&E Corporation’s and the Utility’s Statement of Consolidated Income (Loss) as they are resolved. The determination of how liabilities will ultimately be resolved including through the filing of objections withcannot be made until the Bankruptcy Court where appropriate. In lightapproves a plan of reorganization or approves orders related to settlement of specific liabilities. Accordingly, the substantial number andultimate amount or resolution of claims filed, the claims resolution process may take considerable time to complete and will likely continue after PG&E Corporation and the Utility emerge from bankruptcy. The ultimate number and amount of allowed claimssuch liabilities is not determinable at this time. The resolution of such claims could result in substantial adjustments to PG&E Corporation’s and the Utility’s financial statements.

Reorganization Items, Net

Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income. Reorganization items also include adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments are approved by the Bankruptcy Court.  Cash paid for reorganization items, net was $15$57 million and $78$117 million for PG&E Corporation and the Utility, respectively, during the sixthree months ended June 30,March 31, 2020 as compared to $17 million and $91 million for PG&E Corporation and the Utility, respectively, during the same period in 2019. Reorganization items, net for the three months ended June 30, 2019March 31, 2020 and from the Petition Date through June 30,March 31, 2020 include the following:

Three Months Ended March 31, 2020
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$3  $—  $3  
Legal and other (2)
95  84  179  
Interest income(5) (1) (6) 
Total reorganization items, net$93  $83  $176  
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Includes bridge loan facility fees.

37

Petition Date Through March 31, 2020
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$98  $17  $115  
Legal and other (2)
371  102  473  
Interest income(55) (11) (66) 
Total reorganization items, net$414  $108  $522  
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Includes bridge loan facility fees.

Reorganization items, net for the three months ended March 31, 2019 include the following:

Three Months Ended June 30, 2019Three Months Ended March 31, 2019
(in millions)Utility 
PG&E Corporation (1)
 PG&E Corporation Consolidated(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$—
 $—
 $—
Debtor-in-possession financing costs$97  $17  $114  
Legal and other75
 1
 76
Legal and other23  1  24  
Interest income(18) (3) (21)Interest income(9) (2) (11) 
Adjustments to LSTC—
 —
 —
Trustee fees (2)
—
 1
 1
Total reorganization items, net$57
 $(1) $56
Total reorganization items, net$111  $16  $127  
     
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee in the three months ended June 30, 2019.
 Petition Date Through June 30, 2019
(in millions)Utility 
PG&E Corporation (1)
 PG&E Corporation Consolidated
Debtor-in-possession financing costs$97
 $17
 $114
Legal and other98
 2
 100
Interest income(27) (5) (32)
Adjustments to LSTC—
 —
 —
Trustee fees (2)
—
 1
 1
Total reorganization items, net$168
 $15
 $183
      

(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee through June 30, 2019.



Contractual Interest on Debt Subject to Compromise

Effective as of the Petition Date, PG&E Corporation and the Utility ceased recording interest expense on outstanding pre-petition debt. Contractual interest expense represents amounts due under the contractual terms of outstanding pre-petition debt. From the Petition Date through June 30, 2019, contractual interest expense of $405 million related to LSTC has not been recorded in the financial statements. The portion of authorized revenues from the Petition Date through June 30, 2019 related to interest expense on pre-petition debt has been deferred as a non-current regulatory liability.

The Bankruptcy Court’s Decision on its Authority over PG&E Corporation’s and the Utility’s Rejection of Power Purchase Agreements

On June 7, 2019, the Bankruptcy Court granted PG&E Corporation’s and the Utility’s motion for declaratory judgment in an adversary proceeding entitled Pacific Gas &and Electric Company v. FERC.  In its amended declaratory judgment, the Bankruptcy Court found that FERC had no “concurrent jurisdiction, or any jurisdiction, over the determination of whether any rejections of power purchase contracts by either Debtor should be authorized” pursuant to section 365 of the Bankruptcy Code.  The Bankruptcy Court also found that the “Debtors do not need approval from the Federal Energy Regulatory Commission to reject any of their power purchase contracts” and that “[a]ny determinations of the Federal Energy Regulatory Commission” that were contrary to these findings “are void, of no force and effect and not binding on this court or either Debtor.”  The Bankruptcy Court further stated that such determinations include, but are not limited to, those previously made in certain FERC proceedings initiated before the Chapter 11 Cases were filed in connection with power purchase contracts with the Utility.Utility (the “FERC Orders”).

On June 12, 2019, the Bankruptcy Court certified its amended declaratory judgment for direct appeal to the United States Court of Appeals for the Ninth Circuit.  On July 15, 2019, FERC and certain counterparties to the Utility’s power purchase agreements filed requests for the Ninth Circuit to permit such direct appeal. In addition,appeal, which the Ninth Circuit granted on September 17, 2019. On September 17, 2019, the Ninth Circuit granted the requests and docketed both appeals. Opening briefs of FERC and the other appellants were filed on November 20, 2019, PG&E Corporation’s and the Utility’s answering brief was filed on December 20, 2019, and reply briefs of FERC and the other appellants were filed on January 17, 2020. Oral argument is scheduled for August 12 or 14, 2020. Separately, on June 26, 2019, the Utility filed a petition for review of those earlierthe FERC ordersOrders, also in the Ninth Circuit. On September 20, 2019, the Ninth Circuit granted the Utility’s motion to align the briefing schedule with the direct appeals from the Bankruptcy Court. The Utility’s opening brief was filed on November 20, 2019, FERC’s and respondent-intervenors’ answering briefs were filed on December 20, 2019, and the Utility’s reply brief was filed on January 17, 2020. Oral argument is scheduled for August 12 or 14, 2020.

The Plan proposes to assume all power purchase agreements and community choice aggregation servicing agreements.

38

Resolution of Remaining 2001 Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s 2001 prior 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 pursued settlements with electricity suppliers and 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, in some instances, would be 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.

The Utility’s obligations with respect to such claims (all of which arose prior to the initiation of the Utility’s pending Chapter 11 Case on January 29, 2019), including pursuant to any prior settlements relating thereto, are expected to be determined through the proceedings of the Chapter 11 Cases.

NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Condensed Consolidated Financial Statements above for bankruptcy-related policies and Note 23 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.

Variable Interest Entities
Variable
 Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. 



Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at June 30, 2019,March 31, 2020, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at June 30, 2019,March 31, 2020, it did not consolidate any of them.


Pension and Other Post-Retirement Benefits

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.

39

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30,March 31, 2020 and 2019 and 2018 were as follows:
Pension BenefitsOther Benefits
Three Months Ended March 31,
(in millions)2020201920202019
Service cost for benefits earned (1)
$132  $111  $15  $14  
Interest cost178  189  16  19  
Expected return on plan assets(261) (227) (34) (31) 
Amortization of prior service cost(1) (1) 3  4  
Amortization of net actuarial loss1  1  (5) (1) 
Net periodic benefit cost49  73  (5) 5  
Regulatory account transfer (2)
34  10  —  —  
Total$83  $83  $(5) $5  
 Pension Benefits Other Benefits
 Three Months Ended June 30,
(in millions)2019 2018 2019 2018
Service cost for benefits earned (1)
$111
 $129
 $14
 $17
Interest cost190
 172
 19
 18
Expected return on plan assets(226) (256) (30) (32)
Amortization of prior service cost(2) (2) 3
 3
Amortization of net actuarial loss—
 2
 (1) (2)
Net periodic benefit cost73
 45
 5
 4
Regulatory account transfer (2)
10
 39
 —
 —
Total$83
 $84
 $5
 $4
        
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

 Pension Benefits Other Benefits
 Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Service cost for benefits earned (1)
$222
 $257
 $28
 $33
Interest cost379
 344
 38
 35
Expected return on plan assets(453) (511) (61) (65)
Amortization of prior service cost(3) (3) 7
 7
Amortization of net actuarial loss1
 3
 (2) (3)
Net periodic benefit cost146
 90
 10
 7
Regulatory account transfer (2)
21
 77
 —
 —
Total$167
 $167
 $10
 $7
        

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.



On February 27, 2019, PG&E Corporation and the Utility received final approval from the Bankruptcy Court to maintain existing pension and other benefit plans, other than the non-qualified pension plan, during the pendency of the Chapter 11 Cases.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:consisted of the following:
Pension
Benefits		Other
Benefits		Total
(in millions, net of income tax)Three Months Ended March 31, 2020
Beginning balance$(22) $17  $(5) 
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0 and $1, respectively)(1) 2  1  
Amortization of net actuarial loss (net of taxes of $0 and $2, respectively)1  (3) (2) 
Regulatory account transfer (net of taxes of $0 and $1, respectively)—  1  1  
Net current period other comprehensive gain (loss)—  —  —  
Ending balance$(22) $17  $(5) 
 Pension
Benefits		 Other
Benefits		 Total
(in millions, net of income tax)Three Months Ended June 30, 2019
Beginning balance$(21) $17
 $(4)
Amounts reclassified from other comprehensive income:     
Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1)
(1) 2
 1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)
—
 —
 —
Regulatory account transfer (net of taxes of $1 and $0, respectively) (1)
1
 (2) (1)
Net current period other comprehensive gain (loss)—
 —
 —
Ending balance$(21) $17
 $(4)
      
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
40

 Pension Benefits Other
Benefits		 Total
(in millions, net of income tax)Three Months Ended June 30, 2018
Beginning balance$(30) $17
 $(13)
Amounts reclassified from other comprehensive income: (1)
     
Amortization of prior service cost (net of taxes of $1 and $1, respectively)(1) 2
 1
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)1
 (1) —
Regulatory account transfer (net of taxes of $0 and $0, respectively)—
 (1) (1)
Net current period other comprehensive gain (loss)—
 —
 —
Ending balance$(30) $17
 $(13)
      
Pension BenefitsOther
Benefits		Total
(in millions, net of income tax)Three Months Ended March 31, 2019
Beginning balance$(21) $17  $(4) 
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0 and $1, respectively)(1) 3  2  
Amortization of net actuarial loss (net of taxes of $0, and $0, respectively)1  (1) —  
Regulatory account transfer (net of taxes of $0 and $1, respectively)—  (2) (2) 
Net current period other comprehensive gain (loss)—  —  —  
Ending balance$(21) $17  $(4) 
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)


 Pension
Benefits		 Other
Benefits		 Total
(in millions, net of income tax)Six Months Ended June 30, 2019
Beginning balance$(21) $17
 $(4)
Amounts reclassified from other comprehensive income:     
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)
(2) 5
 3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)
1
 (1) —
Regulatory account transfer (net of taxes of $1 and $1, respectively) (1)
1
 (4) (3)
Net current period other comprehensive gain (loss)—
 —
 —
Ending balance$(21) $17
 $(4)
      
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
 Pension
Benefits		 Other
Benefits		 Total
(in millions, net of income tax)Six Months Ended June 30, 2018
Beginning balance$(25) $17
 $(8)
Amounts reclassified from other comprehensive income:     
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)
(2) 5
 3
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)
2
 (2) —
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)
—
 (3) (3)
Reclassification of stranded income tax to retained earnings(5) —
 (5)
Net current period other comprehensive gain (loss)(5) —
 (5)
Ending balance$(30) $17
 $(13)
      
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate case,cases, which generally occur every three or four years.  The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year.  The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.



The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

41

The following table presents the Utility’s revenues disaggregated by type of customer:
Three Months Ended March 31,
(in millions)20202019
Electric
Revenue from contracts with customers
   Residential$1,242  $1,288  
   Commercial1,007  953  
   Industrial341  293  
   Agricultural123  86  
   Public street and highway lighting17  17  
   Other (1)
(66) (309) 
     Total revenue from contracts with customers - electric2,664  2,328  
Regulatory balancing accounts (2)
376  464  
Total electric operating revenue$3,040  $2,792  
Natural gas
Revenue from contracts with customers
   Residential$1,066  $1,171  
   Commercial234  240  
   Transportation service only348  382  
   Other (1)
(22) (75) 
      Total revenue from contracts with customers - gas1,626  1,718  
Regulatory balancing accounts (2)
(360) (499) 
Total natural gas operating revenue1,266  1,219  
Total operating revenues$4,306  $4,011  
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Electric       
Revenue from contracts with customers       
   Residential$994
 $1,039
 $2,282
 $2,375
   Commercial1,135
 1,234
 2,088
 2,307
   Industrial326
 354
 619
 678
   Agricultural261
 318
 347
 443
   Public street and highway lighting16
 18
 33
 38
   Other (1)
—
 84
 (309) (118)
     Total revenue from contracts with customers - electric2,732
 3,047
 5,060
 5,723
Regulatory balancing accounts (2)
214
 265
 678
 540
Total electric operating revenue$2,946
 $3,312
 $5,738
 $6,263
        
Natural gas       
Revenue from contracts with customers       
   Residential$343
 $452
 $1,515
 $1,410
   Commercial129
 119
 369
 315
   Transportation service only304
 264
 686
 560
   Other (1)
(129) (128) (205) (179)
      Total revenue from contracts with customers - gas647
 707
 2,365
 2,106
Regulatory balancing accounts (2)
350
 215
 (149) (79)
Total natural gas operating revenue997
 922
 2,216
 2,027
Total operating revenues$3,943
 $4,234
 $7,954
 $8,290
        
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.

Recently Adopted Accounting Standards

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, the recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  Under the new standard, all lessees must recognize a ROU asset, reflecting the right to use the underlying asset for the lease term, and a lease liability, reflecting the obligation to make lease payments, on the balance sheet. Operating leases were previously not recognized on the balance sheet.  PG&E Corporation and the Utility adopted the ASU on January 1, 2019.

PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, the Corporation and Utility elected to not separate lease and non-lease components. Additionally, PG&E Corporation and the Utility have elected not to restate comparative periods upon adoption.



PG&E Corporation and the Utility determine if an arrangement is a lease at inception. As most of the leases do not provide implicit discount rates, the Utility uses an estimate of its incremental secured borrowing rates based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities include only fixed lease payments. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease terms will only include options to extend or terminate the lease when it is reasonably certain that the Utility will exercise such options. The Utility recognizes lease expense in conformity with ratemaking.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Condensed Consolidated Balance Sheets. Finance leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Condensed Consolidated Balance Sheets. Financing leases were immaterial for the six months ended June 30, 2019.

Cash payments arising from operating leases were $848 million for the six months ended June 30, 2019 and are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. Cash payments for the principal portion of the financing lease liability will continue to be presented within financing activities. Variable lease payments not included in the financing lease liability, if any, are presented within operating activities. On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of fixed lease payments and excluding any variable lease payments. This amount is presented within the supplemental disclosures of noncash activities for the six months ended, June 30, 2019.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins, for terms between 5 years and 20 years. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land leases.

At June 30, 2019, the Utility’s operating leases had a weighted average remaining lease term of 6.1 years and a weighted average discount rate of 6.1%.

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
(in millions)Three Months Ended June 30, 2019 Six Months Ended June 30, 2019
Operating lease fixed cost$114
 $236
Operating lease variable cost490
 799
Total operating lease costs$604
 $1,035

The following table shows the Utility’s future expected operating lease payments:
(in millions)June 30, 2019
2019 (1)
$450
2020679
2021623
2022548
2023255
Thereafter692
  Total lease payments3,247
Less imputed interest(594)
  Total$2,653
  
(1) Represents the remaining expected operating lease payments from July 1, 2019 through December 31, 2019.



The following table shows the Utility’s future expected obligations for power purchase and other lease commitments:
(in millions)December 31, 2018
2019$684
2020677
2021621
2022546
2023252
Thereafter581
  Total lease commitments$3,361


Accounting Standards Issued But Not Yet Adopted

Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Intangibles-GoodwillIntangibles—Goodwill and Other

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-GoodwillIntangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility adopted the ASU on January 1, 2020 with early2020. The adoption permitted. PG&E Corporation andof this ASU did not have a material impact on the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-CreditInstruments – Credit Losses (Topic 326), which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. ThisPG&E Corporation and the Utility adopted the ASU on January 1, 2020.

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PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in its estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. There was no material impact to PG&E Corporation or the Utility’s Condensed Consolidated Financial Statements resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

Defined Benefit Plans

In August 2018, the FASB issued ASU No. 2018-14, Fair Value Measurement (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for Defined Benefit Plans. The ASU will be effective for PG&E Corporation and the Utility on January 1,in 2020. PG&E Corporation and the Utility are currently evaluating the impact of the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The ASU will be effective for PG&E Corporation and the Utility before December 31, 2022. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.


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NOTE 4: REGULATORY ASSETS,ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets and Liabilities

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:
Balance at
(in millions)March 31, 2020December 31, 2019
Pension benefits (1)
$1,790  $1,823  
Environmental compliance costs1,053  1,062  
Utility retained generation (2)
216  228  
Price risk management138  124  
Unamortized loss, net of gain, on reacquired debt59  63  
Catastrophic event memorandum account (3)
684  656  
Wildfire expense memorandum account (4)
443  423  
Fire hazard prevention memorandum account (5)
260  259  
Fire risk mitigation memorandum account (6)
96  95  
Wildfire mitigation plan memorandum account (7)
840  558  
Deferred income taxes (8)
468  252  
Other557  523  
Total long-term regulatory assets$6,604  $6,066  
 Asset Balance at
(in millions)June 30, 2019 December 31, 2018
Pension benefits (1)
$1,928
 $1,947
Environmental compliance costs997
 1,013
Utility retained generation (2)
251
 274
Price risk management67
 90
Unamortized loss, net of gain, on reacquired debt (3)
230
 76
Catastrophic event memorandum account (4)
918
 790
Wildfire expense memorandum account (5)
127
 94
Fire hazard prevention memorandum account (6)
291
 263
Fire risk mitigation memorandum account (7)
154
 —
Other386
 417
Total long-term regulatory assets$5,349
 $4,964
    
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. 
(3) Includes the accelerated amortization of premiums and debt issuance costs on pre-petition debt.
(4) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval.
(5)(4) Includes specific incremental wildfirewildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.
(6)(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval.
(7)(6) Includes costs associated with the 2019 Wildfire Safety Plan.Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FHPMAFRMMA costs are subject to CPUC review and approval.

(7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through December 31, 2019 and the 2020 Wildfire Mitigation Plan for the period of January 1, 2020 through March 31, 2020. Recovery of WMPMA costs are subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
Current Regulatory Liabilities
44

Current regulatory liabilities are primarily comprised of the current portion of the tax reform adjustment recorded as a result of the Tax Act.



Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:
 Liability Balance at
(in millions)June 30, 2019 December 31, 2018
Cost of removal obligations (1)
$6,233
 $5,981
Deferred income taxes (2)
4
 283
Recoveries in excess of AROs (3)
472
 356
Public purpose programs (4)
785
 674
Employee benefit plans (5)
423
 421
Other1,121
 824
Total long-term regulatory liabilities$9,038
 $8,539
    

Balance at
(in millions)March 31, 2020December 31, 2019
Cost of removal obligations (1)
$6,593  $6,456  
Recoveries in excess of AROs (2)
66  393  
Public purpose programs (3)
903  817  
Employee benefit plans (4)
760  750  
Other929  854  
Total long-term regulatory liabilities$9,251  $9,270  
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.
(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment.
(3) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 9 below.)
(4)(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(5)(4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.

Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable Balance at
(in millions)March 31, 2020December 31, 2019
Electric distribution$213  $—  
Electric transmission—  9  
Gas distribution and transmission45  363  
Energy procurement881  901  
Public purpose programs288  209  
Other675  632  
Total regulatory balancing accounts receivable$2,102  $2,114  

Payable Balance at
(in millions)March 31, 2020December 31, 2019
Electric distribution$—  $31  
Electric transmission148  119  
Gas distribution and transmission74  45  
Energy procurement585  649  
Public purpose programs565  559  
Other473  394  
Total regulatory balancing accounts payable$1,845  $1,797  

For more information, see Note 34 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.

Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:
 Receivable Balance at
(in millions)June 30, 2019 December 31, 2018
Electric distribution$465
 $160
Electric transmission91
 128
Utility generation92
 79
Gas distribution and transmission173
 462
Energy procurement654
 168
Public purpose programs97
 111
Other312
 327
Total regulatory balancing accounts receivable$1,884
 $1,435


45
 Payable Balance at
(in millions)June 30, 2019 December 31, 2018
Electric transmission135
 134
Gas distribution and transmission6
 9
Energy procurement308
 59
Public purpose programs610
 587
Other311
 287
Total regulatory balancing accounts payable$1,370
 $1,076


For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.



NOTE 5: DEBT
NOTE 5
: DEBT

Debtor-In-Possession Facilities

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court.

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 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 to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case.

On February 1, 2019,January 29, 2020, the Utility borrowed $350$500 million under the DIP Revolving Facility. On April 3, 2019, following the Bankruptcy Court’s final approval of the DIP Facilities, the Utility borrowed $1.5 billion under the DIP InitialDelayed Draw Term Loan Facility and repaid the $350 million outstanding under the DIP Revolving Facility.

The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility. For more information, see Note 155 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.

Debtor-in-Possession Financing

The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at June 30, 2019:March 31, 2020:
(in millions)Termination
Date		Aggregate LimitTerm Loan BorrowingsRevolver
Borrowings		Letters of Credit OutstandingAggregate
Availability
DIP FacilitiesDecember 2020(1) $5,500  $2,000  $—  $774  $2,726  
(in millions)
Termination
Date
 Aggregate Limit Term Loan Borrowings 
Revolver
Borrowings
 Letters of Credit Outstanding 
Aggregate
Availability
DIP FacilitiesDecember 2020(1)$5,500
 $1,500
 $—
 $521
 $3,479
            
(1) May be extended to December 2021, subject to satisfaction of certain terms and conditions, including payment of a 25 basis point extension fee.


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As of June 30, 2019,March 31, 2020, PG&E Corporation and the Utility each had no0 commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

47

Debt

The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise:
  Balance at, Balance at
(in millions) Contractual Interest Rates June 30, 2019 December 31, 2018(in millions)Contractual Interest RatesMarch 31, 2020December 31, 2019
Treatment under Plan (1)
Debt Subject to Compromise (1)
    
Debt Subject to Compromise (2)
Debt Subject to Compromise (2)
PG&E Corporation    PG&E Corporation
Borrowings under Pre-Petition Credit Facilities    
Borrowings under Pre-Petition Credit FacilityBorrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 
 variable rate(2)
 $300
 $300
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022
variable rate (3)
$300  $300  Repaid in cash  
Other borrowings:    
Other borrowings Other borrowings  
Term Loan - Stated Maturity: 2020 
 variable rate(3)
 350
 350
Term Loan - Stated Maturity: 2020  
 variable rate (4)
350  350  Repaid in cash  
Total PG&E Corporation Debt Subject to Compromise 650
 650
Total PG&E Corporation Debt Subject to Compromise650  650  
    
Utility    Utility
Senior Notes - Stated Maturity: 
  Senior Notes - Stated Maturity:
2020 3.50% 800
 800
2020  3.50%800  800  Exchanged for New Utility Short-Term Notes  
2021 3.25% to 4.25% 550
 550
2021  3.25% to 4.25%550  550  Exchanged for New Utility Short-Term Notes  
2022 2.45% 400
 400
2022  2.45%400  400  Exchanged for New Utility Short-Term Notes  
2023 3.25% to 4.25% 1,175
 1,175
2023  3.25% to 4.25%1,175  1,175  Reinstated  
2024 through 2047 2.95% to 6.35% 14,600
 14,600
Unamortized discount, net of premium and debt issuance costs —
 (178)
Total Senior notes, net of premium and debt issuance costs 17,525
 17,347
2024 through 20282024 through 20282.95% to 4.65%3,850  3,850  Reinstated  
2034 through 20402034 through 20405.40% to 6.35%5,700  5,700  Exchanged for New Utility Long-Term Notes  
2041 through 20422041 through 20423.75% to 4.50%1,000  1,000  Reinstated  
204320434.60%375  375  Reinstated  
204320435.13%500  500  Exchanged for New Utility Long-Term Notes  
2044 through 20472044 through 20473.95% to 4.75%3,175  3,175  Reinstated  
Total Senior notesTotal Senior notes17,525  17,525  
Pollution Control Bonds - Stated Maturity:    Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026 (4)
 1.75% 100
 100
Series 2009 A-B, due 2026 (5)
 
variable rate (6)
 149
 149
Series 1996 C, E, F, 1997 B due 2026 (5)
 
variable rate (7)
 614
 614
Series 2008 F and 2010 E, due 2026 (5)
Series 2008 F and 2010 E, due 2026 (5)
1.75%100  100  Repaid in cash  
Series 2009 A-B, due 2026 (6)
Series 2009 A-B, due 2026 (6)
variable rate (7)
149  149  Exchanged for New Utility Funded Debt Exchange Notes  
Series 1996 C, E, F, 1997 B due 2026 (6)
Series 1996 C, E, F, 1997 B due 2026 (6)
variable rate (8)
614  614  Exchanged for New Utility Funded Debt Exchange Notes  
Total pollution control bonds 863
 863
Total pollution control bonds863  863  
Borrowings under Pre-Petition Credit Facilities    Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022 (8)
 
 variable rate(9)
 2,965
 2,965
Utility Revolving Credit Facilities - Stated Maturity: 2022 (9)
Utility Revolving Credit Facilities - Stated Maturity: 2022 (9)
 variable rate (10)
2,888  2,888  Exchanged for New Utility Funded Debt Exchange Notes  
Other borrowings:    Other borrowings:
Term Loan - Stated Maturity: 2019 
 variable rate(10)
 250
 250
Term Loan - Stated Maturity: 2019
 variable rate (11)
250  250  Exchanged for New Utility Funded Debt Exchange Notes  
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise 3,215
 3,215
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise3,138  3,138  
Total Utility Debt Subject to Compromise 21,603
 21,425
Total Utility Debt Subject to Compromise21,526  21,526  
Total PG&E Corporation Consolidated Debt Subject to Compromise $22,253
 $22,075
Total PG&E Corporation Consolidated Debt Subject to Compromise$22,176  $22,176  
    
(1) The treatments of debt under the Plan, described in this column relate only to the treatment of principal amounts and not pre-petition or post-petition interest. The New Utility Short-Term Notes, New Utility Long-Term Senior Notes and New Utility Funded Debt Exchange Notes are described in more detail under “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2.
48

(2) Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Utility Debt Subject to Compromise does not include $285 million of accrued contractual interest to the Petition Date. At March 31, 2019,of $1 million and $286 million for PG&E Corporation and the Utility, wrote off $178respectively, to the Petition Date. Total Debt Subject to Compromise also does not include post-petition interest of $20 million and $815 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Condensed Consolidated Balance Sheets.Noteholder RSA. See NotesNote 2 and 4 for further details.
(2)(3) At June 30, 2019,March 31, 2020, the contractual LIBOR-based interest rate on loans was 3.87%2.46%.
(3)(4) At June 30, 2019,March 31, 2020, the contractual LIBOR-based interest rate on the term loan was 3.60%2.18%.
(4)(5) Pollution Control Bonds series 2008F and 2010E were reissued in June 2017.  Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022.


(5)(6) Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(6)(7) At June 30, 2019,March 31, 2020, the contractual interest rate on the letter of credit facilityfacilities supporting these bonds was 7.70%6.45%.
(7)(8) At June 30, 2019,March 31, 2020, the contractual interest rate on the letter of credit facilityfacilities supporting these bonds ranged from 7.70%6.45% to 7.83%6.58%.
(8)(9) Also includes $79At March 31, 2020, excludes $19 million inof undrawn letters of credit.
(9)(10) At June 30, 2019,March 31, 2020, the contractual LIBOR-based interest rate on the loans was 3.67%2.26%.
(10)(11) At June 30, 2019,March 31, 2020, the contractual LIBOR-based interest rate on the term loan was 3.00%1.58%.

Debt Commitments

See “Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitments Letters” in Note 2 of the Condensed Consolidated Financial Statements above for discussion of the debt commitments.

NOTE 6: EQUITY

There were no0 issuances under the PG&E Corporation February 2017 equity distribution agreement for the sixthree months ended June 30, 2019.March 31, 2020.

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans.  During the six months ended June 30, 2019, 8.9 million shares were issued for cash proceeds of $85 million under these plans. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the Northern California wildfires. See Wildfire-related contingenciesContingencies in Note 10 below.

The DIP Credit Agreement includes usual and customary covenants for debtor-in-possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, declare and pay any dividend or make any other distributions with respect to any of their capital stock. Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirementsrequirements” under applicable law and the Utility’s wildfire mitigation plan.”Wildfire Mitigation Plan. On March 20, 2020, PG&E Corporation doesand the Utility filed a Case Resolution Contingency Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not expect to pay any cashcommon dividends duringuntil it has recognized $6.2 billion in non-GAAP core earnings following the Chapter 11 Cases.Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

Equity Backstop Commitments

See “Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters” in Note 2 of the Condensed Consolidated Financial Statements above for discussion of the equity backstop commitments.

49

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS areis calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
Three Months Ended March 31,
(in millions, except per share amounts)20202019
Income available for common shareholders$371  $136  
Weighted average common shares outstanding, basic529  526  
Add incremental shares from assumed conversions:
Employee share-based compensation—  1  
Chapter 11-related settlements (1)
119  —  
Weighted average common shares outstanding, diluted648  527  
Total income per common share, diluted$0.57  $0.25  
 Three Months Ended June 30, Six Months Ended June 30,
(in millions, except per share amounts)2019 2018 2019 2018
Loss attributable to common shareholders$(2,553) $(984) $(2,420) $(542)
Weighted average common shares outstanding, basic529
 516
 528
 516
Add incremental shares from assumed conversions:       
Employee share-based compensation—
 —
 —
 1
Weighted average common shares outstanding, diluted529
 516
 528
 517
Total loss per common share, diluted$(4.83) $(1.91) $(4.58) $(1.05)
(1) As discussed in Note 2, the financing sources for the Plan are expected to include (1) one or more PG&E Corporation common stock offerings of up to $9.0 billion and (2) the issuance of new common stock to the Fire Victim Trust. These financing sources along with the Backstop Commitment premium of 119.0 million shares of common stock (which could increase by 19,909,091 additional shares) for the Backstop Commitments will dilute current equity interests if or when such common stock is issued. At March 31, 2020, only the Backstop Commitment premium meets the requirements to be presented as incremental shares in the calculation of diluted income per common share.


For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.



NOTE 8: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.  By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices.

Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party.  The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.  

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives.  Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Condensed Consolidated Balance Sheets.Sheets at fair value.

50

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume at
Underlying ProductInstrumentsMarch 31, 2020December 31, 2019
Natural Gas (1) (MMBtus (2))
Forwards, Futures and Swaps138,102,835  131,896,159  
 Options7,760,000  14,720,000  
Electricity (Megawatt-hours)Forwards, Futures and Swaps49,291,087  18,675,852  
Options4,414,400  —  
 
Congestion Revenue Rights (3)
298,648,904  308,467,999  
    Contract Volume at
Underlying Product Instruments June 30,
2019		 December 31,
2018
Natural Gas (1) (MMBtus (2))
 Forwards, Futures and Swaps 174,575,917
 177,750,349
  Options 16,455,000
 13,735,405
Electricity (Megawatt-hours) Forwards, Futures and Swaps 2,999,616
 3,833,490
  Options 912,033
 —
  
Congestion Revenue Rights (3)
 329,571,344
 340,783,089
       
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At June 30,March 31, 2020, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash Collateral
Total Derivative
Balance
Current assets – other$35  $(6) $11  $40  
Other noncurrent assets – other133  —  —  133  
Current liabilities – other(31) 6  1  (24) 
Noncurrent liabilities – other(138) —  —  (138) 
Total commodity risk$(1) $—  $12  $11  

At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$36  $(6) $4  $34  
Other noncurrent assets – other130  (6) —  124  
Current liabilities – other(31) 6  2  (23) 
Noncurrent liabilities – other(130) 6  —  (124) 
Total commodity risk$5  $—  $6  $11  
 Commodity Risk
(in millions)
Gross Derivative
Balance
 Netting Cash Collateral 
Total Derivative
Balance
Current assets – other$47
 $(4) $48
 $91
Other noncurrent assets – other161
 —
 —
 161
Current liabilities – other(25) 4
 3
 (18)
Noncurrent liabilities – other(67) —
 —
 (67)
Total commodity risk$116
 $—
 $51
 $167



At December 31, 2018, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)
Gross Derivative
Balance
 Netting Cash Collateral 
Total Derivative
Balance
Current assets – other$44
 $(1) $89
 $132
Other noncurrent assets – other165
 —
 —
 165
Current liabilities – other(29) 1
 7
 (21)
Noncurrent liabilities – other(90) —
 2
 (88)
Total commodity risk$90
 $—
 $98
 $188


Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. During the first quarter of 2019, multiple credit rating agencies downgraded the Utility’s credit ratings below investment grade, which resulted in the Utility posting additional collateral. As of June 30, 2019,March 31, 2020, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

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NOTE 9: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

•
•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.

 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.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.



Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
Fair Value MeasurementsFair Value Measurements
June 30, 2019March 31, 2020
(in millions)Level 1 Level 2 Level 3 
Netting (1)
 Total(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:         Assets:
Short-term investments$3,402
 $—
 $—
 $—
 $3,402
Short-term investments$1,717  $—  $—  $—  $1,717  
Nuclear decommissioning trusts         Nuclear decommissioning trusts
Short-term investments16
 —
 —
 —
 16
Short-term investments82  —  —  —  82  
Global equity securities1,959
 —
 —
 —
 1,959
Global equity securities1,792  —  —  —  1,792  
Fixed-income securities815
 698
 —
 —
 1,513
Fixed-income securities784  734  —  —  1,518  
Assets measured at NAV—
 —
 —
 —
 19
Assets measured at NAV—  —  —  —  17  
Total nuclear decommissioning trusts (2)
2,790
 698
 —
 —
 3,507
Total nuclear decommissioning trusts (2)
2,658  734  —  —  3,409  
Price risk management instruments (Note 8)         Price risk management instruments (Note 8)
Electricity—
 13
 192
 20
 225
Electricity—  7  159  5  171  
Gas—
 3
 —
 24
 27
Gas—  2  —  —  2  
Total price risk management instruments—
 16
 192
 44
 252
Total price risk management instruments—  9  159  5  173  
Rabbi trusts         Rabbi trusts
Fixed-income securities—
 98
 —
 —
 98
Fixed-income securities—  102  —  —  102  
Life insurance contracts—
 71
 —
 —
 71
Life insurance contracts—  76  —  —  76  
Total rabbi trusts—
 169
 —
 —
 169
Total rabbi trusts—  178  —  —  178  
Long-term disability trust         Long-term disability trust
Short-term investments5
 —
 —
 —
 5
Short-term investments6  —  —  —  6  
Assets measured at NAV—
 —
 —
 —
 142
Assets measured at NAV—  —  —  —  157  
Total long-term disability trust5
 —
 —
 —
 147
Total long-term disability trust6  —  —  —  163  
TOTAL ASSETS$6,197
 $883
 $192
 $44
 $7,477
TOTAL ASSETS$4,381  $921  $159  $5  $5,640  
Liabilities:         Liabilities:
Price risk management instruments (Note 8)         Price risk management instruments (Note 8)
Electricity$—
 $4
 $83
 $(4) $83
Electricity$—  $5  $164  $(7) $162  
Gas2
 3
 —
 (3) 2
Gas—  —  —  —  —  
TOTAL LIABILITIES$2
 $7
 $83
 $(7) $85
TOTAL LIABILITIES$—  $5  $164  $(7) $162  
         
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $491$498 million, primarily related to deferred taxes on appreciation of investment value.



52

Fair Value MeasurementsFair Value Measurements
December 31, 2018December 31, 2019
(in millions)Level 1 Level 2 Level 3 
Netting (1)
 Total(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:         Assets:
Short-term investments$1,593
 $—
 $—
 $—
 $1,593
Short-term investments$1,323  $—  $—  $—  $1,323  
Nuclear decommissioning trusts         Nuclear decommissioning trusts
Short-term investments29
 —
 —
 —
 29
Short-term investments6  —  —  —  6  
Global equity securities1,793
 —
 —
 —
 1,793
Global equity securities2,086  —  —  —  2,086  
Fixed-income securities661
 639
 —
 —
 1,300
Fixed-income securities862  728  —  —  1,590  
Assets measured at NAV—
 —
 —
 —
 16
Assets measured at NAV—  —  —  —  21  
Total nuclear decommissioning trusts (2)
2,483
 639
 —
 —
 3,138
Total nuclear decommissioning trusts (2)
2,954  728  —  —  3,703  
Price risk management instruments (Note 8)         Price risk management instruments (Note 8)
Electricity—
 5
 203
 51
 259
Electricity—  2  161  (11) 152  
Gas—
 1
 —
 37
 38
Gas—  3  —  3  6  
Total price risk management instruments—
 6
 203
 88
 297
Total price risk management instruments—  5  161  (8) 158  
Rabbi trusts         Rabbi trusts
Fixed-income securities—
 93
 —
 —
 93
Fixed-income securities—  100  —  —  100  
Life insurance contracts—
 67
 —
 —
 67
Life insurance contracts—  73  —  —  73  
Total rabbi trusts—
 160
 —
 —
 160
Total rabbi trusts—  173  —  —  173  
Long-term disability trust         Long-term disability trust
Short-term investments7
 —
 —
 —
 7
Short-term investments10  —  —  —  10  
Assets measured at NAV—
 —
 —
 —
 155
Assets measured at NAV—  —  —  —  156  
Total long-term disability trust7
 —
 —
 —
 162
Total long-term disability trust10  —  —  —  166  
TOTAL ASSETS$4,083
 $805
 $203
 $88
 $5,350
TOTAL ASSETS$4,287  $906  $161  $(8) $5,523  
Liabilities:         Liabilities:
Price risk management instruments (Note 8)         Price risk management instruments (Note 8)
Electricity$4
 $5
 $108
 $(10) $107
Electricity$1  $2  $156  $(13) $146  
Gas—
 2
 —
 —
 2
Gas—  2  —  (1) 1  
TOTAL LIABILITIES$4
 $7
 $108
 $(10) $109
TOTAL LIABILITIES$1  $4  $156  $(14) $147  
         
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $408$530 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the three and six months ended June 30, 2019March 31, 2020 and 2018.2019.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.


53

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. 

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices.  CRRs are classified as Level 3.

Equity Backstop Commitments

The Backstop Commitments are defined as financial instruments and measurable at fair value on each reporting period. PG&E Corporation used both market observable inputs and unobservable data to derive the fair value as of the reporting date. The Backstop Commitments are classified as Level 3.

Fair value for the Backstop Commitments as of March 31, 2020, was $0. PG&E Corporation’s fair valuation model calculated both the Backstop Party’s commitment to fund up to $9.0 billion in new common stock as well as PG&E Corporation’s Backstop Commitment premium obligation. The commitment to fund new common stock will cease upon equity offerings to finance the transactions contemplated by the Plan or termination of Backstop Commitments. As of March 31, 2020, PG&E Corporation expects to record approximately $1 billion of expense related to the Backstop Commitment premium in Reorganization items, net for the year ended December 31, 2020. This fair value calculation is subject to change based on fluctuations in the price of PG&E Corporation’s common stock as well as the satisfaction of certain conditions in the Backstop Commitment Letters.

Level 3 Measurements and SensitivityUncertainty Analysis

The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives.  The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

54

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 8 above.)
  Fair Value at      
(in millions) June 30, 2019      
Fair Value Measurement Assets Liabilities Valuation
Technique		 Unobservable
Input		 
Range (1)
Congestion revenue rights $191
 $64
 Market approach CRR auction prices $(13.11) - 22.76
Power purchase agreements $1
 $19
 Discounted cash flow Forward prices $ 19.68 - 38.80
           
(1) Represents price per megawatt-hour.

Fair Value at
(in millions)March 31, 2020
Fair Value MeasurementAssetsLiabilitiesValuation
Technique		Unobservable
Input
Range(1) /Weighted-Average Price (2)
Congestion revenue rights$141  $45  Market approachCRR auction prices$(45.08) - $20.20 / 0.27
Power purchase agreements$18  $119  Discounted cash flowForward prices$9.42 - $57.42 / 32.04


  Fair Value at      
(in millions) December 31, 2018      
Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input 
Range (1)
Congestion revenue rights $203
 $75
 Market approach CRR auction prices $ (18.61) - 32.26
Power purchase agreements $—
 $33
 Discounted cash flow Forward prices $ 19.81 - 38.80
           
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Fair Value at
(in millions)December 31, 2019
Fair Value MeasurementAssetsLiabilitiesValuation TechniqueUnobservable Input
Range (1)/Weighted-Average Price (2)
Congestion revenue rights$140  $44  Market approachCRR auction prices$(20.20) - $20.20 / 0.28
Power purchase agreements$21  $112  Discounted cash flowForward prices$11.77 - $59.38 / 33.62
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following tables presenttable presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2019March 31, 2020 and 2018:2019:
Price Risk Management Instruments
(in millions)20202019
Asset balance as of January 1$5  $95  
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)
(10) 34  
Asset balance as of March 31$(5) $129  
 Price Risk Management Instruments
(in millions)2019 2018
Asset (liability) balance as of April 1$129
 $40
Net realized and unrealized gains:   
Included in regulatory assets and liabilities or balancing accounts (1)
(20) (6)
Asset (liability) balance as of June 30$109
 $34
    
(1) The costs related to price risk management activities are fully passed through to customers in rates.  Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

 Price Risk Management Instruments
(in millions)2019 2018
Asset (liability) balance as of January 1$95
 $42
Net realized and unrealized gains:   
Included in regulatory assets and liabilities or balancing accounts (1)
14
 (8)
Asset (liability) balance as of June 30$109
 $34
    
(1) The costs related to price risk management activities are fully passed through to customers in rates.  Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable; short-term borrowings; accounts payable; and customer deposits to approximate their carrying values at June 30, 2019March 31, 2020 and December 31, 2018,2019, as they are short-term in nature. 

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
At March 31, 2020At December 31, 2019
(in millions)Carrying AmountLevel 2 Fair ValueCarrying AmountLevel 2 Fair Value
Debt (Note 5)
PG&E Corporation (1)
$—  $—  $—  $—  
Utility (1)(2)
2,000  2,007  1,500  1,500  
 At June 30, 2019 At December 31, 2018
(in millions)Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value
PG&E Corporation(1)
$—
 $—
 $350
 $350
Utility(1)(2)
1,500
 1,500
 17,450
 14,747
        
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation and the Utility became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 4.5.
(2)The Utility drew $350 million from the DIP Revolving Facility on February 1, 2019 which was subsequently repaid on April 3, 2019 using certainfair value of the proceedsUtility pre-petition debt is $17.2 billion and $17.9 billion as of the DIP Initial Term Loan Facility.March 31, 2020 and December 31, 2019, respectively. For more information, see Note 2 and Note 5.
55



Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:
(in millions)
As of March 31, 2020Amortized
Cost		Total Unrealized GainsTotal Unrealized LossesTotal Fair
Value
Nuclear decommissioning trusts
Short-term investments$82  $—  $—  $82  
Global equity securities652  1,188  (31) 1,809  
Fixed-income securities1,377  155  (14) 1,518  
Total (1)
$2,111  $1,343  $(45) $3,409  
As of December 31, 2019
Nuclear decommissioning trusts
Short-term investments$6  $—  $—  $6  
Global equity securities500  1,609  (2) 2,107  
Fixed-income securities1,505  89  (4) 1,590  
Total (1)
$2,011  $1,698  $(6) $3,703  
(in millions)       
As of June 30, 2019Amortized
Cost		 Total Unrealized Gains Total Unrealized Losses Total Fair
Value
Nuclear decommissioning trusts       
Short-term investments$16
 $—
 $—
 $16
Global equity securities496
 1,486
 (4) 1,978
Fixed-income securities1,431
 84
 (2) 1,513
Total (1)
$1,943
 $1,570
 $(6) $3,507
As of December 31, 2018       
Nuclear decommissioning trusts       
Short-term investments$29
 $—
 $—
 $29
Global equity securities568
 1,246
 (5) 1,809
Fixed-income securities1,288
 30
 (18) 1,300
Total (1)
$1,885
 $1,276
 $(23) $3,138
        
(1) Represents amounts before deducting $491$498 million and $408$530 million for the periods ended June 30, 2019March 31, 2020 and December 31, 2018,2019, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:
As of
(in millions)March 31, 2020
Less than 1 year$26 
1–5 years397 
5–10 years408 
More than 10 years687 
Total maturities of fixed-income securities$1,518 
 As of
(in millions)June 30, 2019
Less than 1 year$26
1–5 years541
5–10 years340
More than 10 years606
Total maturities of fixed-income securities$1,513

The following table provides a summary of activity for fixed income and equity securities:
Three Months Ended March 31,
(in millions)20202019
Proceeds from sales and maturities of nuclear decommissioning trust investments$533  $346  
Gross realized gains on securities18  (34) 
Gross realized losses on securities(9) 19  
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Proceeds from sales and maturities of nuclear decommissioning trust investments$171
 $308
 $517
 $802
Gross realized gains on securities56
 11
 22
 48
Gross realized losses on securities(26) (5) (7) (9)


NOTE 10: WILDFIRE-RELATED CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses 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 provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

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Pre-petition Wildfire-Related Claims

Wildfire-relatedPre-petition wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

At June 30, 2019March 31, 2020 and December 31, 2018,2019, the Utility’s Condensed Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims as follows:
 Balance at
(in millions)June 30, 2019 December 31, 2018
2015 Butte fire$212
 $226
2017 Northern California wildfires5,500
 3,500
2018 Camp fire12,400
 10,500
Total wildfire-related claims (1)
$18,112
 $14,226
    
of $25.5 billion. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire is comprised of (i) $11 billion for subrogated insurance claimholders pursuant to the Subrogation RSA, plus (ii) $47.5 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the Subrogation RSA, plus (iii) $1 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (iv) $13.5 billion for all other wildfire-related claims, including individual wildfire claimholders (including those with uninsured and underinsured property losses) and clean-up and fire suppression costs, pursuant to the TCC RSA. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire corresponds PG&E Corporation’s and the Utility’s best estimate of probable losses and is subject to change based on additional information, including the other factors discussed below. (See “2018 Camp Fire, 2017 Northern California Wildfires and 2015 Butte Fire Accounting Charge” below.)
(1)
On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. As of June 30, 2019, $100 million was reclassified from LSTC to current liabilities - wildfire-related claims to reflect Bankruptcy Court approval of contributions to the Wildfire Assistance Fund.

In addition, during the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $19$34 million and $32$47 million respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $7 million and $41 million, respectively, related to the 2017 Northern California wildfires as compared to $46 million and $68 million, respectively, in the same periods in 2018.2015 Butte fire during the quarters ended March 31, 2020 and 2019, respectively.

2018 Camp Fire Background

OnAccording to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of July 9,November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 13,972 residences, 528 commercial18,804 structures and 4,293 other buildings resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website.

On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release:

•Cal Fire determined that the 2018 Camp fire was caused by electrical transmission lines owned and operated by the Utility near Pulga, California.

•Cal Fire identified a second ignition site and stated that the second fire was consumed by the original fire which started earlier near Pulga, California. Cal Fire stated that the cause of the second fire was determined to be “vegetation into electrical distribution lines owned and operated by” the Utility.

Cal Fire indicated in its news release that its investigation report forAs described under the 2018 Camp fire has been forwarded to the Butte County District Attorney. (Seeheading “District Attorneys’ Offices’ Investigations” below, for further information regarding the investigations of the 2018 Camp fire.)fire was the subject of a criminal investigation, which has been settled, as to PG&E Corporation and the Utility, by the parties, subject to court approvals from the Bankruptcy Court, which was granted as of April 14, 2020, and the Butte County Superior Court, currently scheduled to occur on or about May 26, 2020. As of the date of this filing, thisCal Fire’s investigation report has not been released publicly.shared with PG&E Corporation or the Utility.

PG&E Corporation and the Utility accepthave accepted Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire.


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Further, the CPUC’s SED is conductingalso conducted investigations to assessinto whether the compliance of electric and communication companies’ facilitiesUtility committed civil violations in connection with applicable rules and regulations in areas impacted by the 2018 Camp fire. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities may also be investigating the fire. It is uncertain when the investigations will be complete and whetherOn November 26, 2019, the SED will release any preliminary findings beforeconcluded its investigations are complete.investigation into the 2018 Camp fire and released a report alleging certain violations of state law and CPUC regulations. See “Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 11 for a description of these proceedings, including the alleged violations in connection with the 2018 Camp fire.

2017 Northern California Wildfires Background

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

Cal Fire has issued 19 investigation reports and two supplementary investigation reports that include its determination ofinvestigated the causes of 21 of the 2017 Northern California wildfires and alleged that all of these fires, withmade the exception of the Tubbs fire, involved following determinations:

•the Utility’s equipment.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern Californiaequipment was involved in causing 20 wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket, Atlas, Cascade, Pressley, Point and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, NevadaYoungs fires); and Napa counties). According to the Cal Fire news releases:

the La Porte, McCourtney, Lobo and Honey fires “were caused by trees coming into contact with power lines,” and

the Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires “were caused by electric power and distribution lines, conductors and the failure of power poles.”

Cal Fire stated in its news releases that the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fire investigations, and the investigation related to the Honey fire, have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations by the District Attorneys’ offices related to these fires.)

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the Cascade fire by the Office of the District Attorney of Yuba County.)

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that •the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

During the second quarter of 2019, Cal Fire released its investigation reports related to the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. The Cal Fire investigation report for the Adobe fire included as Attachment 42.1 a “Supplementary Investigation Report” concerning the Pressley fire. The Cal Fire investigator concludes in the Supplementary Investigation Report that the Pressley fire was started by an ember cast from the Adobe fire.

On July 24, 2019, the CPUC released copies of Cal Fire’s investigation report related to the Point fire and supplementary investigation reports related to the Youngs fire, which Cal Fire had not previously released publicly, as attachments to the SED’s own investigative reports for those fires. (The Youngs fire is the fire that the Utility has previously referred to as the Maacama fire.) The Cal Fire investigation report for the Point fire alleges that the fire was caused by a tree limb that broke off in high winds and fell into a power line, causing the power line to contact the ground. The Cal Fire investigators in the Youngs supplementary reports conclude that the fire was caused by a tree that fell into a power line, severing the line.



Cal Fire has not yet released its investigation reports related to the McCourtney and Lobo fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential.

As described in Note 11, on June 27, 2019,under the CPUC issued an OII disclosing the findings of a June 13, 2019 report by the SED, which, among other things, alleges that the Utility committed 27 violations in connection with 12heading “District Attorney’s Offices’ Investigations” below, certain of the 2017 Northern California wildfires (specifically,were the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphursubject of criminal investigations, which have been settled or resulted in PG&E Corporation and Youngs fires). As described in the OII, the 27 alleged violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizing a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identifiedUtility being informed by the applicable district attorney’s office of a decision not to prosecute.

The SED also conducted investigations into whether the Utility committed civil violations in connection with the Cherokee, La Porte and Tubbs fires. The 37 fire was determined by2017 Northern California wildfires. See “Order Instituting an Investigation into the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement2017 Northern California Wildfires and the information contained2018 Camp Fire” in its investigation reports related toNote 11 for a description of these fires remains confidential. On a status conference call beforeproceedings, including the assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal chargesalleged violations in connection with the Lobo and McCourtney fires, the SED may add alleged violations related to those fires and the 2018 Camp fire to the OII. As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violations set forth in the OII. The Utility also filed a Corrective Actions Report and an Application to Develop a Mobile Application and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019, the Utility submitted a report to respond to the information requests contained in the OII, relating to matters such as the Utility’s vegetation management procedures and practices, its use of recloser devices in high fire risk areas, its pro-active de-energization of powerlines during times of high fire danger and its recordkeeping and other practices.

Further, the SED is conducting investigations into certain of the other 2017 Northern California wildfires, including the McCourtney and Lobo fires. Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.wildfires.

Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.)

On October 25, 2019, PG&E Corporation and the Utility submitted a brief to the Bankruptcy Court challenging the application of inverse condemnation to California’s investor-owned utilities, including the Utility. The Bankruptcy Court heard argument regarding PG&E Corporation’s and the Utility’s motion on November 19, 2019. On December 3, 2019, the Bankruptcy Court entered an order holding that the doctrine of inverse condemnation applied to California’s investor-owned utilities, including the Utility, and certifying the decision for direct appeal to the U.S. Court of Appeals for the Ninth Circuit. PG&E Corporation and the Utility have appealed this decision; however, as of the date of this filing, this appeal was stayed upon request of PG&E Corporation and the Utility due to, among other things, the settlement of fire claims embodied in the Public Entity PSA’s, TCC RSA and Subrogation RSA.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent.
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Further, the Utility could be subject to material fines, penalties, or restitution orders if the CPUC or any law enforcement agency were to bring an enforcement action, including, if the Plea Agreement is terminated, a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations.



As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine9 of which sought to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process.

As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five5 of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires included claims under multiple theories of liability, including, but not limited to, inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages.

As described below under the heading “Restructuring Support Agreement with the TCC,” on December 6, 2019, PG&E Corporation’sCorporation and the Utility’s obligationsUtility entered into a RSA with respectthe TCC, the Consenting Fire Claimant Professionals and the Shareholder Proponents to suchpotentially resolve all wildfire-related claims are expectedrelating to be determinedthe 2017 Northern California wildfires and the 2018 Camp fire (other than subrogated insurance claims and Public Entity Wildfire Claims) through the Chapter 11 process. However, the TCC has submitted a motion toOn December 19, 2019, the Bankruptcy Court seeking relief fromentered an order approving the automatic stay to enable certain plaintiffs to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.TCC RSA.

Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations wereare similar to the ones made by individual plaintiffs. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, insurance carriers have filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation’sCorporation and the Utility’s obligationsUtility entered into a RSA with respectcertain holders of insurance subrogation claims to suchpotentially resolve all insurance subrogation claims are expectedrelating to be determinedthe 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process. However, certain holders of subrogation claims have submitted motions toOn December 19, 2019, the Bankruptcy Court seeking relief fromentered an order approving the automatic stay in order to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.Subrogation RSA.

Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations wereare similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process. The PSAs do not require Bankruptcy Court approval to be effective; however, the Bankruptcy Court must ultimately approve the Plan that incorporates the terms of the PSAs.


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FEMA has filed proofs of claim in the Chapter 11 Cases in the amount of $1.2 billion in connection with the 2017 Northern California wildfires and $2.6 billion in connection with the 2018 Camp fire. FEMA has objected to the classification of their claims under the Plan as Fire Victim Claims and has indicated that it intends to seek to have its claims classified separately from the Fire Victim Claims. In addition, Cal Fire has filed proofs of claim in the Chapter 11 Cases in the amount of $133 million in connection with the 2017 Northern California wildfires and specifying at least $110 million in connection with the 2018 Camp fire. The OES has filed proofs of claim in the amount of $347 million in connection with the 2017 Northern California wildfires and $2.3 billion in connection with the 2018 Camp fire. The California Department of Transportation has filed proofs of claim in the Chapter 11 Cases in the amount of $217 million in connection with the 2018 Camp fire.

Certain other Federal, state and local entities (that are not Supporting Public Entities) have filed proofs of claim in the Chapter 11 Cases in connection with the 2017 Northern California wildfires and the 2018 Camp fire asserting total claims in the amount of $503 million. Proofs of claim have also been filed for unspecified amounts to be determined at a later time. On December 12, 2019, the TCC filed an objection to the claims filed by OES in which it argued that the Bankruptcy Court should disallow the OES claims. On January 9, 2020, the TCC filed a supplement to its objection in which it also objected to the claims filed by FEMA. On February 5, 2020, PG&E Corporation and the Utility joined in the TCC’s objection to the OES and FEMA claims. On February 12, 2020, a number of individuals and businesses who hold wildfire-related claims in connection with the 2015 Butte fire, 2017 Northern California wildfires and 2018 Camp fire, as well as certain preference plaintiffs (the “Tubbs Preference Plaintiffs”), joined in the TCC’s objection to the OES and FEMA claims. Also on February 12, 2020, OES and FEMA filed oppositions to the TCC’s objection. On February 26, 2020, the Bankruptcy Court heard argument over the TCC’s and PG&E Corporation’s and the Utility’s legal objections to claims filed by FEMA and Cal OES. On February 27, 2020, the TCC, the Consenting Fire Claimant Professionals (as defined in the Plan), FEMA and certain other federal agencies, the OES and certain other state agencies, the Debtors, and the Shareholder Proponents participated in a mediation in San Francisco, California in an effort to resolve the aforementioned claims.

On April 21, 2020, the parties announced that settlement agreements had been reached with certain Federal agencies (including FEMA and the United States Small Business Administration (the “SBA”)) and certain State agencies (including Cal OES and Cal Fire) regarding their claims filed against PG&E Corporation or the Utility in the Chapter 11 Cases which constitute “Fire Claims” (as defined in the Plan). Pursuant to the terms of the settlement agreements, the Fire Claims of FEMA and the SBA will be allowed at $1 billion, channeled to the Fire Victim Trust, and fully subordinated and junior in right of payment to the prior payment in full of all other Fire Victim Claims from the Fire Victim Trust; $117 million will be paid to the DOJ in full and final satisfaction and discharge of the Fire Claims of certain other Federal agencies and payable solely from the proceeds of the “Assigned Rights and Causes of Action” (as defined in the Plan), after the payment of professional fees and costs incurred in connection with the prosecution of such Assigned Rights and Causes of Action; Cal OES’s Fire Claims will be withdrawn with prejudice; Cal Fire’s Fire Claims will be allowed at $115.3 million, payable over a period of years by the Fire Victim Trust, with the first $70 million payable solely and exclusively from any cash interest earned on the cash holdings of the Fire Victim Trust after the Effective Date and the remaining $45.3 million payable solely and exclusively from such cash interest less the expenses of administering the Fire Victim Trust in such years; the Fire Claims of certain other State agencies will be allowed at $89 million, payable by the Fire Victim Trust over a period of years, with the first $60 million payable solely and exclusively from proceeds of the monetization of the PG&E Corporation common stock in excess of $6.75 billion in accordance with an agreed-upon formula and available cash interest after expenses and after the Cal Fire Settlement Amount (as defined below) has been paid in full, and the balance payable solely and exclusively from such monetization proceeds and interest earned on the cash holdings of the Fire Victim Trust (less expenses of administering the Fire Victim Trust); and the holders of the above claims that are being settled and channeled to the Fire Victim Trust, consistent with the Plan, will have no right of recovery from PG&E Corporation or the Utility. Consistent with the Plan and the agreements, the obligations of payment relating to the agreements are solely the responsibility of the Fire Victim Trust, and PG&E Corporation and the Utility will have no further obligations with respect to the claims that are the subject of the agreements. PG&E Corporation and the Utility filed a motion seeking Bankruptcy Court approval of the agreements on April 26, 2020. A hearing before the Bankruptcy Court to consider approval of the agreements is currently scheduled for May 12, 2020.

As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. TheOn November 11, 2019, the Bankruptcy Court entered an order approving a stipulation between PG&E Corporation and the Utility and the TCC to extend the Bar Date is subjectfor unfiled, non-governmental fire claimants to certain exceptions, includingDecember 31, 2019, at 5:00 p.m. (Pacific Time). See “Potential Claims” in Note 2 above.

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Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be determined through the Chapter 11 process (including the settlement agreements described below), regulatory proceedings and any potential enforcement proceedings. The timing and outcome of these and other potential proceedings are uncertain.

Proceeding in San Francisco County Superior Court for claims arising under section 503(b)(9)Certain Tubbs Fire-Related Claims (the “Tubbs Trial”)

In connection with the TCC RSA, on December 26, 2019, the San Francisco Superior Court entered an order vacating all dates and deadlines in the Tubbs Trial and scheduled a hearing for March 2, 2020 to show cause regarding dismissal of the Tubbs Trial. On February 28, 2020, at the request of the Plaintiffs, the Court continued the hearing on the order to show cause to July 27, 2020.

On January 6, 2020, in accordance with the terms of the TCC RSA, PG&E Corporation and the Utility filed a motion with the Bankruptcy Code,Court seeking authority to enter into settlement agreements settling and liquidating the bar date for which occurred on April 22, 2019. It is expected that numerous wildfire-related claims will be filedasserted against PG&E Corporation and the Utility in connection withby each of the 2018 Camp fireTubbs Preference Plaintiffs. On January 30, 2020, the Bankruptcy Court issued an order granting PG&E Corporation and the 2017 Northern California wildfiresUtility’s motion to enter into settlement agreements with each of the Tubbs Preference Plaintiffs (the “Tubbs Preference Settlements”). The Tubbs Preference Settlements will be channeled through the Bar Date. Fire Victim Trust.

Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California (the “Estimation Proceeding”)

On July 18, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire, and the 2017 Northern California wildfires, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” below.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigations or to the McCourtney and Lobo investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs have reached an agreement to transfer available evidence collected by Cal Fire for the fires for which its investigation reports have been released to a shared storage facility. The transfer of the evidence is not yet complete. (See “District Attorneys’ Offices’ Investigations” below for information regarding certain investigations related to the 2018 Camp fire and 2017 Northern California wildfires.)

Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be resolved through the Chapter 11 process, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

PG&E Corporation and the Utility, as part of their efforts to emerge from bankruptcy, are engaged in discussions with holders of claims related to the 2017 Northern California wildfires and the 2018 Camp fire in an attempt to reach a global settlement of such claims. As discussed under the heading “Plan Support Agreements with Public Entities,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims. The most recent settlement offers made by PG&E Corporation and the Utility to subrogated insurance claimholders and individual claimholders as of the date of this filing are discussed in further detail below under the heading “2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge.” PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with other claimholders.  Even if discussions with claimholders were successful, the consummation of such a global settlement would likely be contingent on numerous uncertain conditions, including Bankruptcy Court approval and governmental action.2015 Butte fire.

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On MayAugust 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court’s decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation’s and the Utility’s petition for review.

Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims

On July 2, 2019, the TCC submitted a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order terminating the automatic stay to permit certain individual plaintiffs (the “Tubbs Preference Plaintiffs”) to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire, and to request the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires to order one or more of the cases of the Tubbs Preference Plaintiffs to trial with preference pursuant to California Code of Civil Procedure section 36. On July 9, 2019, the TCC submitted an amended motion to request relief from the stay with respect to additional individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire.

On July 3, 2019, the Ad Hoc Subrogation Group submitted a motion for relief from the automatic stay to permit certain of the Ad Hoc Subrogation Group’s members to pursue their claims against PG&E Corporation and the Utility regarding the issue of PG&E Corporation’s and the Utility’s liability for the Tubbs fire in the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires.



On July 19, 2019, PG&E Corporation and the Utility filed an objection to the motions of the TCC and the Ad Hoc Subrogation Group, requesting that the motions be denied. Also on July 19, 2019, the UCC and the Shareholder Group filed objections to the motions of the TCC and the Ad Hoc Subrogation Group with the Bankruptcy Court, requesting that the motions be denied. The Shareholder Group also joined in PG&E Corporation’s and the Utility’s objection to the motions of the TCC and the Ad Hoc Subrogation Group.

On July 22, 2019, the Bankruptcy Court issued anrecommendations to the District Court recommending the District Court order continuing the hearings on the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to August 14, 2019.

Motion for the Establishment of Wildfire Claims Estimation Procedures

On July 18, 2019, PG&E Corporation and the Utility submitted a motion, pursuant to sections 105(a) and 502(c)partial withdrawal of the Bankruptcy Code, for entryreference of an order establishing procedures and schedules for the section 502(c) estimation of PG&E Corporation’s and the Utility’s aggregate liability for contingent and/or unliquidated claims arising out of the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (which are collectively referred to in this paragraph as “wildfire claims”). In the motion, PG&E Corporation and the Utility proposed, among other things, the following general parameters of the estimation process:

First, the Bankruptcy Court would address the legal issue of whether, pursuant to the state law doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where PG&E Corporation or the Utility were not negligent.

Second, the Bankruptcy Court would schedule a hearing on the limited issue of causation of the Tubbs fire on October 7, 2019, or as soon as possible thereafter.

Third, following the Bar Date, the Bankruptcy Court would determine the aggregate value of the wildfire claims in a hearing proposed to be scheduled for early December 2019. This phase of the estimation process would involve the resolution of questions around the likelihood of success of the wildfire claims on issues such as negligence, the recoverability of certain categories of damages and the aggregate estimate of overall damages based upon sampling of claims and expert testimony. In the motion, PG&E Corporation and the Utility indicated that they are prepared to agree that, as part of the proposed estimation process, they will not contest causation with respect to any wildfire for which Cal Fire has concluded that PG&E Corporation and the Utility are responsible, includingfrom the 2018 Camp fire and the 2017 Northern California wildfires identified above, exceptwildfires. On August 23, 2019, the Tubbs fire.

The motion is expected to be heard byDistrict Court issued an order adopting the recommendation of the Bankruptcy Court on August 14, 2019. On August 7, 2019, certain third parties filed joindersin full and statements in support withordering that the reference to the Bankruptcy Court with respectbe withdrawn in part.

On October 9, 2019, the District Court issued an initial order for the estimation hearings to PG&E Corporation’sbegin on February 18, 2020 and the Utility’s motion, including the Ad Hoc Noteholder Committee, the UCC and the Shareholder Group. Alsoconclude on August 7, 2019, certain third parties filed objections to PG&E Corporation’s and the Utility’s motionFebruary 28, 2020, with the Bankruptcypossibility of an additional week of hearings if warranted.

In connection with the TCC RSA, on December 20, 2019, the District Court includingentered an order staying the CityEstimation Proceeding and County of San Francisco,vacating the Ad Hoc Subrogation GroupFebruary 18, 2020 hearing and all pre-hearing dates. Under section 502(c) and pursuant to the TCC. The objectionterms of the City and County of San Francisco is limited to PG&E Corporation’s and the Utility’s proposal for the Bankruptcy Court to address the legal issue of whether, under the doctrine of inverse condemnation,TCC RSA, PG&E Corporation and the Utility may befiled a motion in the District Court on March 20, 2020 requesting that the District Court estimate the aggregate liability of the Fire Victim Claims at $13.5 billion—the amount the parties agreed to in the TCC RSA. Certain parties, including the TCC, objected to the motion arguing, among things, that the District Court needs to clarify certain provisions of the TCC RSA. PG&E Corporation and the Utility filed a reply to the objection on April 10, 2020, and the District Court held strictly liablea status conference on April 16, 2020. The next status conference is set for wildfire claims asserting property damages even where it was not negligent.May 18, 2020. A hearing on the motion is set for May 21, 2020.

Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganizationPlan in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). PG&E Corporation and the Utility’s Chapter 11 plan of reorganization currently is under development and has not yet been filed with the Bankruptcy Court.  PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or groupgroups of public entities, as applicable:

•the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”);;


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•the Town of Paradise;Paradise;

•the County of Butte;Butte;

•the Paradise Recreation & Park District;District;

•the County of Yuba;Yuba; and

•the Calaveras County Water District.

For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.”

Each PSA provides that PG&E Corporation and the Utility’s Chapter 11 plan of reorganizationPlan will include, among other things, the following elements:

•following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization,Plan, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and

•subject to the Supporting Public Entities voting affirmatively to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization,Plan, following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization,Plan, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”).

The “Settlement Amount” set forth in each PSA is as follows:

•for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities),

•for the Town of Paradise, $270.0 million,

•for the County of Butte, $252.0 million,

•for the Paradise Recreation & Park District, $47.5 million,

•for the County of Yuba, $12.5 million, and

•for the Calaveras County Water District, $3.0 million.

Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support PG&E Corporation and the Utility’s Chapter 11 plan of reorganizationPlan with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganizationPlan in the Chapter 11 Cases.

Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including:

•if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and

•by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization. Plan.



Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if:

•PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018,

•the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and
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•any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA.

Potential LossesRestructuring Support Agreement with Holders of Subrogation Claims

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Aggregate Subrogation Recovery”) to be paid by PG&E Corporation and the Utility pursuant to the Plan in Connectionorder to settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

The Subrogation RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Plan in the Chapter 11 Cases.

On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approving the terms of the settlement contemplated under the Subrogation RSA. On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA.

The Subrogation RSA will automatically terminate if (i) the Plan is not confirmed by June 30, 2020 (or such later date as may be authorized by any amendment to AB 1054) or (ii) the Effective Date does not occur prior to December 31, 2020 (or six months following the deadline for confirmation of the Plan if such deadline is extended by any amendment to AB 1054).

The Subrogation RSA may be terminated by any Consenting Subrogation Creditor as to itself if the Aggregate Subrogation Recovery is modified. The Subrogation RSA may be terminated by the Consenting Subrogation Creditors holding at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors under certain circumstances, including, among others, if (i) they reasonably determine in good faith at any time prior to confirmation of the Plan that PG&E Corporation and the Utility are insolvent or otherwise unable to raise sufficient capital to pay the Aggregate Subrogation Recovery on the Effective Date, (ii) PG&E Corporation and the Utility breach the terms of the Subrogation RSA or otherwise fail to take certain actions specified in the Subrogation RSA, (iii) the Plan does not treat the individual plaintiffs’ wildfire-related claims consistent with the provisions of AB 1054, (iv) the Bankruptcy Court allows a plan proponent other than PG&E Corporation and the Utility to commence soliciting votes on a plan (other than the Plan) that incorporates the terms of the settlement contemplated by the Subrogation RSA and PG&E Corporation and the Utility have not already commenced soliciting votes on the Plan which incorporates such settlement, (v) the Bankruptcy Court confirms a plan other than the Plan or (vi) the Plan is modified to be inconsistent with such settlement. The Subrogation RSA may be terminated by PG&E Corporation and the Utility (a) in the event of certain breaches of the Subrogation RSA by Consenting Subrogation Creditors holding at least 5% of the Subrogation Claims held by Consenting Subrogation Creditors or (b) if the Bankruptcy Court confirms a plan other than the Plan or if the terms of the Plan related to the settlement contemplated by the Subrogation RSA become unenforceable or are enjoined.

Subject to certain limited exceptions, the valuation of the Subrogation Claims in an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) will survive any termination of the Subrogation RSA and will be binding on PG&E Corporation and the Utility in the Chapter 11 Cases.

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Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019, with the TCC, the Consenting Fire Claimant Professionals and the Shareholder Proponents (as amended, the “TCC RSA”). The TCC RSA provides for, among other things, an aggregate of $13.5 billion in value to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration is to be funded into a trust (the “Fire Victim Trust”) to be established pursuant to the Plan for the benefit of holders of the Fire Victim Claims and will consist of (a) $5.4 billion in cash contributed on the effective date of the Plan, (b) $1.35 billion in cash comprising (i) $650 million paid in cash on or before January 15, 2021 and (ii) $700 million paid in cash on or before January 15, 2022, subject to the terms of a tax benefit payment agreement to be entered into between the Fire Victim Trust and the reorganized Utility, and (c) $6.75 billion in common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation will not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the effective date of the Plan, assuming the Utility’s current allowed ROE. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also includes (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 and 2016 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted prior to the Petition Date.

Under the terms of the Plan, all Fire Victim Claims, including claims by uninsured and underinsured individual claimholders as well as government entities that are not Supporting Public Entities (including FEMA and OES/Cal Fire), would be settled and discharged in consideration of the payment of the Aggregate Fire Victim Consideration to the Fire Victim Trust. However, the TCC RSA is an agreement among PG&E Corporation and the Utility, the TCC, the Shareholder Proponents, and the Consenting Fire Claimant Professionals, which are attorneys representing individual claimholders. No individual claimholder is a party to the TCC RSA. Accordingly, there can be no assurance that such claimholders will support the Plan or the treatment of their Fire Victim Claims in the Chapter 11 Cases as provided in the Plan.

In addition, each party to the TCC RSA must, among other things, (a) use commercially reasonable efforts to support and cooperate with PG&E Corporation and the Utility to obtain confirmation of the Plan and any necessary regulatory or other approvals, and (b) oppose efforts and procedures to confirm the Ad Hoc Noteholder Plan. Each party to the TCC RSA also must not, among other things, (1) object to, delay, impede, or take any other action to interfere with acceptance, confirmation or implementation of the Plan or (2) propose, file or support any other plan of reorganization, restructuring, or sale of assets with respect to PG&E Corporation and the Utility. Each Consenting Fire Claimant Professional must use all reasonable efforts to advise and recommend to its existing and future clients (who hold Fire Victim Claims) to support and vote to accept the Plan and to opt-in to consensual releases under the Plan.

The TCC RSA will automatically terminate under certain circumstances, including, among others, if (a) a sufficient number of Fire Victim Claims votes to accept the Plan such that the class of Fire Victim Claims in the Plan votes to accept the Plan under 11 U.S.C. section 1126(c) as determined by the Bankruptcy Court are not made by the later of (i) the voting deadline for the Plan or (ii) June 30, 2020, (b) the disclosure statement for the Plan is not approved by the Bankruptcy Court by March 30, 2020 and a motion seeking approval of the settlement of the Estimation Proceeding for the Aggregate Fire Victim Consideration is not filed by March 30, 2020, (c) the Plan is not confirmed by the Bankruptcy Court by June 30, 2020, or (d) the effective date of the Plan does not occur prior to August 29, 2020 (which deadlines in (b) through (d) of this paragraph may be extended by consent of PG&E Corporation and the Utility, the TCC, the Shareholder Proponents and the Requisite Consenting Fire Claimant Professionals (as defined below)).

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The TCC RSA may be terminated by the TCC or the Requisite Consenting Fire Claimant Professionals (consisting of (a) the TCC, acting by vote of simple majority of its members, and (b) a group of thirteen law firms (subject to addition) that are Consenting Fire Claimant Professionals and whose initial members are specified in the TCC RSA, acting by vote of a simple majority of its members) if (a) PG&E Corporation and the Utility or the Shareholder Proponents breach any of their obligations, representations, warranties or covenants set forth in the TCC RSA, (b) PG&E Corporation and the Utility and the Shareholder Proponents fail to prosecute the Plan and seek entry of a confirmation order that contains or is otherwise consistent with the terms of the TCC RSA, or propose, pursue or support a Chapter 11 plan of reorganization or confirmation order inconsistent with the terms of the TCC RSA or the Plan, (c) the Plan is or is modified to be inconsistent with the terms of the TCC RSA, or (d) the TCC or the Requisite Consenting Fire Claimant Professionals determine on or before the date of the Bankruptcy Court hearing to approve the TCC RSA that Section 4.19(f)(ii) of the Plan (and any related provisions) has not been modified to their satisfaction. The TCC RSA may be terminated by PG&E Corporation and the Utility or the Shareholder Proponents if (1) either the TCC or Consenting Fire Claimant Professionals that represent in the aggregate more than 8,000 holders of Fire Victim Claims breach any of their obligations, representations, warranties or covenants set forth in the TCC RSA or (2) if the TCC takes any action inconsistent with its obligations under the TCC RSA or fails to take any action required under the TCC RSA.

PG&E Corporation’s and the Utility’s obligation relating to the Tubbs Preference Settlements will survive any termination of the TCC RSA and will be enforceable against PG&E Corporation and the Utility. In addition, the TCC RSA provides that, upon termination of the TCC RSA, (a) the Estimation Proceeding will immediately recommence and (b) all litigation regarding the Tubbs fire, including a determination of whether or not the Utility caused the Tubbs fire, will be determined by the District Court without any reference to any state court proceeding. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA.

Pursuant to further discussions with claimants relating to the Ghost Ship fire, certain provisions of the TCC RSA were superseded by the terms of the Plan, and accordingly the above description of the TCC RSA has been revised to reflect the fact that claims arising out of the Ghost Ship fire will be resolved separately from the TCC RSA.

2015 Butte Fire

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire 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.

Third-Party Claims

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its 2 vegetation management contractors in the Superior Court of California, County of Sacramento.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council previously had authorized the coordination of all cases in Sacramento County.  As of January 28, 2019, 95 known complaints were filed against the Utility and its 2 vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador.  The complaints involve approximately 3,900 individual plaintiffs representing approximately 2,000 households and their insurance companies.  These complaints were part of, or were in the process of being added to, the coordinated proceeding.  Plaintiffs sought to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also sought punitive damages.  The Utility believes a loss related to punitive damages is unlikely, but possible. Several plaintiffs dismissed the Utility’s 2 vegetation management contractors from their complaints. The Utility does not expect the number of claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applied to the Utility with respect to the 2015 Butte fire. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability.

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On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The Utility reached agreement with 2 plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. The court granted the Utility’s stipulated judgment motion on November 29, 2018 and the Utility filed its appeal on December 11, 2018. As a result of the filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

In addition to the coordinated plaintiffs, Cal Fire, the OES, the County of Calaveras, the Calaveras County Water District, and 4 smaller public entities (3 fire districts and the California Department of Veterans Affairs) brought suit or indicated that they intended to do so. The Utility settled the claims of the 3 fire protection districts and the Calaveras County Water District.

On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred, which proceeding is now stayed. Prior to the stay, the Utility and Cal Fire were also engaged in a mediation process.

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors. The Utility and the County of Calaveras settled the County’s claims in November 2018 for $25 million.

Further, in May 2017, the OES indicated that it intended to bring a claim against the Utility related to the Butte fire that it estimated to be approximately $190 million. The Utility has not received any information or documentation from the OES since its May 2017 statement, other than a proof of claim for $107 million filed with the Bankruptcy Court. In June 2017, the Utility entered into an agreement with the OES that extended its deadline to file a claim to December 2020. As described above, on April 21, 2020, the parties announced that settlement agreements have been reached with certain Federal agencies (including FEMA and the SBA) and certain State agencies (including Cal OES and Cal Fire) regarding their Fire Claims, including in connection with the 2015 Butte fire. PG&E Corporation and the Utility filed a motion seeking Bankruptcy Court approval of the agreements on April 26, 2020. A hearing before the Bankruptcy Court to consider approval of the agreements is currently scheduled for May 12, 2020.

PG&E Corporation’s and the Utility’s obligations with respect to claims related to the 2015 Butte fire that had not been resolved as of the Petition Date are expected to be determined through the Chapter 11 process (including the settlement agreements described in this Note 10).

As discussed under the headings “Plan Support Agreements with Public Entities” and “Restructuring Support Agreement with the TCC,” PG&E Corporation and the Utility have entered into agreements to potentially resolve certain government entity claimholders’ wildfire-related claims arising from the 2015 Butte fire as well as with the TCC and the Consenting Fire Claimant Professionals to potentially resolve all wildfire-related claims arising from the 2015 Butte fire held by individual claimholders.

2018 Camp Fire, 2017 Northern California Wildfires and 2015 Butte Fire Accounting Charge

There were 0 charges for the three months ended March 31, 2020. At March 31, 2020 and December 31, 2019, the Utility’s Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims of $25.5 billion. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire is comprised of (i) $11 billion for subrogated insurance claimholders pursuant to the Subrogation RSA, plus (ii) $47.5 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the Subrogation RSA, plus (iii) $1 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (iv) $13.5 billion for all other wildfire-related claims, including individual wildfire claimholders (including those with uninsured and underinsured property losses) and clean-up and fire suppression costs, pursuant to the TCC RSA. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire corresponds to PG&E Corporation’s and the Utility’s best estimate of probable losses and is subject to change based on additional information, including the other factors discussed below.

In the case of the Tubbs fire and the 37 fire, PG&E Corporation and the Utility continue to believe that if the claims related to these fires were litigated on the merits, it would not be probable that they would incur a loss for such claims. As a result of the entry into the PSAs, the Subrogation RSA and the TCC RSA, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with such fires. With respect to the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point, Nuns, Norrbom, Adobe, Partrick, Pythian, Youngs and Pressley fires), PG&E Corporation and the Utility previously determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits.
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The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp, the 2017 Northern California wildfires and the 2015 Butte fire represents PG&E Corporation’s and the Utility’s best estimate of probable losses and is subject to change based on additional information. Notwithstanding the entry into the PSAs, the Subrogation RSA and the TCC RSA, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including whether any termination events are triggered under these agreements, whether the classification and treatment of claims in the Plan is successfully challenged by claimholders who are not party to a settlement agreement, whether the requisite number of impaired claimholders vote to approve the Plan in the Chapter 11 Cases, whether any fines or penalties are treated as Fire Claims as provided in the Plan and whether a plan of reorganization incorporating the terms of those settlements is confirmed. (See “Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires

On May 8, 2019,Wildfires” above for a summary of material termination rights under the California Department of Insurance issued a news release announcing an update on property losses in connection withPSAs, the 2018 wildfires in Southern California (which are not in the Utility’s service territory)Subrogation RSA and the 2018 Camp fire, indicating that “total claims over $12 billion asTCC RSA.) Many of April [2019]” in insured losses have been reported fromthese factors are beyond the November 2018 fires,control of which approximately $8.6 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires.

The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.6 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility. For example, notwithstanding the TCC RSA, the TCC filed a motion in the Bankruptcy Court on April 6, 2020 seeking approval of a letter from the TCC to individual holders of wildfire-related claims requesting that they withhold their votes in favor of the Plan until the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularlyprovides supplemental disclosure with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.6 billion of insurance claims made asPlan and certain issues relating to the value of the above dates does not account for uninsuredstock to be distributed to the Fire Victim Trust (which the Bankruptcy Court denied). The Bankruptcy Court issued an order denying the TCC’s motion on April 7, 2020. If one or underinsured property losses, interest, attorneys’ fees, fire suppressionmore of these settlement agreements is terminated or if one or more classes of impaired claimholders fail to approve the Plan, PG&E Corporation’s and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet (“future claims”), each of which could be significant.

Potential liabilitiesthe Utility’s aggregate liability related to the 2018 Camp fire and 2017 Northern California wildfires depend(and in certain cases, other pre-petition fires) could substantially exceed $25.5 billion. In addition, if these agreements were terminated, regardless of the ultimate determination of PG&E Corporation’s and the Utility’s liability, such termination would be expected to result in additional delay and expense in the Chapter 11 Cases.

Absent settlement agreements or in the event of a failed solicitation of votes for the Plan, the process for estimating losses associated with claims requires management to exercise significant judgment based on variousa number of assumptions and subjective factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs or other damages the Utility may be responsible for if found negligent or as estimated in the Chapter 11 Cases.

The $25.5 billion liability does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below. While the Plan provides that the $25.5 billion liability includes the amount of any penalties or fines that may be imposed by governmental entities, and the amount of any penalties, fines, or restitution ordersfines that might result from any criminal charges brought.brought, it is possible such penalties or fines may ultimately be determined to be separate from and incremental to the $25.5 billion liability. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire may change, which could result in material increases to the loss accrued.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported 0 fatalities and 4 first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, 1 commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

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The Utility has submitted electric incident reports to the CPUC indicating that:

•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;

•various generating facilities on the Geysers #9 Lakeville 230kV line detected the disturbance and separated at approximately the same time;

•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;

•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and

•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.

The cause of the 2019 Kincade fire is under investigation by Cal Fire and the CPUC, and PG&E Corporation and the Utility are cooperating with those investigations. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties. There are a number of unknown facts surrounding the cause of the 2019 Kincade fire, and legal considerations that may impactaccordingly, the amountcause of any potential liability. Among other things, there is uncertainty at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims and other factors may have2019 Kincade fire remains uncertain.

Based on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporationfacts and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion, which amount does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. This estimate is based on a wide variety of data and other informationcircumstances available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount.



If PG&E Corporation and the Utility were to be found liable for any punitive damages, and such damages were allowed by the Bankruptcy Court, or if PG&E Corporation and the Utility were subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. Regulatory proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses, and record a charge that is the amount within the range that is a better estimate than any other amount or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses 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.

2018 Camp Fire

In light of the current state of the law and the information currently available to the Utility, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire. PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry intoinformation contained in the PSAselectric incident report and the statusother information gathered as part of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims,investigation, PG&E Corporation and the Utility recorded an additional charge for claimsbelieve it is reasonably possible that they will incur a loss in connection with the 2018 Camp2019 Kincade fire. If PG&E Corporation and the Utility were to incur a loss in respect of the 2019 Kincade fire, inPG&E Corporation and the Utility estimate that the amount of $1.9 billion for the three months ended June 30, 2019.

The aggregate liability of $12.4 billion for claims in connection with the 2018 Camp firesuch loss could exceed $600 million (before available insurance). This amount corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probableestimable range of reasonably possible losses and is subject to change based on additional information. The $600 million estimate of the lower end of the range of reasonably possible losses does not include, among other things, (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal, state, county and local government entities or agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire willcould be greater than the amount accrued,$600 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.potential damages.

The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited tothe factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2018 Camp2019 Kincade fire may change, which could result in material increases to the loss accrued.change.



The $12.4 billion liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount in respect of FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below.

2017 Northern California Wildfires

In light of the current state of the law and the information currently available to the Utility,future, it is possible that facts could emerge that lead PG&E Corporation and the Utility have determinedto believe that ita loss is probable, they will incurresulting in the accrual of a loss for claims in connection with all 21 of the 2017 Northern California wildfires identified above, the reasons for which are discussed in more detail in this section below. PG&E Corporation and the Utility recorded a charge inliability at that time, the amount of $2.5 billion duringwhich could be significant and may exceed the quarter ended June 30, 2018 and a charge in the amountforegoing estimate of $1.0 billion during the quarter ended December 31, 2018, for a total charge in the amount of $3.5 billion for the year ended December 31, 2018. Based on additional facts and circumstances available to the Utility as of the date of this filing, including additional information from Cal Fire, the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2017 Northern California wildfires in the amount of $2.0 billion for the three months ended June 30, 2019.

The aggregate liability of $5.5 billion for claims in connection with the 2017 Northern California wildfires corresponds to the lower end of the range of reasonably possible losses. For the reasons discussed above, the 2019 Kincade fire could have a material impact on PG&E Corporation’s and the Utility’s reasonably estimated probable lossesfinancial condition, results of operations, liquidity, and is subject to change basedcash flows, as well as on additional information.

In the casebankruptcy timing and process and the ability of the Tubbs and 37 fires, PG&E Corporation andUtility to participate in the Utility continue to believe that if the claims related to these fires were litigated on the merits, it would not be probable that they would incur a loss for such claims. However, as a result of PG&E Corporation’s and the Utility’s most recent settlement offer to holders of claims related to the Tubbs and 37 fires as of the date of this filing, Wildfire Fund.

PG&E Corporation and the Utility have determined that itreceived and are responding to data requests from the CPUC’s SED relating to the Kincade fire. Various other entities, including law enforcement agencies, may also be investigating the fire. It is probable theyuncertain when the investigations will incur a loss for claims in connection with such fires. With respect to 17 of the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires)), PG&E Corporation and the Utility previously determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits. With respect to 2 of the other 19 of the 2017 Northern California wildfires (the Youngs and Pressley fires), PG&E Corporation and the Utility have determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits based on information that became available to PG&E Corporation and the Utility after the filing of their last Quarterly Report on Form 10-Q.be complete.
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Loss Recoveries

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2017 Northern California wildfires may change, which could result in material increases to the loss accrued.

The $5.5 billion liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount in respect of FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below.



Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

The aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $8.5 billion for subrogated insurance claimholders, (ii) $7.5 billion for individual claimholders (including those with uninsured and underinsured property losses, among other claims), (iii) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs and (iv) $900 million for clean-up and fire suppression costs. The aggregate liabilities of $8.5 billion for subrogated insurance claimholders and $7.5 billion for individual claimholders are based on PG&E Corporation’s and the Utility’s estimates of probable loss developed from data and other information available to PG&E Corporation and the Utility and PG&E Corporation’s and the Utility’s most recent settlement offers to representatives of such claimholders as of the date of this filing. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders. With respect to the $1.0 billion liability for claims held by the Supporting Public Entities, while PG&E Corporation and the Utility previously disclosed the existence of claims asserted by such entities, PG&E Corporation and the Utility had not previously taken a charge related to these claims as the amount of the liability could not be reasonably estimated. As described above, the aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information. (See “Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires” above.)

As of the date of this filing, PG&E Corporation and the Utility believe that the settlement discussions with representatives of subrogated insurance claimholders are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in the negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and such claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the subrogated insurance claims may increase by a material amount, which would result in an additional accrual above the $8.5 billion reflected in this filing. Any such increase could be substantial and could be taken in the third quarter of 2019. In their motion submitted to the Bankruptcy Court on July 23, 2019, the Ad Hoc Subrogation Group stated that holders of subrogated insurance claims hold in excess of $20 billion of wildfire-related claims against PG&E Corporation and the Utility. In the “Restructuring Term Sheet” attached to such motion, the Ad Hoc Subrogation Group proposed terms for a plan of reorganization that would settle all such subrogated insurance claims for consideration valued at $15.8 billion. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders.

Loss Recoveries

PG&E Corporation and the Utility had insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

PG&E CorporationThe Utility has liability insurance from various insurers that provides coverage for third-party liability attributable to the 2015 Butte fire in an aggregate amount of $922 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility had $842can reasonably estimate the amount or its range. Through March 31, 2020, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 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 coverage for liabilities,recoveries. In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including wildfire events,policies where the Utility is listed as an additional insured, are uncertain.

The balance for the period from August 1, 2017 through Julyinsurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets and was $50 million at both March 31, 2018, subject to an initial self-insured retention of $10 million per occurrence2020 and further retentions of approximately $40 million per occurrence. During the third quarter ofDecember 31, 2019, respectively.

In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. In 2020, PG&E Corporation and the Utility has liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation and the Utility continue to pursue additional insurance coverage. Various coverage limitations applicable to different insurance layers could result in uninsured costs in the future depending on the amount and type of damages resulting from covered events. PG&E Corporation and the Utility expect to receive the insurance recoveries associated with the 2018 Camp fire and 2017 Northern California wildfires shortly after emergence from Chapter 11.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through June 30, 2019,March 31, 2020, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842$843 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.losses.



If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and the 2017 Northern California wildfires will substantially exceed their available insurance.

The following table presents changes in the insurance receivable for the six months ended June 30, 2019. The balancebalances for insurance receivable isreceivables with respect to the 2018 Camp fire and the 2017 Northern California wildfiresare included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:Sheets. The balance for insurance receivable for the 2018 Camp fire was $1.38 billion as of March 31, 2020 and December 31, 2019. The balance for insurance receivable for the 2017 Northern California wildfires was $807 million as of March 31, 2020 and December 31, 2019, respectively.
(in millions)Insurance Receivable
2018 Camp fire 
Balance at December 31, 2018$1,380
Accrued insurance recoveries—
Reimbursements—
Balance at June 30, 2019$1,380
  
2017 Northern California wildfires 
Balance at December 31, 2018$829
Accrued insurance recoveries—
Reimbursements—
Balance at June 30, 2019$829

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Regulatory Recovery

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain,uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a customer harm threshold,CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service (the “Customer Harm Threshold”).service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold.CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm ThresholdCHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.

On March 29, 2019, the Assigned Commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding.



On July 8, 2019, the CPUC issued a decision in the Customer Harm ThresholdCHT proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility from access to relief under the Customer Harm Threshold during the pendency of the Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm ThresholdCHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential maximum regulatory adjustment of either 20% of the Customer Harm ThresholdCHT or 5% of the total disallowed wildfire liabilities, whichever is greater;liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the Customer Harm Threshold.CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of temporary Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date.

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

Wildfire-Related Derivative Litigation

TwoNaN purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire.

On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of bankruptcy proceedings, as discussed below. A case management conference is currently set for July 6, 2020.
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On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. PlaintiffThe plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. A case management conference is currently set for July 6, 2020.



On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The court has scheduledOn February 5, 2019, the plaintiff in Bowlinger filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. A case management conference is currently set for December 13, 2019.July 10, 2020.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 1, 2020.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al., was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. A case management conference is currently set for July 9, 2020.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Sectionsection 362(a) of the Bankruptcy Code. On February 5, 2019,PG&E Corporation’s and the plaintiff in Bowlinger v. Chew, et al. filed a responseUtility’s rights with respect to the notice asserting that the automatic stay did not apply to his claims.derivative claims asserted against former officers and directors of PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court aswere assigned to the Fire Victim Trust under the TCC RSA.
Bowlinger action, which was granted.

Wildfire-Related Securities Class Action Litigation

Wildfire-Related Class Action

In June 2018, two2 purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively.  The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend theirits complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Sectionsection 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

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On February 22, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four4 public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the federal Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously-filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. The action remains stayed as to PG&E Corporation and the Utility. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court.

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the plaintiffs filed a notice of appeal regarding the denial of their motion.

De-energization Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40,361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint adds PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against two officers of PG&E Corporation previously named in the action. As of April 30, 2020, PG&E Corporation had not yet been served with this complaint.

Given the early stages of the litigations, including but not limited to the fact that defendants’ motions to dismiss have not yet been decided and no discovery has occurred in the consolidated class action litigation or, the de-energization class action, PG&E Corporation and the Utility are currently seeking an order fromunable to reasonably estimate the Bankruptcy Courtamount of any potential loss.

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Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend the stay to the officer, director,claims asserted against the directors and underwriter defendants.officers in the securities class action. PG&E Corporation and the Utility maintain directors and officers insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases.



District Attorneys’ Offices’ Investigations

DuringFollowing the second quarter of 2018 Cal Fire issued news releases stating that it referred the investigations related to the McCourtney, Lobo, Honey, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” On March 12, 2019, the Sonoma, Napa, Humboldt and Lake County District Attorneys announced that they would not prosecute PG&E Corporation or the Utility for the fires in those counties, which include the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires.

PG&E Corporation and the Utility were the subject of criminal investigations or other actions by the Nevada County District Attorney’s Office to whom Cal Fire had referred its investigations into the McCourtney and Lobo fires. On July 23, 2019, the Nevada County District Attorney informed PG&E Corporation and the Utility of his decision not to pursue criminal charges in connection with the McCourtney and Lobo fires.

The HoneyCamp fire, was referred to the Butte County District Attorney’s Office, and in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates.

On October 9, 2018, the Office of the District Attorney of Yuba County announced its decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The District Attorney’s Office also indicated that it reserved the right “to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.”

In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility have beenwere informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury hashad been empaneled in Butte County.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the Utility was served with subpoenas in“Butte DA,” respectively) to resolve the grand jury investigation. Thecriminal prosecution of the Utility has produced documents and continues to produce documents and respond to other requests for information in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility has agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4). Upon approval and acceptance of the Plea Agreement by the Butte County Superior Court and the Bankruptcy Court, the People have agreed not to prosecute any other criminal investigationcharges related to or arising out of the 2018 Camp fire including, but not limited to, documents related toagainst the operation and maintenanceUtility, PG&E Corporation or any of equipment owned or operated by the Utility. The Utility has also cooperated with the Butte County District Attorney’s Office and the California Attorney General’s Office in the collection of physical evidence from equipment owned or operated by the Utility.their subsidiaries, including PG&E Corporation and the Utility are unableas reorganized pursuant to predict the outcomeChapter 11 Cases.

Pursuant to the Plea Agreement, the Utility will be sentenced to pay the maximum total fine and penalty of approximately $3.5 million. This $3.5 million fine and penalty will not be paid from the amounts to be distributed by the Utility to the Fire Victim Trust. The Plea Agreement provides that no other or additional sentence will be imposed on the Utility in the criminal investigation intoaction in connection with the 2018 Camp fire. The Utility could be subjecthas also agreed to material fines, penalties, or restitution if it is determined thatpay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.

Pursuant to the Plea Agreement, the Utility failedmay withdraw the plea if, among other things, (a) the Plea Agreement is not approved by the Butte County Superior Court, or (b) the Agreement is not approved by the Bankruptcy Court or the Plan is not confirmed by the Bankruptcy Court on or before June 30, 2020 or does not become effective in accordance with the terms thereof. If the plea is withdrawn by the Utility, the indictment referenced in the Agreement shall remain.

Simultaneous with entry into the Plea Agreement, the Utility has committed to complyspend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte DA consulting, sharing information with applicable laws and regulations, as well as non-monetary remedies such as oversight requirements. The criminal investigationreceiving information from the monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022. This consent is not subject to the automatic stay imposed as a resultapproval of the commencement offederal court overseeing the Chapter 11 Cases.Utility’s probation and the monitor.

On March 23, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into the Plea Agreement. On April 16, 2020, the Bankruptcy Court approved PG&E Corporation’s and the Utility’s Plea Agreement.

Additional investigations and other actions may arise out of the other 2017 Northern California wildfires, and the 2018 Camp fire, and the 2019 Kincade fire. The timing and outcome for resolution of the remaining referrals by Cal Fire relating to the appropriate2019 Kincade fire to the applicable county District Attorneys’ offices are uncertain.

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SEC Investigation

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office iswas conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.



Clean-up and Repair Costs

The Utility incurred costs of $655$786 million for clean-up and repair of the Utility’s facilities (including $236$327 million in capital expenditures) through June 30, 2019,March 31, 2020, in connection with the 2018 Camp fire. The Utility also incurred costs of $334$365 million for clean-up and repair of the Utility’s facilities (including $161$187 million in capital expenditures) through June 30, 2019,March 31, 2020, in connection with the 2017 Northern California wildfires. In addition, the Utility incurred costs of $60 million for clean-up and repair of the Utility’s facilities (including $17 million in capital expenditures) through March 31, 2020, in connection with the 2019 Kincade fire. The Utility is authorized to track and seek recovery of clean-up and repair costs through CEMA. (CEMA requests are subject to CPUC approval.) The Utility capitalizes and records as regulatory assets costs that are probable of recovery. At June 30, 2019,March 31, 2020, the CEMA regulatory asset balances related to the 2019 Kincade fire, 2018 Camp fire, and 2017 Northern California wildfires were zero$34 million, 0, and $88$67 million, respectively, and are included in long-term regulatory assets on the Condensed Consolidated Balance Sheets. Additionally, other than the amounts subject to the settlement agreement, as modified by the Decision Different issued on April 20, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the capital expenditures for clean-up and repair are included in property, plant and equipment at June 30, 2019.March 31, 2020.

Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Wildfire Assistance Fund

On May 24, 2019, the Bankruptcy Court entered an order authorizing PG&E Corporation and the Utility to establish and fund a program (the “Wildfire Assistance Fund”) to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of substitute or temporary housing (“Alternative Living Expenses”) and other urgent needs. The Wildfire Assistance Fund is intended to aid certain wildfire claimants who are either uninsured or still in need of assistance for Alternative Living Expenses or have other urgent needs. The Wildfire Assistance Fund will consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. The administrator will be responsible for developing the specific eligibility requirements and application procedures for the distribution of the Wildfire Assistance Fund to eligible claimants. Up to $5 million of the Wildfire Assistance Fund may be used to pay the costs of administering the fund. The establishment of the Wildfire Assistance Fund is not an acknowledgment or admission by PG&E Corporation or the Utility of liability with respect to the 2018 Camp fire or 2017 Northern California wildfires.

The Utility fully funded $105 million into the Wildfire Assistance Fund on August 2, 2019. As of March 31, 2020, the administrator issued claimant payments totaling $74 million under the Wildfire Assistance Fund.

2015 Butte FireWildfire Fund under AB 1054

In September 2015,On July 12, 2019, the California Governor signed into law AB 1054, a wildfire (the “2015 Butte fire”) ignitedbill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and spreadconditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in Amadorthe aggregate in any calendar year and Calaveras Counties(ii) the amount of insurance coverage required to be in Northern California. On April 28, 2016, Cal Fire released its reportplace for the electric utility company pursuant to Section 3293 of the investigationPublic Utilities Code, added by AB 1054.

Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the originelectric utility company’s transmission and causedistribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.4 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the 2015 Butte fire. Accordingfund.

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The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to Cal Fire’s report,be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the 2015 ButteDepartment of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire burned 70,868 acres, resultedthreat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concludedthe Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.

AB 1054 also provides that the 2015 Buttefirst $5.0 billion expended in the aggregate by California’s three investor-owned electric utility companies on fire was caused whenrisk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the investor-owned electric utility companies in accordance with their Wildfire Fund allocation metrics (described above). AB 1054 contemplates that such capital expenditures may be securitized through a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure bycustomer charge.

On July 23, 2019, the Utility and/ornotified the CPUC of its vegetation management contractors, ACRT Inc. and Trees, Inc.,intent to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.



Third-Party Claims

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractorsparticipate in the Superior Court of California, County of Sacramento.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council previously had authorized the coordination of all cases in Sacramento County.  As of January 28,Wildfire Fund. On August 7, 2019, 95 known complaints were 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.  The complaints involve approximately 3,900 individual plaintiffs representing approximately 2,000 households and their insurance companies.  These complaints were part of, or were in the process of being added to, the coordinated proceeding.  Plaintiffs sought to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also sought punitive damages.  Several plaintiffs dismissed the Utility’s two vegetation management contractors from their complaints. The Utility does not expect the number of claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages.  The court denied the Utility’s motion and the Utility filedsubmitted a writmotion with the Bankruptcy Court for the entry of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utilityan order authorizing PG&E Corporation and to deny plaintiffs’ claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal’s decision. Both requests were denied. Neither the trial nor appellate courts originally addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. However, the trial court, in November 2018, denied a motion filed by the Utility that would have confirmed that punitive damages under Public Utilities Code Section 2106 are unavailable. The Utility believes a loss related to punitive damages is unlikely, but possible.

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applied to the Utility with respect to the 2015 Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling was binding only between the Utility and the plaintiffsparticipate in the coordination proceeding at the time of the ruling, others couldWildfire Fund and to make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance,any initial and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it was bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the court stated that the Utility’s constitutional arguments should be madeannual contributions to the appellate courts and suggested that, to the extent the Utility raised the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the court’s decision.Wildfire Fund upon emergence from Chapter 11. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. The court granted the Utility’s stipulated judgment motion on November 29, 2018 and the Utility filed its appeal on December 11, 2018. As a result of the filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

In addition to the coordinated plaintiffs, Cal Fire, the OES, the County of Calaveras, the Calaveras County Water District, and four smaller public entities (three fire districts and the California Department of Veterans Affairs) brought suit or indicated that they intended to do so. The Calaveras County Water District and the four smaller public entities filed their complaints in August 2018 and September 2018. They were added to the coordinated proceedings. The Utility settled the claims of the three fire protection districts and the Calaveras County Water District.



On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims.  On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility’s vegetation contractors. Cal Fire had requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of Appeal’s decision in Dep’t of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion was set for January 31, 2019, but the hearing and Cal Fire’s case against the Utility are now stayed. Prior to the stay, the Utility and Cal Fire were also engaged in a mediation process.

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also sought punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras settled the County’s claims in November 2018 for $25.4 million.

Further, in May 2017, the OES indicated that it intended to bring a claim against the Utility that it estimated to be approximately $190 million.  This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the 2015 Butte fire. The Utility has not received any information or documentation from the OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that extended its deadline to file a claim to December 2020.

PG&E Corporation’s and the Utility’s obligations with respect to such outstanding claims are expected to be determined through the Chapter 11 process. As described in Note 2, on July 1,26, 2019, the Bankruptcy Court entered an order approvinggranting such authorizations. In order to participate in the Bar DateWildfire Fund, the Utility must also meet the eligibility and other requirements set forth in AB 1054, and pay its share of October 21, 2019, at 5:00 p.m. (Pacific Time)the initial contribution to the Wildfire Fund upon emergence from Chapter 11. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for filingeligible claims against PG&E Corporationarising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases.

The Utility relatingexpects to record its required contributions as an asset and amortize the asset over the estimated life of the Wildfire Fund. The Wildfire Fund asset will be further adjusted for impairment as the assets are used to pay eligible claims, which will result in decreases to the period prior toassets available for coverage of future events. AB 1054 does not establish a definite term of the Petition Date, including claims in connection with the 2015 Butte fire. The Bar DateWildfire Fund; therefore, this accounting treatment is subject to certain exceptions, including for claims arising under section 503(b)(9)significant judgments and estimates. The assumptions create a high degree of uncertainty related to the estimated useful life of the Bankruptcy Code,Wildfire Fund. The most significant assumption is the bar date fornumber and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. The Utility intends to utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies.

Other assumptions include the estimated cost of wildfires caused by other electric utilities, the amount at which occurred on April 22, 2019. It is expected that numerous wildfire-relatedwildfire claims will be filedsettled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the level of future insurance coverage held by the electric utilities, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. There could also be a significant delay between the occurrence of a wildfire and the timing of which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another electric utility. As of March 31, 2020, the Utility has not reflected the required contributions in its Consolidated Financial Statements as it has not yet satisfied all of the Wildfire Fund eligibility criteria pursuant to AB 1054.

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In order to participate in the Wildfire Fund, within 60 days of the effective date of AB 1054, the Utility must obtain the Bankruptcy Court’s approval of the Utility’s election to pay the initial and annual Wildfire Fund contributions upon emergence from Chapter 11, which approval was granted by the Bankruptcy Court on August 26, 2019. The Utility would then be required to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11, and meet certain eligibility requirements listed below, in order to participate in the Wildfire Fund. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases. There are several additional eligibility requirements for the Utility, including that by June 30, 2020, the following conditions are satisfied:

•the Utility’s Chapter 11 Case has been resolved pursuant to a plan of reorganization or similar document not subject to a stay;

•the Bankruptcy Court has determined that the resolution of the Utility’s Chapter 11 Case provides funding or otherwise provides for the satisfaction of any pre-petition wildfire claims asserted against PG&E Corporation and the Utility in connection with the 2015 Butte fireChapter 11 Case, in the amounts agreed upon in any settlement agreements, authorized by the Bankruptcy Court through an estimation process or otherwise allowed by the Bar Date. On July 18, 2019, PG&E Corporation and Bankruptcy Court;

•the Utility filed a motion for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s andCPUC has approved the Utility’s aggregate liability for certain claims arising outplan of reorganization and other documents resolving its Chapter 11 Case, including the Utility’s resulting governance structure as being acceptable in light of the 2015 Butte fire, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” above.

Estimated Losses from Third-Party Claims

In connection with the 2015 Butte fire, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

In addition, the Utility may be liable for fire suppression costs, personal injury damages,Utility’s safety history, criminal probation, recent financial condition and other damages iffactors deemed relevant by the Utility is found to have been negligent.  While CPUC;

•the Utility believes it was not negligent, there can be no assurance that a court would agree with the Utility.

The Utility’s assessment of the estimated loss related to the 2015 Butte fire 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 certain other damages.

The UtilityCPUC has determined that it is probable that it will incur a loss of $1.1 billion in connection with the 2015 Butte fire. While this amount includes the Utility’s assumptions about fire suppression costs (includingplan of reorganization and other documents resolving its assessment of the Cal Fire loss), it does not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

The process for estimating costs associatedChapter 11 Case are (i) consistent with claims relatingCalifornia’s climate goals as required pursuant to the 2015 Butte fire requires management to exercise significant judgment basedCalifornia Renewables Portfolio Standard Program and related procurement requirements and (ii) neutral, on a number of assumptions and subjective factors.  As more information becomes known, management estimates and assumptions regarding the financial impact of the 2015 Butte fire may result in material increasesaverage, to the loss accrued.



Utility’s ratepayers; and
PG&E Corporation’s and
•the CPUC has determined that the Utility’s Condensed Consolidated Balance Sheets included liabilities for 2015 Butte fire third-party claimsplan of $226 millionreorganization and $212 million asother documents resolving its Chapter 11 Case recognize the contributions of December 31, 2018ratepayers, if any, and June 30, 2019, respectively, reflecting paymentscompensate them accordingly through mechanisms approved by the CPUC, which may include sharing of $14 million in January 2019, prior to the Petition Date. As of June 30, 2019, the Utility has paid $888 million of the $904 million in settlements to date in connection with the 2015 Butte fire.value appreciation.

If the Utility records losses in connection with claims relating to the 2015 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, liquidity, and cash flows could be materially affected in the reporting periods during which additional charges are recorded.

Loss Recoveries

The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the 2015 Butte fire in an aggregate amount of $922 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 June 30, 2019, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 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 has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

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 and was $85 million and $50 million as of December 31, 2018 and June 30, 2019, respectively, reflecting reimbursements of $35 million during the six months ended June 30, 2019.

NOTE 11: OTHER 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 liabilityloss has been incurred and the amount of the liabilityloss can be reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate orprovision based on the lower end of the range, if thereunless an amount within the range is noa better estimate.estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of lossesloss 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 excludes anticipated legalthese costs which are expensed 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’s and the Utility’s financial condition, results of operations, liquidity and cash flows may be materially affected by the outcome of the following matters.

Enforcement and Litigation Matters

U.S. District Court Matters and Probation

On August 9, 2016,In connection with the jury in the federal criminal trial against the Utility inUtility’s probation proceeding, the United States District Court for the Northern District of California in San Francisco, found the Utility guilty on 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 imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, withhas the ability to apply for early termination after three years, a fine of $3 million toimpose additional probation conditions on the Utility. Additional conditions, if implemented, could be paid to the federal government, certain advertising requirements,wide-ranging and community service.

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 has retained the Monitor atwould impact the Utility’s expense. The goaloperations, number of the Monitor is to help ensure that the Utility takes reasonableemployees, costs and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programsfinancial performance. Depending on a Utility-wide basis.



On November 27, 2018, the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including whatthese additional requirements, ofcosts in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenancefinancial condition, results of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurateoperations, liquidity, and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018.cash flows.
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On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the 2017 Atlas fire.  The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order.  On January 4, 2019, the court issued another order requiring that the Utility provide, “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition.  The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire.  In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

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.”

The Utility was ordered to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed.  The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019.  On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Safety Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to:

“fully comply with all applicable laws concerning vegetation management and clearance requirements;”

“fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;”

submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;”



“maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and

“ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forgo issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.”

The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.”

Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond five years in light of the violation that has been adjudicated and whether the Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue.

The court held a sentencing hearing on the probation violation related to reporting requirements in connection with the 2017 Honey fire on May 7, 2019. After that hearing, the court imposed two additional conditions of probation by order dated May 14, 2019: (1) requiring that PG&E’s Board of Directors, Chief Executive Officer, senior executives, the Monitor and U.S. Probation Officer visit the towns of Paradise and San Bruno “to gain a firsthand understanding of the harm inflicted on those communities;” and (2) requiring that a committee of PG&E’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety Plan and the additional terms of probation regarding wildfire safety, reporting in writing to the full Board at least quarterly. The court also stated that it was not going to rule at this time on whether the court has authority to extend probation and would leave that question “in abeyance.” The court did not discuss whether the Monitor reports should be made public. Members of PG&E Corporation’s Board of Directors and senior management attended site visits to the Town of Paradise on June 7, 2019 and the City of San Bruno on July 16, 2019, which were coordinated by the U.S. Probation Officer overseeing the Utility’s probation. In addition, the Compliance and Public Policy Committee, a committee of PG&E Corporation’s Board of Directors, will be responsible for tracking the Utility’s progress against the Utility’s wildfire mitigation plan, as approved by the CPUC, and compliance with the terms of the Utility’s probation regarding wildfire safety.
On July 10, 2019, the court ordered the Utility to respond to a Wall Street Journal article titled “PG&E Knew for Years Its Lines Could Spark Wildfires, and Didn’t Fix Them” on a paragraph-by-paragraph basis, stating the extent to which each paragraph in the article is accurate.  The court also ordered the Utility to disclose all political contributions made by the Utility since January 1, 2017, and provide additional explanations regarding those contributions and dividends distributed prior to filing the Chapter 11 Cases. The Utility filed its response with the court on July 31, 2019. In the response, the Utility disagreed with the Wall Street Journal article’s suggestion that the Utility knew of the specific maintenance conditions that caused the 2018 Camp fire and nonetheless deferred work that would have addressed those conditions.

CPUC and FERC Matters

Order Instituting an Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire

On June 27, 2019, the CPUC issued anthe Wildfires OII (the “2017 Northern California Wildfires OII”) to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.



The 2017 Northern California Wildfires OII disclosesAs previously disclosed, on December 17, 2019, the findings of a June 13, 2019 report byUtility, the SED which, among other things, alleges thatof the Utility committed 27 violationsCPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with 12this proceeding and jointly moved for its approval.

Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of the 2017 Northern California wildfires (specifically, the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphurwildfire-related expenses and Youngs fires). As describedcapital expenditures in future applications in the OII,amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the 27 allegedsettlement agreement. The settlement agreement stipulates that no violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizinghave been identified in the Tubbs fire. As a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identified byresult of this finding, the SED in connectionsettlement agreement does not prevent the Utility from seeking recovery of costs associated with the Cherokee, La Porte and Tubbs fires.fire through rates. The 37 fire was determined by the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential. On a status conference call before the assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal charges in connection with the Lobo and McCourtney fires, the SED may add alleged violations related to those fires and the 2018 Camp fire to the OII.

The 2017 Northern California Wildfires OII requires the Utility to (i) show cause by July 29, 2019 why it should not be sanctioned for the 27 violations alleged in the SED report and (ii) submit a report by August 5, 2019, responding to information requests relating to “matters of concern that […] warrant further investigation and possible charges for violations of law.” These latter matters include the following: (i) the Utility’s vegetation management procedures and practices, (ii) the Utility’s procedures and practices regarding use of “recloser” devices in fire risk areas and during fire season, (iii) the Utility’s lack of procedures or policies for proactive de-energization of power lines during times of extreme fire danger, and (iv) the Utility’s record-keeping and other practices. The Utility is also required to take certain corrective actions and provide information regarding the qualifications of vegetation management personnel within 30 days of the issuance of the 2017 Northern California Wildfires OII. The Utility must also file an application to develop an open source, publicly available asset management system/database and mobile app, the costs of development and continued operation of which would be at shareholder expense.

The OII also indicates that the assigned commissioner shall set a prehearing conference for 45 to 60 days after the initiation of the proceeding or as soon as practicable after the CPUC makes the assignment. The assigned commissioner will also issue a scoping memo setting forth the scope of the proceeding and establishing a procedural schedule.

As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violationsamounts set forth in the OII. The Utility also filed a Corrective Actions Reporttable below include actual recorded costs and an Application to Develop a Mobile Applicationforecasted cost estimates for expenses and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019,capital expenditures which the Utility submitted a reporthas incurred or will incur to respondcomply with its legal obligations to the information requests containedprovide safe and reliable service.

(in millions)
Description(1)
ExpenseCapitalTotal
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)(2)
$236  $—  $236  
Transmission Safety Inspections and Repairs Expense (TO)(3)
433  —  433  
Vegetation Management Support Costs (FHPMA)36  —  36  
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)82  66  148  
2018 Camp Fire CEMA Expense (CEMA)435  —  435  
2018 Camp Fire CEMA Capital for Restoration (CEMA)—  253  253  
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)(4)
—  84  84  
Total$1,222  $403  $1,625  
(1) Unless indicated otherwise, all amounts included in the OII, as explained above.table reflect actual recorded costs for 2019.

(2) Includes $29 million forecasted for 2020.
Based on(3) Transmission amounts are under the information currently available, FERC’s regulatory authority.
(4) Includes $59 million forecasted for 2020.

To the extent the recorded costs for each account apart from Transmission Safety Repairs total an amount that is different from $1.420 billion, then the amount for which the Utility shall not seek rate recovery for Transmission Safety Repairs will be adjusted so that the total amount for which the Utility shall not seek rate recovery equals $1.625 billion.

PG&E Corporation and the Utility believerecord 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 charged to customers and the amount of disallowance can be reasonably estimated.

As of March 31, 2020, PG&E Corporation and the Utility recorded charges of $344 million, related to the portion of the $403 million in disallowed capital that had been spent through March 31, 2020 and, in 2020, expects to record $59 million related to capital expenditures listed in the table above. In addition, PG&E Corporation and Utility recorded charges of approximately $71 million related to vegetation management and catastrophic event expense costs that were previously determined to be probable of recovery and expects to record an additional $19 million in expenses later in 2020.

The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025.

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On February 27, 2020, the presiding officer issued a decision (the “POD”) requiring modifications to the settlement agreement that would (i) add $198 million in disallowances, bringing the total to $1.823 billion (ii) add $64 million in shareholder spending on System Enhancement Initiatives, bringing the total to $114 million; (iii) add a $200 million fine payable to the General Fund of the State of California; and (iv) require the Utility to return any tax savings associated with shareholder payments under the settlement to be “returned for the benefit of ratepayers once [the Utility] has realized the savings” (the “Tax Modification”). On March 18, 2020, the Utility appealed the POD and asked the CPUC to approve the settlement.

On March 27, 2020, the assigned commissioner requested that the full CPUC review the POD (the “Request for Review”) and (i) permanently suspend payment of the $200 million fine; and (ii) make the modification to the tax treatment apply only to shareholder payments for operating expenditures. On April 9, 2020, the Utility filed a response to the Request for Review, reiterating many of the points made in its appeal of the presiding officer decision. The Utility requested that the original settlement be approved or, in the alternative, that the POD’s Tax Modification be eliminated entirely, and the $200 million fine be removed or permanently suspended. Also on April 9, 2020, several parties filed their responses to the request for review, including but not limited to TURN, the SED, and the TCC. TURN supported the Tax Modification but rejected the assigned commissioner’s proposal to suspend the $200 million fine. The SED reiterated its support for the settlement as originally filed, but noted that it does not oppose the modifications set forth in the Request for Review. The TCC did not support any modifications to the settlement, including imposition of the $200 million fine. However, to the extent the fine is imposed, the TCC (1) urged the CPUC to reject the Utility’s request that the fine be designated as a Fire Claim under the Plan of Reorganization payable from the Fire Victim Trust, (2) asked that the Commission not specify the source of payment for the fine, and (3) proposed that the fine should be suspended “until such time, if ever, that a ‘triggering event’ occurs warranting payment.”

On April 20, 2020, the assigned commissioner issued a Decision Different adopting the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC could consider and vote on the POD and the Decision Different as early as on May 7, 2020.

The settlement agreement, as modified by the Decision Different, will imposebecome effective upon: (i) approval by the CPUC in a written decision, (ii) following such approval by the CPUC, approval of the Bankruptcy Court, and (iii) the effectiveness of a chapter 11 plan of reorganization for the Utility approving the implementation of the settlement agreement. The CPUC may accept, reject or propose alternative terms to the settlement agreement and Decision Different, including imposing additional penalties including fines or other remedies, on the Utility.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties. 

The Utility is unable to predict the timing and outcome of this proceeding.

OII and Order to Show Cause into the Utility’s Locate and Mark practices

On December 14, 2018, the CPUC issued an OII and order to show cause to assess the Utility’s practices and procedures related to the locating and marking of natural gas facilities. The OII directed the Utility to show cause as to why the CPUC should not find violations in this matter, and why the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility was also directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.

On October 3, 2019, the Utility, SED and CUE jointly submitted to the CPUC a proposed settlement agreement. Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $65 million, comprised of (i) a fine of $5 million funded by shareholders to be paid to the General Fund of the State of California pursuant to, and in accordance with, the time frame and other provisions governing distributions as set forth in the Chapter 11 plan of reorganization for the Utility as confirmed by the Bankruptcy Court; and (ii) $60 million in shareholder-funded initiatives undertaken to enhance, among other things, the Utility’s locate and mark compliance and capabilities and the reliability of the Underground Service Alert ticket management information that the Utility maintains in the ordinary course of its business.

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As previously disclosed, on January 17, 2020, the presiding officer issued a decision requiring modifications to the settlement agreement that would (i) require an extension of certain compliance audits required by the settlement agreement, at a cost to shareholders of $6 million, (ii) an additional fine of $39 million funded by shareholders to be paid to the General Fund of the State of California, (iii) certain additional system enhancements, and (iv) requirements on the previously proposed system enhancements, including a requirement that any funds remaining after completion of the system enhancements are not to be spent as agreed to by the parties, but is to be paid to the General Fund. On February 6, 2020, the settling parties filed a motion accepting the presiding officer’s proposed modifications to the settlement and proposing alternative relief.

On February 14, 2020, the presiding officer issued a decision noting that the settling parties had accepted the modifications included in the POD and rejected the alternative relief proposed by the settling parties. The POD became the final decision of the CPUC on February 20, 2020. On April 8, 2020, the Utility filed a motion with the bankruptcy court, seeking the approval of the settlement agreement, as modified by the POD. The bankruptcy court approved this motion on April 24, 2020.

As of March 31, 2020, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to payConsolidated Balance Sheets include a material amount of penalties or if the Utility were required to incur a material amount of costs that it cannot recover through rates.$44 million accrual.

This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed.

OII into Compliance with Ex Parte Communication Rules
Order Instituting an Investigation and Order to Show Cause into the Utility
’s Locate and Mark practices

On December 14, 2018,November 23, 2015, the CPUC issued an order instituting investigation and order to show cause (the “OII”) to assess the Utility’s practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the CPUC should not find violations in this matter, and why the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.



The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided an analysis, based on the available data, of tickets that should be properly categorized as late, and identification of associated dig-ins. As a result, the OII will determineinto whether the Utility violated any provisionshould be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locateCPUC’s Rules of Practice and mark policies, practices, and related issues, andProcedure governing the extent to whichconduct of those appearing before the Utility’s practices with regard to locate and mark may have diminished system safety.

CPUC. The CPUC indicates that it has not concluded thatsubsequently divided the Utility has violated the law in any instanceOII into two phases, pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found,different sets of communications.

As previously disclosed, on December 5, 2019, the CPUC will consider what monetary finesapproved a settlement agreement between the Cities of San Bruno and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines.

On March 14, 2019, as directed by the CPUC, the Utility submitted a report that addressedSan Carlos, Public Advocates Office, the SED, report and responded to the order to show cause.  A prehearing conference was held on April 4, 2019, to establish scope and a procedural schedule.  The assigned Commissioner and ALJ encouraged the SEDTURN, and the Utility, to reach a partial stipulation in order to streamline the proceeding.  On April 24, 2019, the Utility provided notice of a settlement conference and the parties have continued settlement discussions.  On May 7, 2019, the assigned Commissioner issued a scoping memo and ruling that included within the proceedings, in addition to the issues identified in the OII relating to the Utility’s locate and mark procedures, issues relating to the Utility’s use of “qualified electrical workers” for locating and marking underground infrastructure. On July 24, 2019, the SED submitted its opening testimony to the CPUC.  A status conference with the ALJ was held on July 30, 2019. The parties continue settlement discussions. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony is due August 16, 2019, and the Utility’s reply testimony is due September 18, 2019.  The SED’s rebuttal testimony is due October 4, 2019.  Evidentiary hearings are scheduled for October 21 to 25, 2019.

Based on the information available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties, including fines or other remedies. Accordingly, PG&E Corporation and the Utility recorded a charge during the quarter ended June 30, 2019 for an amount that is not material, which corresponds to the lower end of the range of PG&E Corporation's and the Utility's reasonably estimated losses and is subject to change based on additional information.  PG&E Corporation and the Utility are unable to determine a better estimate within such range given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties.  The Utility is unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to pay a material amount of penalties or if the Utility were required to incur a material amount of costs that it cannot recover through rates.

This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising outresolving phase two of this proceeding are stayed.

For(phase one was settled in April 2018, for more information about this proceeding, see “OII into Compliance with Ex Parte Communication Rules” in Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

On April 26, 2018, the CPUC approved the revised PD issued on April 3, 2018, adopting10-K). Under the settlement agreement, jointly submitted to the CPUC on March 28, 2017, as modified (the “settlement agreement”) by the Utility the Cities of San Bruno and San Carlos, PAO (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN.

The decision resulted in a total penalty of $97.5 million comprised of: (1) a $12 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 the Utility’s next GRC cycle (i.e., the 2020 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.



As a result of the CPUC’s April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At June 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include an $16 million accrual for a portion of the 2019 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On June 28, 2019, the Cities of San Bruno and San Carlos, PAO, the SED, TURN, and the Utility filed a joint motion with the CPUC seeking approval of a comprehensive settlement agreement that addresses all issues in the second phase of this proceeding. The settlement agreement proposed that the Utility pay a total penalty of $10 million comprised of: (1) a $2 million payment to the California General Fund of the State of California, (2) forgoing collection of $5 million in revenue requirements during the term of its 2019 GT&S rate case, (3) forgoing collection of $1 million in revenue requirement during the term of its 2020 GRC cycle, and (4) compensation payments of $1 million to each of the Cities of San Bruno and San Carlos in a total amount of $2 million ($1 million to each city). According toCarlos. By the terms of the settlement, these payments and forgone collection wouldthe financial remedies will not take placebe implemented until a plan of reorganization is approved in the Chapter 11 Cases. In accordance with accounting rules, adjustments related to forgone collections would be recorded in the periods in which they are incurred. On April 8, 2020, the Utility filed a motion with the Bankruptcy Court, seeking the approval of the settlement agreement. The Bankruptcy Court approved this motion on April 24, 2020.

At June 30, 2019,As of March 31, 2020, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $4 million accrual for the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos. The Utility is unable to predict whether the CPUC will approve the settlement.

For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 went into effect on May 1, 2019.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. The Utility expects the FERC to issue a decision in the TO18 rate case by late-2019,in 2020, however, the timing of that decision is uncertain, and it will likely be the subject of requests for rehearing and appeal.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18.

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On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing of its TO20 formula rate case, subject to hearings and refund, and established May 1, 2019, as the effective date for rate changes.  The FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties.  On March 31, 2020, the Utility filed a partial settlement of TO20 resolving certain issues related to the formula rate but leaving several issues including return on equity, capital structure, and depreciation rates for further settlement discussions or hearing.

The Utility is unable to predict the timing or outcome of FERC’s decisions in the TO18 and TO19 proceedings or the timing or outcome of the TO20 proceeding.



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.

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 $98$117 million and $116 million at March 31, 2020 and December 31, 2018. These amounts2019, respectively, and were included in Other current liabilities in the Condensed Consolidated Balance Sheets. On the Petition Date, these amounts were moved to LSTC. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code.

On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”

On April 6, 2020, plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. Plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. Plaintiff filed a designation of the record and statement of the issues on April 20, 2020, and the Utility will have until May 4, 2020, 14 days thereafter, to file a designation of any additional items.

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2015 GT&S Rate Case Disallowance of Capital DisallowanceExpenditures

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case.  The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. Additional charges may be required in the future based on the outcome of the CPUC’s audit of 2011 through 2014 capital spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 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 comprised of the following:
 Balance at
(in millions)March 31, 2020December 31, 2019
Topock natural gas compressor station$348  $362  
Hinkley natural gas compressor station133  138  
Former manufactured gas plant sites owned by the Utility or third parties (1)
667  568  
Utility-owned generation facilities (other than fossil fuel-fired),
  other facilities, and third-party disposal sites (2)
105  101  
Fossil fuel-fired generation facilities and sites (3)
104  106  
Total environmental remediation liability$1,357  $1,275  
 Balance at
(in millions)June 30, 2019 December 31, 2018
Topock natural gas compressor station$346
 $369
Hinkley natural gas compressor station142
 146
Former manufactured gas plant sites owned by the Utility or third parties (1)
580
 520
Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites (2)
112
 111
Fossil fuel-fired generation facilities and sites (3)
125
 137
Total environmental remediation liability$1,305
 $1,283
    
(1)Primarily driven by the following sites: San Francisco Beach Street, Vallejo, and San Francisco East Harbor, Napa, Beach Street, San Francisco North Beach, and San Rafael MGP-Bio Marin MGP.Harbor.
(2) Primarily driven by the Geothermal landfill and Shell Pond site.
(3)Primarily driven by the San Francisco Potrero Power Plant.



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 Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to 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 the environmental requirements on an ongoing basis, 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 June 30, 2019,March 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, and the Utility’s time frame for remediation.remediation, and unanticipated claims filed against the Utility.  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. At June 30, 2019,March 31, 2020, the Utility expected to recover $960$1,029 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

For more information, see remediation site descriptions below and see Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.

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. The Utility is also required to take measures to abate the effects of the contamination on the environment.

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Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $302$216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater 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 California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility 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 sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background study report was received in January 2020 and is expected to be issued in 2019 and finalized in 2020.2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $139$129 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.



Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $528$539 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $98$78 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $86$80 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.


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Insurance

Wildfire Insurance

In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general wildfire liability in policies covering wildfire and non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for wildfire property damages only, which included approximately $200 million of coverage through the use of a catastrophe bond. For the period from August 1, 2019 through July 31,In 2020, PG&E Corporation and the Utility have secured approximatelyhas liability insurance coverage for wildfire events in an amount of $430 million for general wildfire liability(subject(subject to an initial self-insured retention of $10 million per occurrence). for the period of August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period of August 1, 2019 through July 31, 2020 and $480 million for the period of September 3, 2019 through September 2, 2020. PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from August 1, 2019 through July 30, 2020.coverage. Various coverage limitations applicable to different insurance layers could result in uninsured costs in the future depending on the amount and type of damages resulting from covered events.

PG&E Corporation’s and the Utility’s cost of obtaining the wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through July 31,September 2, 2020 (consisting of the $430 million general wildfire liability coverage described above and $520 million for non-wildfire general liability) is approximately $190$212 million, compared to the approximately $50 million that the Utility is currently recovering throughrecovered in rates throughduring the year ended December 31, 2019. The Utility intends to seekhas sought recovery for the full amount of certain premium costs paid in excess of the amount the Utility currently is recovering from customers through the endGRC period ended December 31, 2019. The Utility’s 2020 GRC settlement agreement includes a new two-way balancing account that would allow the Utility to pass through insurance premium costs for up to $1.4 billion in coverage. The Utility is unable to predict the timing and outcome of the current2020 GRC period, which ends on December 31, 2019.proceeding.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur.  Through June 30, 2019,March 31, 2020, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842$843 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.



Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and European Mutual Association for Nuclear Insurance, covering nuclear or non-nuclear events at the Utility’s two2 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 the policy renewal on April 1, 2020, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41$43 million.  If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $5$4 million, as of the policy renewal on April 1, 2020.  For more information about the Utility’s nuclear insurance coverage, see Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K. 

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 June 30, 2019,March 31, 2020, it is reasonably possible that unrecognized tax benefits will decrease by approximately $10$40 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. 

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards during the pendency of the Chapter 11 Cases.

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility expect to be able to defer the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. PG&E Corporation and the Utility are currently evaluating the potential tax impact of these changes. PG&E Corporation will continue to monitor legislative activities.

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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, 2018,2019, the Utility had undiscounted future expected obligations of approximately $40$38 billion. (See Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.) The Utility has not entered into any new material commitments during the sixthree months ended June 30, 2019.March 31, 2020.

NOTE 12: SUBSEQUENT EVENTS
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On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

Each of California’s large investor-owned electric utility companies that are not currently subject to Chapter 11 (Southern California Edison and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

The Wildfire Fund to be established under AB 1054 will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund.



The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

In order to participate in the Wildfire Fund, within 60 days of the effective date of AB 1054, the Utility must obtain the Bankruptcy Court’s approval of the Utility’s election to pay the initial and annual Wildfire Fund contributions upon emergence from Chapter 11. The Utility would then be required to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11, and meet certain eligibility requirements listed below, in order to participate in the Wildfire Fund. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases. There are several additional eligibility requirements for the Utility, including that by June 30, 2020, the following conditions are satisfied:

the Utility’s Chapter 11 Case has been resolved pursuant to a plan of reorganization or similar document not subject to a stay;

the Bankruptcy Court has determined that the resolution of the Utility’s Chapter 11 Case provides funding or otherwise provides for the satisfaction of any pre-petition wildfire claims asserted against the Utility in the Chapter 11 Case, in the amounts agreed upon in any settlement agreements, authorized by the Bankruptcy Court through an estimation process or otherwise allowed by the Bankruptcy Court;

the CPUC has approved the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case, including the Utility’s resulting governance structure as being acceptable in light of the Utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC;

the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case are (i) consistent with California’s climate goals as required pursuant to the California Renewables Portfolio Standard Program and related procurement requirements and (ii) neutral, on average, to the Utility’s ratepayers; and

the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case recognize the contributions of ratepayers, if any, and compensate them accordingly through mechanisms approved by the CPUC, which may include sharing of value appreciation.

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.



If the Utility satisfies the requirements to participate in the Wildfire Fund, the Utility will be required to fund its initial contribution upon its emergence from Chapter 11.  The Utility’s required contributions to the Wildfire Fund will be substantial.  Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.  The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions.  The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases.  The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, consummate or implement any such plan, which will ultimately require Bankruptcy Court, creditor and regulatory approval.  Further, there can be no assurance that the expected benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



OVERVIEW

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.

The Utility is regulated primarily by the CPUC and the FERC.  The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage.  The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts.  The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.  The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report.Form 10-Q.  It also should be read in conjunction with the 20182019 Form 10-K.

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation’s and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). For additional information regarding the Chapter 11 Cases, refer to the website maintained by Prime Clerk, LLC, PG&E Corporation’s and the Utility’s claims and noticing agent, at http://restructuring.primeclerk.com/pge. The contents of this website are not incorporated into this document.

For more information about the Chapter 11 Cases, see “Item 1A. Risk Factors – Risks Related to Chapter 11 Proceedings and Liquidity” and “Item 7. MD&A – Chapter 11 Proceedings” in the 20182019 Form 10-K and Notes 2 and 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Going Concern

The accompanying Condensed Consolidated Financial Statements to this Form 10-Q have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, PG&E Corporation and the Utility are facing extraordinary challenges relating tosuffered material losses as a seriesresult of catastrophic wildfires that occurred inthe 2017 Northern California in 2017wildfires and 2018.the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection. As a result of these challenges, such realization of assets and satisfaction of liabilities are subject to uncertainty. For more information about the 2018 Camp fire and 2017 Northern California wildfires, see Note 10 of the Notes to the Condensed Consolidated Financial Statements and the 20182019 Form 10-K.

Management has concluded that uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns, and their independent registered public accountants included an explanatory paragraph in their auditors’ reports relating to the consolidated balance sheets of PG&E Corporation and the Utility as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, included in the 2018 Form 10-K, which statedstates certain conditions exist which raise substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns in relation to the foregoing. The Condensed Consolidated Financial Statements do not include any adjustments that might result from the outcome of these uncertainties.this uncertainty. For more information about these matters, see Notes 1 and 2 to the Condensed Consolidated Financial Statements and the 20182019 Form 10-K.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net lossincome available for common shareholders was $2,553 million and $2,420$371 million in the three and six months ended June 30, 2019, respectively,March 31, 2020, compared to net losses of $984 million and $542$136 million in the same periodsperiod in 2018.2019. In the three months ended March 31, 2020, PG&E Corporation recognized charges of $1.9 billion and $2.0 billion, net of probable insurance recoveries, associated withadditional base revenues authorized in the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019,TO20 rate case, as compared to charges of $2.1 billion, net of probable insurance recoveries, associated with the 2017 Northern California wildfires during the same periodsperiod in 2018.2019.


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Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

•
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. Although PG&E Corporation and the Utility have currently retained the exclusive rights to file a plan of reorganization until September 26, 2019 and to solicit acceptances thereof until November 26, 2019, the Ad Hoc Noteholder Committee and the Ad Hoc Subrogation Group have submitted motions to the Bankruptcy Court for the entry of orders terminating these exclusive rights. If these rights are terminated, there could be a material effect on PG&E Corporation’s and the Utility’s ability to achieve confirmation of a plan of reorganization that would enable PG&E Corporation and the Utility to reach their stated goals.

•
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, which was approved on a final basis on March 27, 2019.  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.

•
The Impact of the 2018 Camp Fire and the 2017 Northern California 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 (as of June 30, 2019, the Utility recorded total charges of $18 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; any punitive damages, fines and penalties or damages related to future claims could be material;

◦whether, in light of the CPUC July 8, 2019 final decision in the Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, the Utility will be able to obtain a substantial recovery of costs related to the 2017 Northern California wildfires;

◦the impact of investigations, including criminal, regulatory, and SEC investigations;

◦the outcome of the 2017 Northern California Wildfires OII, and any fines or penalties that could result therefrom;

◦fines or penalties, which could be material, if any regulatory or law enforcement agency were to bring an enforcement action, including a criminal proceeding, and determined that the Utility had failed to comply with applicable laws and regulations;

◦the amount of damages in respect of future claims, which could be material;


•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 have incurred and expect to continue 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. Although PG&E Corporation and the Utility have entered into settlement agreements to resolve the claims of the major classes of claimholders, including Utility debtholders, individual wildfire victims, holders of subrogated insurance claims and certain public entities, claimholders not party to a settlement agreement may still be able to challenge and otherwise impede the Plan, including in the case of individual wildfire-related claimholders by voting against the Plan. These settlement agreements could be terminated under various circumstances, some of which are beyond PG&E Corporation’s and the Utility’s control. In addition, PG&E Corporation’s and the Utility’s ability to emerge from Chapter 11 is dependent on their ability to satisfy the conditions set forth in AB 1054, as determined by the CPUC. PG&E Corporation and the Utility believe the Plan meets the requirements of AB 1054 by, among other things, satisfying wildfire claims through settlements consistent with the terms of AB 1054, by keeping rates neutral, on average, for the Utility’s customers, and by providing for the assumption of all power-purchase agreements, community-choice aggregation servicing agreements, and collective bargaining agreements. Finally, in order to emerge from Chapter 11, PG&E Corporation and the Utility must finance the Plan. There are numerous uncertainties related to such financings, including the ability to successfully raise equity or debt in the public or private markets, the ability to satisfy the terms and conditions set forth in the debt and equity commitment letters and the Noteholder RSA, the ability to collect insurance proceeds and the amount of additional capital that can be obtained to finance the Plan, including through securitization.

◦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 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, which was approved on a final basis on March 27, 2019.  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 and cash flow from operations, 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, and availability under the DIP Credit Agreement are not sufficient to meet 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.

◦the recoverability of the above-mentioned costs, even if a court decision imposes liability under the doctrine of inverse condemnation;
•The Impact of the 2018 Camp Fire, 2017 Northern California Wildfires and the 2015 Butte fire.  PG&E Corporation and the Utility face several uncertainties in connection with the 2018 Camp fire, 2017 Northern California wildfires and the 2015 Butte fire, related to:

◦the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise, which potential financings are not addressed by AB 1054 as it only applies to future wildfires;
◦the amount of possible loss related to third-party claims (as of March 31, 2020, the Utility’s best estimate of probable loss in connection with the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire was $25.5 billion), which amount is subject to change based on a number of factors, including whether existing settlements are upheld, whether any termination events are triggered under these agreements, whether the classification and treatment of claims in the Plan is successfully challenged by claimholders who are not party to a settlement agreement, whether punitive damages, fines and penalties are treated as specified in the Plan, whether the Plan is confirmed, and whether the requisite number of impaired wildfire claimholders vote to approve the Plan in the Chapter 11 Cases;

◦the amount and recoverability of enhanced and accelerated inspection costs of the Utility’s electric transmission and distribution assets (the Utility incurred costs of $275 million and $485 million for enhanced and accelerated inspection and repair costs for the three and six months ended June 30, 2019, respectively); and
◦the outcome of the Wildfires OII, including whether the settlement agreement, as amended, is approved by the CPUC and the Bankruptcy Court;

◦the amount and recoverability of clean-up and repair costs (the Utility incurred costs of $989 million for clean-up and repair of the Utility’s facilities through June 30, 2019).
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◦the impact of other investigations, including criminal, regulatory, and SEC investigations;

◦the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise; and

◦the amount and recoverability of clean-up and repair costs, including as may be limited by the outcome of the Wildfires OII (the Utility incurred costs of $1.21 billion for clean-up and repair of the Utility’s facilities through March 31, 2020).

(See Notes 4, 10, and 1011 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Item 1A. Risk Factors in Part II.)

•
•The Impact of the 2019 Kincade Fire. Claims related to the 2019 Kincade fire will not be discharged in connection with emerging from Chapter 11. Accordingly, if PG&E Corporation or the Utility were determined to be liable for the 2019 Kincade fire, such liabilities could be significant and could exceed the amounts available under applicable insurance policies, which could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

•The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. Although the financial impact of future wildfires could be mitigated through insurance, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund would be available to the Utility to pay eligible claims for liabilities arising from future wildfires and would serve as an alternative to traditional insurance products, provided that the Utility satisfies the numerous conditions to the Utility’s participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds.

 While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. Although the financial impact of future wildfires could be mitigated through insurance, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured loses depending on the amount and type of damages resulting from covered events. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund would be available to the Utility to pay eligible claims for liabilities arising from future wildfires and would serve as an alternative to traditional insurance products, provided that the Utility satisfies the numerous conditions to the Utility’s participation in the Wildfire Fund set forth in AB 1054.

However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s eligibility to access relief under the Wildfire Fund (which is dependent on, among other things, PG&E Corporation and the Utility emerging from Chapter 11 Cases being resolved by June 30, 2020 pursuant to a plan or similar document not subject to a stay and the Utility making theits initial contribution thereto), the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. The Utility may not be able to finance its required contributions to the Wildfire Fund, which consist of an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million. Finally, even if the Utility satisfies the eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising between July 12, 2019 and the Utility’s emergence from Chapter 11, the availability of the Wildfire Fund to pay such claims will be capped at 40% of the amount of such claims.

•
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 those described above as well as the outcome of the Locate and Mark OII, the outcome 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 Monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

•The AB 1054 Deadline of June 30, 2020. In the event that PG&E Corporation and the Utility are unable to confirm a plan of reorganization by June 30, 2020, the Utility will not be eligible to participate in the Wildfire Fund established under AB 1054. In that scenario, the Utility (i) would be unable to seek payment from the Wildfire Fund for liabilities arising from wildfires occurring after the July 12, 2019 effective date of AB 1054 (which in the case of pre-emergence wildfires, such as the 2019 Kincade fire, would be limited to 40% of such liabilities in excess of $1 billion), (ii) would not receive the benefit of the 20% disallowance cap contemplated by AB 1054, (iii) would not be required to make any contributions to the Wildfire Fund, (iv) in applications for cost recovery for wildfires occurring after July 12, 2019, would nevertheless be subject to review under the “just and reasonable” standard set forth in section 451.1 of the Public Utilities Code (i.e., the standard as modified by AB 1054) and (v) may still be eligible to obtain the annual safety certifications contemplated by section 8389 of the Public Utilities Code (which has implications for the burden of proof in a proceeding for cost recovery under section 451.1 of the Public Utilities Code).

•
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•The Impact of the COVID-19 pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been (for the months of March and April 2020) and will continue to be significantly affected by the outbreak of COVID-19. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, the moratorium on service disconnections and an observed reduction in non-residential electrical load. The Utility is in the early stages of evaluating the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. This impact to liquidity may be partially offset by reductions in discretionary capital spending or potential regulatory or payroll tax policy changes. As of March 31, 2020, PG&E Corporation and the Utility had access to approximately $4.6 billion of total liquidity comprised of approximately $1.5 billion of Utility cash, $0.4 billion of PG&E Corporation cash and $2.7 billion of availability under the DIP Credit Agreement. Other potential impacts of COVID-19 on PG&E Corporation and the Utility include operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations may also adversely impact operations, a reduction in revenue due to the cost of capital adjustment mechanism, the potential for higher borrowing costs due to the increasing difference in the higher yield of lower-rated debt as compared to the lower yield of higher-rated debt of similar maturity and incremental financing needs. For more information on the impact of COVID-19 on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be significantly affected by the outbreak of the COVID-19 pandemic” and “Market conditions resulting from the outbreak of COVID-19 may hinder PG&E Corporation’s and the Utility’s exit financing to emerge from Chapter 11” in Item 1A Risk Factors in Part II.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. PG&E Corporation and the Utility’s analysis of the potential impact of COVID-19 is preliminary and subject to change.

•The Uncertainties Regarding the Impact of Recent and Future Public Safety Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility’s wildfire risk mitigation initiatives outlined in the 2019 Wildfire Mitigation Plan, has been the subject of significant scrutiny and criticism by various stakeholders, including the California Governor, the CPUC and the court overseeing the Utility’s probation. On November 12, 2019, the CPUC issued an order to show cause why the Utility should not be sanctioned for alleged violations of law related to its communications with customers, coordination with local governments, and communications with critical facilities and public safety partners during the PSPS events in late 2019. On November 13, 2019, the CPUC instituted an OII to examine 2019 PSPS events carried out by California’s investor-owned utilities and to consider enforcement actions. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. In addition to the 2019 PSPS events, the Utility expects that PSPS events will be necessary in 2020 and future years. (See “OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions” in “Regulatory Matters” below.)

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In addition, the proposals of SB 378, which would impose penalties and other requirements on electric utility companies relating to PSPS events, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition to other requirements, SB 378 would impose on an electric utility company a civil penalty of at least $250,000 per 50,000 affected customers for every hour that a PSPS event is in place, would require the CPUC to establish a procedure for customers, local governments and others to recover costs accrued during a PSPS event from the electric utility company, which cost recovery would be borne by shareholders, and would prohibit an electric utility company from billing customers for any nonfixed costs during a PSPS event. Further, the proposals of AB 1941 could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. AB 1941 proposes to suspend RPS requirements, determine the savings to electric utility companies from the suspension and direct those savings towards system hardening to mitigate wildfire risks and PSPS impacts, and would prohibit salary increases or bonuses to executive officers during the suspension of RPS requirements. In addition, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The requested requirements include providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. A CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events. PG&E Corporation and the Utility are unable to predict the timing and the outcome of this request.

•The Costs of Other Wildfire Mitigation Efforts. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events. PG&E Corporation and the Utility incurred approximately $2.6 billion in connection with the 2019 WMP, and expect to incur approximately $2.7 billion in 2020 in connection with its 2020-2022 WMP. Although the Utility may seek cost recovery for certain of these expenses and capital expenditures, the Utility has agreed not to seek rate recovery of certain wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion.

While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. The Court overseeing the Utility’s probation in connection with the Utility’s federal criminal proceeding has imposed numerous obligations on the Utility related to its business and operations, including full compliance with all applicable laws concerning vegetation management and clearance requirements, submission to regular, unannounced inspections by the Monitor of the Utility’s vegetation management efforts and equipment inspection, enhancement and repair efforts and the maintenance of traceable, verifiable, accurate and complete records of the Utility’s vegetation management efforts and monthly reports to the Monitor on the status and progress of vegetation management efforts. On April 29, 2020, the Court entered an order requiring, among other things, the Utility to materially expand its vegetation management program, including through the hiring of additional employees, and to implement a new inspection and record-keeping system for transmission towers. PG&E Corporation and the Utility also face uncertainties in connection with the amount and recoverability of enhanced and accelerated inspection costs of the Utility’s electric transmission and distribution assets. (See “Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. 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 those described above as well as the outcome of the safety culture 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 Monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California.

•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2020 GRC, FERC TO18, TO19, and TO20 rate cases, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, FHPMA, WMPMA, and FRMMA that are incurred in connection with the Utility’s 2019 WMP, the amount of which is approximately $2.6 billion, and 2020-2022 WMP, with costs of approximately $2.7 billion planned in 2020.  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.  The Utility’s ability to seek cost recovery may also be limited by the outcome of the Wildfires OII. (See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.)

•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. 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 submitted 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 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. On April 1, 2020, the CPUC issued a Proposed Decision which if approved, would grant the waiver. A final decision on the Utility’s application is expected to be voted out on May 7, 2020. On April 20, 2020, the CPUC also issued a proposed decision in the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization addressing this issue. (See “Regulatory Matters” below.)

. 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, 2020 cost of capital proceeding, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, FHPMA, WPMA, and FRMMA that are incurred in connection with the Utility's 2019 Wildfire Safety Plan, the amount of which is substantial and is expected to increase.  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 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.)

•
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. 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 submitted 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 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. The Utility is unable to predict the timing and outcome of its waiver application. (See “Regulatory Matters” below.)

For more information about the factors and risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors” in this Form 10-Q and the 20182019 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See the section entitled “Forward-Looking Statements” belowabove for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are not ableunable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three months ended March 31, 2020 and 2019.See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) attributable to common shareholders for the three and six months ended June 30, 2019March 31, 2020 and 2018:2019:
Three Months Ended March 31,
(in millions)20202019
Consolidated Total$371  $136  
PG&E Corporation(77) 3  
Utility$448  $133  
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Consolidated Total$(2,553) $(984) $(2,420) $(542)
PG&E Corporation1
 (4) 4
 (11)
Utility$(2,554) $(980) $(2,424) $(531)

PG&E Corporation’s net income (loss) primarily consists of income taxes, interest income on cash held, and interest expense on long-term debt.debt, and reorganization items.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019March 31, 2020 and 2018.2019.  The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings.  In addition, expenses that have been specifically authorized (such as the payment of pensionenergy procurement costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings.


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Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base.  Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.
Three Months Ended
March 31, 2020		Three Months Ended
March 31, 2019
Revenues/Costs:Revenues/Costs:
(in millions)That Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal Utility
Electric operating revenues$2,155  $885  $3,040  $1,913  $879  $2,792  
Natural gas operating revenues864  402  1,266  794  425  1,219  
   Total operating revenues3,019  1,287  4,306  2,707  1,304  4,011  
Cost of electricity—  545  545  —  599  599  
Cost of natural gas—  284  284  —  339  339  
Operating and maintenance
1,463  502  1,965  1,694  410  2,104  
Depreciation, amortization, and decommissioning855  —  855  797  —  797  
   Total operating expenses2,318  1,331  3,649  2,491  1,348  3,839  
Operating income (loss)701  (44) 657  216  (44) 172  
Interest income
16  —  16  21  —  21  
Interest expense
(252) —  (252) (101) —  (101) 
Other income, net
49  44  93  22  44  66  
Reorganization items(93) —  (93) (111) —  (111) 
Income before income taxes$421  $—  $421  $47  $—  $47  
Income tax benefit (1)
(30) (86) 
Net income451  133  
Preferred stock dividend requirement (1)
3  —  
Income Available for Common Stock$448  $133  
 Three Months Ended
June 30, 2019		 Three Months Ended
June 30, 2018
 Revenues/Costs: Revenues/Costs:
(in millions)That Impacted Earnings That Did Not Impact Earnings Total Utility That Impacted Earnings That Did Not Impact Earnings Total Utility
Electric operating revenues$1,872
 $1,074
 $2,946
 $1,979
 $1,333
 $3,312
Natural gas operating revenues792
 205
 997
 752
 170
 922
   Total operating revenues2,664
 1,279
 3,943
 2,731
 1,503
 4,234
Cost of electricity—
 837
 837
 —
 963
 963
Cost of natural gas—
 108
 108
 —
 79
 79
Operating and maintenance 
1,562
 378
 1,940
 1,244
 542
 1,786
Wildfire-related claims, net of insurance recoveries3,900
 —
 3,900
 2,125
 —
 2,125
Depreciation, amortization, and decommissioning796
 —
 796
 746
 —
 746
   Total operating expenses6,258
 1,323
 7,581
 4,115
 1,584
 5,699
Operating loss(3,594) (44) (3,638) (1,384) (81) (1,465)
Interest income 
22
 —
 22
 11
 —
 11
Interest expense 
(60) —
 (60) (222) —
 (222)
Other income, net 
20
 44
 64
 27
 81
 108
Reorganization items(57) —
 (57) —
 —
 —
Loss before income taxes$(3,669) $—
 $(3,669) $(1,568) $—
 $(1,568)
Income tax benefit (1)
    (1,119)     (592)
Net loss    (2,550)     (976)
Preferred stock dividend requirement    4
     4
Loss Attributable to Common Stock    $(2,554)     $(980)
            
(1) This itemThese items impacted earnings for the three months ended June 30, 2019March 31, 2020 and 2018.2019.



 Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
 Revenues/Costs: Revenues/Costs:
(in millions)That Impacted Earnings That Did Not Impact Earnings Total Utility That Impacted Earnings That Did Not Impact Earnings Total Utility
Electric operating revenues$3,786
 $1,952
 $5,738
 $3,915
 $2,348
 $6,263
Natural gas operating revenues1,586
 630
 2,216
 1,490
 537
 2,027
   Total operating revenues5,372
 2,582
 7,954
 5,405
 2,885
 8,290
Cost of electricity—
 1,436
 1,436
 —
 1,782
 1,782
Cost of natural gas—
 447
 447
 —
 368
 368
Operating and maintenance 
3,256
 788
 4,044
 2,494
 896
 3,390
Wildfire-related claims, net of insurance recoveries3,900
 —
 3,900
 2,118
 —
 2,118
Depreciation, amortization, and decommissioning1,593
 —
 1,593
 1,498
 —
 1,498
   Total operating expenses8,749
 2,671
 11,420
 6,110
 3,046
 9,156
Operating loss(3,377) (89) (3,466) (705) (161) (866)
Interest income 
43
 —
 43
 20
 —
 20
Interest expense 
(161) —
 (161) (439) —
 (439)
Other income, net 
41
 89
 130
 56
 161
 217
Reorganization items(168) —
 (168) —
 —
 —
Loss before income taxes$(3,622) $—
 $(3,622) $(1,068) $—
 $(1,068)
Income tax benefit (1)
    (1,205)     (544)
Net loss    (2,417)     (524)
Preferred stock dividend requirement    7
     7
Loss Attributable to Common Stock    $(2,424)     $(531)
            
(1)
This item impacted earnings for the six months ended June 30, 2019 and 2018.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and six months ended June 30,March 31, 2020 and 2019, and 2018, focusing on revenues and expenses that impacted earnings for these periods. 

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings decreasedincreased by $67$312 million, or 2%12%, and $33 million, or 1% in the three and six months ended June 30, 2019, respectively,March 31, 2020, compared to the same periodsperiod in 2018,2019, primarily due to additional revenues recorded pursuant to the regulatory treatment of interest on pre-petition debt and other impacts of the Chapter 11 Cases.pending TO20 rate case.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increaseddecreased by $318$231 million, or 26%14%, in the three months ended June 30, 2019,March 31, 2020, compared to the same period in 2018,2019, primarily due to $275a decrease of $198 million related to enhanced and acceleratedelectric asset inspections and repairs of transmission and distribution assets and $71 million forcosts. Additionally, clean-up and repair costs relating to the 2018 Camp fire with no similar charges in the same period in 2018.

The Utility’s operating and maintenance expenses that impacted earnings increaseddecreased by $762$166 million, or 31%, in the six months ended June 30, 2019,as compared to the same period in 2018, primarily due to $4852019 (the Utility recorded $13 million in the three months ended March 31, 2020 for clean-up and repair costs related to enhanced and accelerated inspections and repairs of transmission and distribution assets and $250the 2018 Camp fire, as compared to $179 million in same period in 2019). These decreases were partially offset by $43 million for clean-up and repair costs relating to the 2018 Camp2019 Kincade fire with no similar charges in the same period in 2018. Additionally, the Utility recorded $40 million in clean-up and repair costs relating to the 2017 Northern California wildfires in the six months ended June 30, 2018, with no similar charges in the same period in 2019.



Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings increased by $1,775 million, or 84%, and $1,782 million, or 84%,incurred in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018. The Utility recognized pre-tax charges of March 31, 2020.
$1.9 billion and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019, as compared to pre-tax charges of $2.5 billion, offset by probable insurance recoveries of $375 million, associated with the 2017 Northern California wildfires during the same periods in 2018.
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(See “Item 1A. Risk Factors” in the 2018 Form 10-K and Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $50$58 million, or 7%, and $95 million, or 6%, in the three and six months ended June 30, 2019, respectively,March 31, 2020, compared to the same periodsperiod in 2018,2019, primarily due to capital additions.additions and an increase in depreciation rates associated with the 2019 GT&S rate case.

Interest Income

There was no material change to interest income that impacted earnings for the periods presented.

Interest Expense

Interest expense that impacted earnings decreasedincreased by $162$151 million, or 73%150%, and $278 million, or 63% in the three and six months ended June 30, 2019, respectively,March 31, 2020, compared to the same periodsperiod in 2018,2019, primarily due to the cessation of interest accruals on outstanding pre-petition debt beginning January 29,in the three months ended March 31, 2019 in connection with the Chapter 11 Cases. In the fourth quarter of 2019, the Utility concluded that interest was probable of being an allowed claim and resumed recording interest on pre-petition debt subject to compromise.

Other Income, Net

There were no material changes to otherOther income, net that impacted earnings forincreased by $27 million, or 123%, in the periods presented.three months ended March 31, 2020, compared to the same period in 2019, primarily due to lower pension expense resulting from higher expected return on plan assets.

Reorganization items, net

Reorganization items, net increaseddecreased by $57$18 million, and $168 millionor 16%, in the three and six months ended June 30, 2019, respectively,March 31, 2020, compared to the same periodsperiod in 2018,2019 primarily due to $75a $94 million and $195charge recorded in 2019 related to DIP facilities costs, offset by a $72 million respectively, ofincrease in expenses directly associated with the Utility’s Chapter 11 filing in the three and six months ended June 30, 2019, partially offset by interest income of $18 million and $27 million, respectively.filing.

(See “Item 1A. Risk Factors” in the 20182019 Form 10-K and Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Income Tax ProvisionBenefit

Income tax benefits increasedbenefit decreased by $527$56 million, and $661 millionor 65%, in the three and six months ended June 30, 2019, respectively,March 31, 2020 as compared to the same periods in 2018. The increases in income tax benefits were primarily the result of higher pretax losses in the three and six months ended June 30, 2019, compared to the same period in 2018.



2019. The effective tax rates for the three months ended March 31, 2020 and 2019 were (7.0)% and (182.3)%, respectively. The decrease in the income tax benefit was primarily the result of higher pre-tax income in the three months ended March 31, 2020, compared to the same period in 2019.

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
2019 2018 2019 201820202019
Federal statutory income tax rate21.0 % 21.0% 21.0 % 21.0%Federal statutory income tax rate21.0 %21.0 %
Increase (decrease) in income tax rate resulting from:       Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
7.4 % 8.6% 7.7 % 11.5%
State income tax (net of federal benefit) (1)
1.0 %(17.7)%
Effect of regulatory treatment of fixed asset differences (2)
2.3 % 6.2% 4.6 % 16.8%
Effect of regulatory treatment of fixed asset differences (2)
(23.4)%(179.2)%
Tax credits0.1 % 0.2% 0.2 % 0.6%Tax credits(0.4)%(5.8)%
Other, net(0.3)% 1.9% (0.2)% 1.1%Other, net(5.2)%(0.6)%
Effective tax rate30.5 % 37.9% 33.3 % 51.0%Effective tax rate(7.0)%(182.3)%
       
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by various CPUC decisions.  All amounts are impacted by the level of income before income taxes.  The various CPUC rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 20182020 and 2019, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

Utility Revenues and Costs that did notDid Not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by electricity and natural gas procurement costs.  See below for more information.

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  The costsCost of electricity also includeincludes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)  The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 2018(in millions)20202019
Cost of purchased power, net (1)
$796
 $919
 $1,295
 $1,672
Cost of purchased power, netCost of purchased power, net$473  $499  
Fuel used in generation facilities41
 44
 141
 110
Fuel used in generation facilities72  100  
Total cost of electricity$837
 $963
 $1,436
 $1,782
Total cost of electricity$545  $599  
       
(1) Cost of purchased power, net decreased for the three and six months ended June 30, 2019, compared to the same periods in 2018, primarily due to lower Utility electric customer demand, driven by customer departures to CCAs and DA providers, and by higher net sales in the CAISO electricity markets.



Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)  The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand. 
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 2018(in millions)20202019
Cost of natural gas sold$82
 $53
 $391
 $310
Cost of natural gas sold$253  $309  
Transportation cost of natural gas sold26
 26
 56
 58
Transportation cost of natural gas sold31  30  
Total cost of natural gas$108
 $79
 $447
 $368
Total cost of natural gas$284  $339  
       
(1) One thousand cubic feet
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Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs.  If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.

Other Income, Net

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

OnAs a result of the Petition Date,outbreak of COVID-19, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be significantly affected. The Utility is in the early stages of evaluating the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist, including the moratorium on service disconnections and an observed reduction in non-residential electrical load. The reduction in cash collections from customers may be partially offset by reductions in discretionary capital spending or potential regulatory or tax policy changes. As of March 31, 2020, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. In connection with the Chapter 11 Cases,had access to approximately $4.6 billion of total liquidity comprised of approximately $1.5 billion of Utility cash, $0.4 billion of PG&E Corporation cash and the Utility entered into$2.7 billion of availability under the DIP Credit Agreement.

The DIP Credit Agreement providesoutbreak of COVID-19 and the resulting economic conditions and government orders have and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have and will continue to impact the Utility for $5.5 billion in senior secured superpriority debtor in possession credit facilities inan indeterminate period of time. Although the formUtility is seeking regulatory relief to mitigate the impact of (i)the consequences of the COVID-19 pandemic, there can be no assurance that any relief is forthcoming or that, if any relief measures are implemented, the timing that any such relief would impact the Utility. On April 16, 2020, the CPUC approved a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” togetherresolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the DIP Revolving Facilitycustomer protections described within the resolution. The Utility must file a Tier 2 Advice Letter with the CPUC no later than May 1, 2020, describing all reasonable and the DIP Initial Term Loan Facility, the “DIP Facilities”), subjectnecessary actions to the termsimplement emergency customer protections through April 16, 2021. (See “Emergency Authorization and conditions set forth therein. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the UtilityOrder Directing Utilities to borrow up to the full amount of the DIP Revolving Facility (including the full amount of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement. (ForImplement Emergency Customer COVID-19 Protections” below for more information on the DIP Credit Agreement, see “DIP Credit Agreement” below and Note 5 of the Notes to the Consolidated Financial Statements in Item 1.information.)

For the duration of the Chapter 11 Cases, the Utility’s ability to fund operations, finance capital expenditures and pay other ongoing expenses and make distributions to PG&E Corporation will primarily depend on the levels of its operating cash flows and availability under the DIP Credit Agreement. The Utility expects that the DIP Facilities will provide it with sufficient liquidity to fund its ongoing operations, including its ability to provide safe service to customers, during the Chapter 11 Cases. For the duration of the Chapter 11 Cases, PG&E Corporation’s ability to fund operations and pay other ongoing expenses will primarily depend on cash on hand and intercompany transfers. In the event that PG&E Corporation’s and the Utility’s capital needs increase materiallysignificantly due to unexpected events or transactions, additional financing outside of the DIP Facilities may be required, which would be subject to approval by the Bankruptcy Court. Such approval is not assured. For more information on PG&E Corporation’s and the Utility’s material commitments for capital expenditures, see “Regulatory Matters” below.


Market conditions resulting from the outbreak of COVID-19 may hinder PG&E Corporation’s and the Utility’s exit financing to emerge from Chapter 11 to the extent that it makes an equity offering that satisfies the price thresholds in the Backstop Commitment Letters more difficult to attain or affects the terms on which PG&E Corporation and the Utility may be able to raise money in the debt markets for the amount of its debt raise that is not backstopped by the Debt Commitment Letters. Management will continue to monitor potential impacts to PG&E Corporation’s and the Utility’s exit financing plans, including cost and timing of financing and availability of capital.

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During 2018 and January 2019, PG&E Corporation’s and the Utility’s credit ratings were subject to multiple downgrades by Fitch, S&P and Moody’s including to ratings below investment grade and ultimately to “D” or low “C” ratings. In the first quarter of 2019, Moody’s, Fitch, and Fitch withdrewS&P have all withdrawn each of their credit ratings for PG&E Corporation and the Utility as a result of the Chapter 11 Cases. As a result of PG&E Corporation’s and the Utility’s credit ratings ceasing to be rated at investment grade, the Utility has been required to post additional collateral under certain of its commodity purchase agreements and certain other obligations, and has been exposed to significant constraints on its customary trade credit.obligations. In addition, PG&E Corporation and the Utility may be required to post additional collateral in respect of certain other obligations, including workers’ compensation and environmental remediation obligations. (See NotesNote 8 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. 

Financial Resources

Acceleration of Pre-Petition Debt Obligations

The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of, the Accelerated Direct Financial Obligations. Accordingly, as a result of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility disclosed in Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

DIP Credit Agreement

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and received the proceeds of such borrowing, net of original issue discount and repayment of the $350 million in outstanding borrowings under the DIP Revolving Facility. The DIP Initial Term Loan Facility matures on December 31, 2020 (subject to an extension option described further below) and bears interest at a spread of 225 basis points over LIBOR.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case. The DIP Facilities will mature on December 31, 2020, subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee. The Utility paid customary fees and expenses in connection with obtaining the DIP Facilities.

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and received the proceeds of such borrowing, net of original issue discount and repayment of the $350 million in outstanding borrowings under the DIP Revolving Facility. The DIP Initial Term Loan Facility matures on December 31, 2020 (subject to an extension option described further below) and bears interest at a spread of 225 basis points over LIBOR. On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed Draw Term Loan Facility.

As of August 7, 2019,April 29, 2020, the Utility had outstanding borrowings of $1.5 billion under the DIP Initial Term Loan Facility, no outstanding borrowings$500 million under the DIP Delayed Draw Term Loan Facility, or the DIP Revolving Facility and $537$815 million in face amount of letters of credit outstanding under the DIP Revolving Facility. As of August 7, 2019,April 29, 2020, there were undrawn commitments of $500 million and $3.0$2.7 billion on the DIP Delayed Draw Term Loan FacilityRevolving Facility.

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Debt Commitment Letters

On October 11, 2019, PG&E Corporation and the DIP RevolvingUtility entered into the Debt Commitment Letters with the Commitment Parties, which were subsequently amended on November 18, 2019, December 20, 2019, January 30, 2020, February 14, 2020 and February 28, 2020, pursuant to which the Commitment Parties committed to provide $10.825 billion in bridge financing in the form of (a) a $5.825 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy as borrower thereunder and (b) a $5 billion senior unsecured bridge loan facility (together with the OpCo Facility, respectively. Pursuantthe “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy as borrower thereunder, subject to the terms and conditions set forth therein. The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights set forth in the Debt Commitment Letters. PG&E Corporation and the Utility will pay customary fees and expenses in connection with obtaining the Facilities. If the entire $10.825 billion of bridge commitments remain outstanding as of June 30, 2020, the aggregate fees payable (including commitment fees and ticking fees, but excluding any fees related to the funding of the DIP Credit Agreement, until such time asFacilities) by PG&E Corporation and the DIP Delayed Draw Term Loan Facility has been drawn in full,Utility would be approximately $75 million.

In connection with the anticipated funding for the Plan and the anticipated amount of debt and equity to be used for funding thereunder, on February 14, 2020, the Debt Commitment Letters were amended to, among other things, (1) adjust the maximum amount of any roll-over, “take-back” or the commitments in respect thereof have terminated or expired, further borrowingsreinstated debt permitted under the DIP Revolving Facility are not permitted.



CPUC Authorization of DIP Credit Agreement

On January 28, 2019, the CPUC grantedFacilities from $30.0 billion to $33.35 billion at the Utility exemptionsand from $7.0 billion to $5.0 billion at PG&E Corporation, (2) reduce the amount of proceeds from the requirementissuance of prior CPUC approval forequity that PG&E Corporation has to receive as a condition to funding from $12.0 billion to $9.0 billion, and (3) increase the amount of proceeds from the issuance of debt instrumentssecurities or other debt for borrowed money as a condition to funding from $2.0 billion at PG&E Corporation to $6.0 billion at the incurrenceUtility.

In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the DIP financing. The CPUC also indicated its position thatforegoing. (See “Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings” below and "Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt Commitment Letters" in Note 2 of the exemptions do not extendNotes to the transfer of ownership of anyCondensed Consolidated Financial Statements in Item 1.)

On October 23, 2019, PG&E Corporation and the Utility asset that is pledged as partfiled a motion with the Bankruptcy Court seeking approval of the DIP financingDebt Commitment Letters and that incertain related matters. On March 16, 2020, the event ofBankruptcy Court approved the Utility’s default under the DIP financing, the Utility would need to seek the CPUC’s approval to execute such a transfer. Further, the CPUC indicated that the Utility’s “expenditure of the initial DIP financing funds for any purposes may not be recovered from ratepayers without Commission approval in a future application for rate recovery” and that the Utility “bears the burden of demonstrating the reasonableness of any expenditure.”Debt Commitment Letters (as amended through February 28, 2020).

Equity Financings

There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the sixthree months ended June 30, 2019. 

March 31, 2020.
During the six months ended June 30, 2019, PG&E Corporation issued
8.3 million shares for cash proceeds of $85.2 million under the PG&E Corporation 401(k) plan. The proceeds from these sales were used for general corporate purposes. Beginning January 1, 2019, PG&E Corporation’sCorporation changed its default matching contributions under its 401(k) plan are deposited infrom PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PCGPG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

PG&E Corporation does not expectexpects to issue new shares of PG&E Corporation common stock for up to $9.0 billion of proceeds at or prior to emergence from Chapter 11 in order to finance the Plan. The structure, terms and conditions of any such equity forissuance are expected to be determined by PG&E Corporation and the remaining duration ofUtility at a later time in the Chapter 11 Cases.process, subject to the terms and conditions of the Backstop Commitment Letters. There can be no assurance that any such equity offering would be successful. PG&E Corporation has obtained the Backstop Commitment Letters providing for equity funding of up to $12.0 billion to finance the transactions contemplated by the Plan. In the event that new equity offerings do not raise at least $9.0 billion of proceeds, or if additional capital is required, PG&E Corporation may draw on the Backstop Commitments for equity funding of up to $12.0 billion, subject to satisfaction or waiver by the Backstop Parties of the conditions set forth therein. (See “Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings” below and “Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt Commitment Letters” in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) On March 16, 2020, the Bankruptcy Court approved the Commitment Letters (as amended through March 6, 2020).

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Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings

PG&E Corporation and the Utility expect that the funding for the Plan will consist of both new debt and equity for both PG&E Corporation and the Utility as well as other sources of funding totaling approximately $58 billion. For additional information, see the 2019 Form 10-K.

In addition, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence securitization transaction. (For more information regarding the application, see “Regulatory Matters” below.)

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the 2018 Camp fire and the 2017 Northern California wildfires. PG&E Corporation does not expect to pay any cash2018. For more information on dividends, during the Chapter 11 Cases. (Seesee “Dividends” in Note 10 of the Notes6 to the Condensed Consolidated Financial Statements in Item 1.) Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s wildfire mitigation plan. (See “U.S. District Court Matters and Probation” in Item 1. Legal Proceedings and Item 7. MD&A.)Statements.

Utility Cash Flows

The Utility’s cash flows were as follows:
Three Months Ended March 31,
(in millions)20202019
Net cash provided by operating activities$1,612  $2,274  
Net cash used in investing activities(1,655) (1,247) 
Net cash provided by financing activities476  231  
Net change in cash, cash equivalents and restricted cash$433  $1,258  
 Six Months Ended June 30,
(in millions)2019 2018
Net cash provided by operating activities$2,776
 $2,722
Net cash used in investing activities(2,434) (2,895)
Net cash provided by financing activities1,399
 210
Net change in cash, cash equivalents and restricted cash$1,741
 $37

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.  During the sixthree months ended June 30, 2019,March 31, 2020, net cash provided by operating activities increaseddecreased by $54$662 million compared to the same period in 2018.2019.  This increasedecrease was due to an increase in vendor payments in 2020 that were not paid during the first quarter of 2019 due to the automatic stay as of the Petition Date, and a reduction in interest paidcash receipts from customers as a result of $368 million, offset by an increase in amounts paid for reorganization items, and enhanced and accelerated inspections and repairsthe economic impacts of transmission and distribution assets in 2019, with no similar payments in 2018.the COVID-19 pandemic.



The Utility will continue to operate its business as a debtor in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. Future cash flow from operating activities will be affected by various ongoing activities, including:

•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 “Enforcement and Litigation Matters” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part II, Item 1. Legal Proceedings for more information);

•the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects with spending reductions and the ability of the Utility to recover any losses incurred in connection with COVID-19 through cost recovery, as well as the impact of COVID-19 on the availability or cost of financing;

•the timing and amount of substantially increasing costs in connection with the 2019 and 2020 Wildfire Mitigation Plans that are not currently being recovered in rates (see “Regulatory Matters” below for more information);

•the timing and amount of premium payments related to wildfire insurance (see “Wildfire Insurance” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information); and

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

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

The Utility had material obligations outstanding as of the Petition Date, including claims related to the 2018 Camp fire and 2017 Northern California wildfires. Any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Future cash flows will be materially impacted by the timing and outcome of the Chapter 11 Cases.

Investing Activities

Net cash used in investing activities decreasedincreased by $461$408 million during the sixthree months ended June 30, 2019March 31, 2020 as compared to the same period in 2018.2019. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers.  Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

The Utility’sCash paid by the Utility for capital expenditures werewas approximately $6.5$6.3 billion in 2018.2019. Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur approximately $7.1$7.5 billion in capital expenditures in 2019, and $7 billion in 2020.

Financing Activities

Net cash provided by financing activities increased by $1.2 billion$245 million during the sixthree months ended June 30, 2019March 31, 2020 as compared to the same period in 2018.2019.  This increase was primarily due to $1.5 billionan additional $150 million of borrowings under the DIP Initial Term Loan FacilityFacilities and an approximately $90 million reduction in amounts paid for DIP credit facility debt issuance costs in 2020 as compared to 2019. Additionally, the Utility paid $30 million in bridge facility financing fees in 2020, with no similar amount in 2019.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. 

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 20182019 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”

U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on 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 imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the 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 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 has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

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Upon the court’s request, on March 2, 2020, the Utility provided to the court its target number of contract tree trimmers for 2020, information regarding the Utility’s 2019 inspections of Tower 009/081 on the Cresta-Rio Oso 230 kV Transmission Line (the “Cresta-Rio Oso Line”), information regarding the relationship between priority codes set forth in the Utility’s Electric Transmission Preventive Maintenance Manual and the safety factors specified in General Order 95 promulgated by the CPUC, as well as the application of each to the C-hooks of interest on the Cresta-Rio Oso Line. In addition, on April 2, 2020, the Utility submitted a report to the court regarding the Utility’s March 19, 2020 collection of equipment from the Cresta-Rio Oso Line. On April 10, 2020, the TCC in the Utility’s Chapter 11 bankruptcy case and estimation proceedings filed a declaration from a TCC expert concerning Cresta-Rio Oso 230kV Transmission Line evidence collection and removal on March 19, 2020.

On April 29, 2020, the court issued an order imposing new conditions of probation that would require the Utility, among other things, to:

•employ, on its own payroll, “a sufficient number of inspectors to manage the outsourced tree-trimming work,” including pre-inspectors to “identify trees and limbs in violation of California clearance laws that require trimming” and post-inspectors to “spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed,” and submit a detailed plan to carry out this requirement by May 28, 2020;

•“keep records identifying the age of every item of equipment on every transmission tower and line,” ensuring that “every part [has] a recorded date of installation” and “[i]f the age of a part is unknown, [] conduct research and estimate the year of installation;”

•“[i]n consultation with the monitor, [] design a new inspection system for assessing every item of equipment on all transmission towers,” using forms that are “precise enough to track what inspectors actually do, such as whether they touch or tug on equipment,” take videos of every inspection, and “submit plans for its new inspection system to the [court] for approval by May 28[, 2020];” and

•“require all contractors performing such inspections to carry insurance sufficient to cover losses suffered by the public should their inspections be deficient and thereby start a wildfire.”

The order noted that the court will be flexible in approving any protocols submitted by May 28, 2020, that achieve the essence of the newly imposed conditions of probation if the CPUC, the federal monitor, and the Utility unanimously recommend such protocols. While the Utility is in the early stages of analyzing the proposed probation conditions, such conditions, if implemented, could have a material effect on the Utility’s financial condition, results of operations, liquidity and cash flows.

For more information on the Utility’s probation, see the 2019 Form 10-K.

The Utility expects to continue receiving additional orders from the court in the future.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies.  The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the 20182019 Form 10-K.

Rate Cases

Application for Wildfire Mitigation and Catastrophic Events Interim Rates

On February 7, 2020, the Utility filed an interim relief application seeking $899 million in interim rates related to certain electric distribution costs recorded in the following memorandum accounts: WMPMA, FRMMA, FHPMA, and CEMA. The costs pertain mainly to the years 2017-2019. The application addresses costs recorded in: (i) the WMPMA and FRMMA to comply with the 2019 WMP and other wildfire mitigation costs not otherwise recoverable through rates, (ii) the FHPMA to comply with various fire safety rulemakings through 2019, and (iii) the CEMA for responding to, and restoring customer service after, certain storms and fires occurring in 2019.

The Utility submitted a request on March 23, 2020, to reduce the interim rate relief by $8.4 million to the proposed revenue requirement. This reduction, which reduces the requested rate relief to $891 million, relates to the capital cost reduction required by Assembly Bill 1054.
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The Utility is unable to predict the timing and outcome of this application.

For additional information, see the 2019 Form 10-K.

Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account

On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or sought to be authorized in rates in the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA. The Utility has proposed a schedule for the proceeding that requests a final decision by the end of 2020 and costs to be recovered in 2021.

The Utility is unable to predict the timing and outcome of this application.

Application for a Waiver of the Capital Structure Condition

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 submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019.  The waiver is subject to CPUC approval.

On April 30, 2019,February 27, 2020, the Utility filed a pleading to notify the CPUC heldof an additional decline in its equity ratio to approximately 20.4%, based on information reported in its 2019 Form 10-K, primarily related to non-cash charges related to the 2018 Camp fire and the 2017 Northern California wildfires.

A Proposed Decision was issued on April 1, 2020. If approved, the Proposed Decision would grant the Utility’s request for a prehearing conference, andwaiver. A final decision is expected to be voted out on May 29,7, 2020.

For additional information, see the 2019 the CPUC issued a scoping memo and ruling on issues for briefing.  On July 15, 2019, the ALJ approved briefing dates in August and September of 2019.  No evidentiary hearings are scheduled.  The Utility is unable to predict the timing and outcome of its waiver application.Form 10-K.

2020 Cost of Capital Proceeding

On April 22,December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020, as compared to 12% requested by the Utility. The Utility’s annual cost of capital adjustment mechanism also remains unchanged. The cost of capital adjustment mechanism can trigger changes in the Utility’s authorized ROE and cost of debt, if the 12-month average Moody’s Baa bond rate for the period ending September 30, 2020 were to be 100 basis points higher or lower than 4.5 percent (the benchmark). The adjustment to i) ROE would be one-half the basis point change in the bond rate from the benchmark, and ii) authorized bond costs would be updated. The decision maintains the common equity component of the Utility’s capital structure at 52%, as requested by the Utility, filed an application withand reduces its preferred stock component from 1% to 0.5%, also as requested by the Utility. The decision also approves the cost of debt requested by the Utility. On April 20, 2020, the CPUC requestingalso issued a proposed decision in the OII to consider PG&E Corporation’s and the Utility’s Plan of Reorganization that, if approved, would direct the Utility to update its authorized cost of debt.

For additional information, see the 2019 Form 10-K.

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2017 General Rate Case

As previously disclosed, as a result of the Tax Act, on October 17, 2019, the CPUC authorizeapproved the Utility's capital structureUtility’s advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $282 million reduction to the 2018 revenue requirement and a $291 million reduction to the 2019 revenue requirement. The Utility incorporated these revenue requirement reductions into rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2020.  In its application,2020 and later in 2020 will incorporate other anticipated changes, such as the Utility requested thatchange in revenue requirement resulting from the CPUC approve2020 GRC phase one decision. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s proposed capital structure (i.e., the relative weightings of common equity, preferred equity, and debt), as well as the proposed return on equity, proposed cost of preferred stock, and proposed cost of debt. The Utility requested a 16% rate of return on equity for 2020, which reflected, among other things, the wildfire-related challenges that the Utility was facing.  The Utility also proposed to amend its cost of capital application with an updated cost of capital if the CPUC or the California legislature implemented actions to materially reduce the challenges that investor-owned utilities face in California in connection with the extreme wildfire risk.

AB 1054, enacted on July 12, 2019, provides for the establishmentcalculation of the Wildfire Fund that willrelated revenue requirement. It is uncertain when the IRS guidance may be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12,issued.

For additional information, see the 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. On July 23,Form 10-K.

2020 General Rate Case

As previously disclosed, on December 20, 2019, the Utility notifiedtogether with the Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA), TURN, CUE, the CPUC’s Office of the Safety Advocate, the National Diversity Coalition, the Center for Accessible Technology, the Small Business Utility Advocates, and California City County Street Light Association filed a motion with the CPUC seeking approval of its election to participatea settlement agreement that resolves all of the issues raised by these parties in the Wildfire Fund. The Utility’s participation in the Wildfire Fund is subject to the conditions and limitations set forth in AB 1054 and approval by the Bankruptcy Court.2020 GRC.

As a result of the expected effects of AB 1054settlement agreement and based on the Utility’s wildfire-related risk profile, on August 1, 2019, in a supplemental cost of capital testimony,other facts and circumstances known to PG&E Corporation and the Utility proposed to revise its rateas of return on equity to 12%.

The following table compares the revenue requirement amounts currently authorized in the Utility’s 2015 GT&S rate casedate of this filing, PG&E Corporation and the 2017 GRC, with those requestedUtility expect to remain on track to satisfy the rate base conditions included in the Utility’s 2020 cost of capital application, as updated by the Utility’s August 1, 2019 testimony to reflect a revised rate of return on equity:
 2019 Currently Authorized 2020 Requested (as revised)
 Cost Capital Structure Weighted Cost Cost Capital Structure Weighted Cost
Return on common equity10.25% 52.00% 5.33% 12.00% 52.00% 6.24%
Preferred stock5.60% 1.00% 0.06% 5.52% 0.50% 0.03%
Long-term debt4.89% 47.00% 2.30% 5.16% 47.50% 2.45%
Weighted average cost of capital    7.69%     8.72%



The proposed cost of capital and capital structure will be essential for the Utility to attract new investment capital to upgrade, maintain, and modernize its critical energy infrastructure. The Utility indicated in its application that, over the next four years (2019-2022), the Utility expects to fund up to $28 billion in energy infrastructure investments, including $21 billion in electric and gas safety and reliability and system hardening, $4 billion in new gas pipelines and electric powerlines, $1 billion in power generation, and $2 billion in information technology, equipment and facilities.

The Utility indicated in its supplemental cost of capital testimony that AB 1054 does not directly impact the Utility’s test year 2020 cost of debt. However, the cost of debt will be impacted by the Utility’stheir exit financing as part of its future chapter 11 plan of reorganization. The supplemental cost of capital testimony did not address the Utility’s currently-effective formula rate for electric transmission rates, including the requested return on equity, which is pending at the FERC. The parties in the FERC proceeding are currently involved in settlement negotiations.documents.

The Utility also proposed to file a new cost of capital application with the CPUC on or about the time it emerges from its Chapter 11 proceeding.  The Utility requested in its cost of capital application that the annual cost of capital adjustment mechanism be continued, although its normal operation could be superseded by a new cost of capital application. (The annual cost of capital adjustment mechanism is a tool to modify the cost of long-term debt and cost of equity authorized by the CPUC based on changes in interest rates.) The Utility is unable to predict the timing and outcome of this proceeding.

Revenue Requirements

ForIn accordance with a January 16, 2020 the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $271 million for electric generation and distribution and $74 million gas distribution operations, assuming 2017 authorized rate base amounts.  The revenues for the gas transmission and storage operations would increase by approximately $51 million, assuming 2018 authorized rate base amounts.  However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utilitydecision in its 2019 GT&S Rate CaseOIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and its 2020Reliability Improvements and Revise the GRC both currently pending beforePlan the CPUC, the revenue requirement changes resulting from the Utility’s requested 2020 ROE may differ from the amounts reflected in this cost of capital application.

The following table compares the revenue requirement amounts currently authorized in the Utility’s 2015 GT&S rate case and the 2017 GRC, with those requested in the Utility’s 2020 cost of capital application, as updated to reflect a revised rate of return on equity submitted to the CPUC on August 1, 2019:
Revenue Requirement
(in millions)
Authorized in 2017 GRC and 2015 GT&S Requested in 2020 Cost of Capital Application (as revised)
Electric generation and distribution$6,266
 $6,537
Gas distribution1,739
 1,813
Gas transmission and storage$1,269
 $1,320

As disclosed in “Application for a Waiver of the Capital Structure Condition”above, due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, on February 28, 2019, the Utility submitted to the CPUC an application for a waiver of the capital structure condition.  The 2020 cost of capital application does not modify that request.

On July 2, 2019, the assigned Commissioner issued a scoping memo and ruling that, among other things, consolidated the Utility’s proceeding with the 2020 cost of capital applications submitted to the CPUC by Southern California Edison Company, San Diego Gas & Electric Company, and Southern California Gas Company.  The scoping memo also identified the issues to be addressed within the proceeding and its schedule. On July 15, 2019, the assigned ALJ also issued a ruling directing the Utility and the other Applicants to submit supplemental testimony regarding AB 1054’s impact on financial risks and other issues within the scope of this proceeding by August 1, 2019. According to the current schedule, rebuttal testimony is due August 16, 2019, and additional rebuttal on testimony regarding the passage of AB 1054 is due August 21, 2019. A proposed decision, would be issued on November 15, 2019. A final decision would be issued no sooner than 30 days after the proposed decision.  The Utility is unable to predict the timing and outcome of this proceeding.



2017 General Rate Case

On May 11, 2017, the CPUC issued a final decision in the Utility’s 2017 GRC, which determined the annual amount of base revenues (or “revenue requirements”) that the Utility is authorized to collect from customers from 2017 through 2019 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. The final decision approved, with certain modifications, the settlement agreement that the Utility, PAO, TURN, and 12 other intervening parties jointly submitted to the CPUC on August 3, 2016. Consistent with the amounts proposed in the settlement agreement, the final decision approved a revenue requirement increase of $88 million for 2017, with additional increases of $444 million in 2018 and $361 million in 2019.

On September 24, 2018, the CPUC approved the Utility’s advice letter proposal to make a one-time reduction to revenues by approximately $21 million. This advice letter was directed by an ALJ ruling in response to the Utility’s $300 million expense reduction announcement in January 2017.

Also, as a result of the Tax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the CPUC’s final decision in the 2017 GRC. The PFM, if adopted, would reduce revenue requirements by $267 million and $296 million for 2018 and 2019 respectively, and increase rate base by $199 million and $425 million for 2018 and 2019, respectively. On July 12, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements.  There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter period of time developed in collaboration with the Energy Division. The earliest the CPUC can consider this matter is on August 15, 2019. The Utility cannot predict the timing and outcome of this matter.

The Utility provided an update of the cost effectiveness study for the SmartMeterTM Upgrade project to the CPUC on July 10, 2017. On July 11, 2019, the CPUC further extended the statutory deadline for the 2017 GRC to February 9, 2020, in order to allow for comments and CPUC action on a PD on the SmartMeterTM upgrade cost effectiveness study.  The Utility cannot predict the timing and outcome of any CPUC action in connection with this study.

For more information, see the 2018 Form 10-K.

2020 General Rate Case

On December 13, 2018, the Utility filed its 2020 GRC application with the CPUC. In the 2020 GRC, the Utility has requested that the CPUC determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers from 2020 through 2022 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s request also reflects an updated capital forecast for 2018 and 2019. The 2020 GRC application also includes recorded costs for 2017 and updated forecasts for the proposed mitigations for the period 2018 through 2022 for the Utility’s top safety-related risks as presented in the Utility’s November 2017 Risk Assessment Mitigation Phase report.

For 2020, the Utility has requested base revenues of $9.6 billion, an increase of $1.1 billion, or 12.4%, as compared to authorized base revenues for 2019. The requested weighted average rate base for 2020 is approximately $30 billion, which corresponds to an increase of $2.7 billion over the 2019 authorized rate base of $27.3 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized revenues in 2021 and 2022 by $454 million and $486 million, respectively. Over the 2020-2022 GRC period, the Utility plans to make average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution and electric generation infrastructure, and to improve safety, reliability, and customer service.
Line of Business:
(in millions)
Amounts Requested in the GRC Application 
Amounts Currently Authorized for 2019 (1)
 Increase (Decrease) to 2019 Authorized Amounts
Electric distribution$5,113
 $4,364
 $749
Gas distribution2,097
 1,963
 134
Electric generation2,366
 2,191
 175
Total revenue requirements$9,576
 $8,518
 $1,058
      
(1) These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.



Cost Category:
(in millions)
Amounts Requested in the GRC Application 
Amounts Currently Authorized for 2019 (1)
 Increase (Decrease) to 2019 Authorized Amounts
Operations and maintenance$2,156
 $1,946
 $210
Customer services319
 338
 (19)
Administrative and general1,315
 953
 361
Less: Revenue credits(196) (152) (44)
Franchise fees, taxes other than income, and other adjustments236
 181
 55
Depreciation, return, and income taxes5,747
 5,252
 495
Total revenue requirements$9,576
 $8,518
 $1,058
      
(1) These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.
(2) These amounts may appear not to tie due to small rounding differences.

Revenue requirement driversIncrease to 2019 Authorized Amounts
Community Wildfire Safety Program6.8%
Liability insurance (1)
3.2%
Core gas and electric operations2.4%
Total proposed revenue requirement increase12.4%
(1) The Utility’s GRC forecast indicates that future liability insurance premium costs will be approximately $355 million in 2020

Among other things, the Utility proposed to invest a total of approximately $5 billion (including approximately $3 billion for capital expenditures) between 2018 and 2022 on CWSP measures. Through this program, the Utility proposes to bolster wildfire prevention, risk monitoring, emergency response efforts, and add new and enhanced safety measures, increase vegetation management and harden its electric system to help further reduce wildfire risks.

In addition, the Utility requested authorization to establish several new balancing accounts, including:

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

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.

This GRC proposal did not request funding for potential lawsuits or claims resulting from the 2018 Camp fire and 2017 Northern California wildfires. Also, the Utility is not seeking recovery of compensation of PG&E Corporation’s and the Utility’s officers. In addition, the Chapter 11 Cases may require a change to the scope of work that the Utility proposes to accomplish in the 2020 GRC period. The Utility also may seek or may be required to update the scope of work for the 2019 Wildfire Safety Plan that was approved byfile with the CPUC on June 4, 2019.30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

In its application, the Utility requests that the CPUC issue a final decision by March 2020 and that the 2020 GRC rates be effective January 1, 2020. On March 8, 2019, the CPUC issued a ruling addressing the schedule and scope of the 2020 GRC. The ruling indicates a proposed decision will be issued in the first quarter of 2020.

On June 28, 2019, PAO submitted testimony recommending that the CPUC authorize a 2020 GRC revenue requirement of $503 million, or 5.91%, higher thanFor additional information, see the 2019 authorized level. PAO also recommended establishing a one-way balancing account for the Utility’s revenue requirement during the rate case term (2020 to 2022).Form 10-K.



2015 Gas Transmission and Storage Rate Case

InAs previously disclosed, in its final decisions in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The Utility would be required to take a charge in the future if the CPUC’s audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The Utility cannot predict the timing and outcome of the audit.

As previously disclosed, as a result of the Tax Act, on March 30, 2018,October 17, 2019, the Utility submittedCPUC approved the Utility’s advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the CPUC a PFM of2018 revenue requirement. The Utility incorporated the CPUC’s final decision in the 2015 GT&S rate case proposing to reduce revenue requirements by $58 million and increase rate base by $12 million for 2018 (excluding the impacts of an approximately $7 million increase in revenue requirement and a $60 million increase in rate base associated with the Utility’s private letter ruling advice letter approved by the CPUCreduction into rates beginning January 1, 2020. The IRS is expected to provide additional guidance on July 18, 2018). On July 15, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements.  There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter periodmethod. This IRS guidance may impact the Utility’s calculation of time developed in collaboration with the Energy Division. The earliest a final decision couldrelated revenue requirement. It is uncertain when the IRS guidance may be voted is on August 15, 2019. The Utility cannot predict the timing and outcome of this matter.issued.

For moreadditional information, see the 20182019 Form 10-K.

2019 Gas Transmission and Storage Rate Case

On November 17, 2017,As previously disclosed, on September 12, 2019, the Utility filed itsCPUC voted out the final decision in the 2019 GT&S rate case application withof the Utility. By approving the decision, the CPUC for the years 2019 through 2021. The Utility also provided a revenue requirement and rates for 2022, in the event the CPUC adopts an additional year. On October 1, 2018, the Utility entered into a stipulation with PAO that, if approved, would extend the rate case cycle through 2022 as recommended by PAO.

In its application, the Utility requested that the CPUC authorizeadopted a 2019 revenue requirement of $1.59 billion to recover anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2019. This corresponds to an increase of $289 million over the Utility’s 2018 authorized revenue requirement of $1.30 billion. The Utility’s request also proposed revenue requirements of $1.73 billion for 2020, $1.91 billion for 2021, and $1.91 billion for 2022 if the CPUC orders a fourth year for the rate case period.

The Utility subsequently revised its forecast revenue requirement as a result of the Tax Act and other forecast updates, including significant reductions in the areas of gas storage facilities and gas system operations programs. The revised revenue requirements are as follows: $1.48 billion for 2019, $1.59 billion for 2020, $1.69 billion for 2021, and $1.68 billion for 2022. The revised 2019 requested revenue requirement corresponds to an increase of $184 million over the Utility’s 2018 authorized revenue requirement.

The requested rate base for 2019 is $4.75 billion, which corresponds to an increase of $1.04 billion over the 2018 adopted rate base of $3.71 billion. The Utility’s request is based on capital expenditure forecasts of $829 million for 2019, $872 million for 2020, and $830 million for 2021 (which exclude common capital allocations). The requested rate base amounts exclude approximately $576 million of capital spending subject to audit by the CPUC related to 2011 through 2014 expenditures in excess of amounts adopted in the 2011 GT&S rate case. The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be approved by the CPUC and included in the Utility’s future rate base.

The requested increase in revenue requirement is largely attributable to increased infrastructure investment and costs related to new natural gas storage safety and environmental regulations issued by DOGGR, the Pipeline and Hazardous Materials Safety Administration, and the CPUC.

In response to the Utility’s application, parties proposed various forecast reductions. For example, the PAO recommended a 2019 revenue requirement of $1.35 billion, an increase of $45 million over 2018 adopted amounts. TURN proposed widespread reductions in forecast costs and recommended capital and expense disallowances of more than $500 million.



A second phase of the proceeding addressed the removal of officer compensation costs from the revenue requirement, which is required by SB 901. On March 1, 2019, the Utility, PAO and TURN submitted a joint stipulation to the CPUC proposing to reduce the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $455,000 for total operating expenses and capital expenditures of $617 million and $829 million, respectively.

In this case, the CPUC will authorize the revenue requirement that the Utility will collect through rates to recover its anticipated costs of providing natural gas transmission and storage services from 2019 through 2021, or 2022, in the event the CPUC adopts an additional year.

On July 16, 2019, the assigned ALJ issued a PD in the Utility’s 2019 GT&S rate case pending at the CPUC. The PD proposes a 2019 revenue requirement of $1.327$1.332 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $27$31 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The PDCPUC also proposesadopted revenue requirements of $1.427$1.432 billion for 2020, and $1.511$1.516 billion for 2021, and $1.580 billion for 2022, compared to the Utility’s request of $1.595 billion for 2020, and $1.693 million for 2021. The PD also proposes a revenue requirement of $1.575 billion for 2022, compared to the Utility’s request of2021, and $1.679 billion for 2022. The proposed revenue requirement for 2022 allows for
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As previously disclosed, on January 16, 2020, the possible combinationCPUC approved a final decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, as a result of which the Utility’s 2023Utility will be required to combine the GRC and GT&S rate cases.

The revenue requirement amounts requested bycases starting with the 2023 GRC. In accordance with the decision, on June 30, 2021, the Utility and the revenue requirement amounts in the PD are set forth in the following table:
Revenue Requirement
(in millions)

2018 Currently Authorized 2019 2020 2021 2022
Utility’s Request$1,301
 $1,485
 $1,595
 $1,693
 $1,679
PD$1,301
 $1,327
 $1,427
 $1,511
 $1,575

The PD proposesis required to remove from rate base of $304 million of pipeline replacement capital expenditures for the 2016-2018 period due to cost overruns. Incorporating this reduction, the PD proposes a rate base for 2019 of $4.46 billion, which corresponds to an increase of $0.75 billion over the 2018 adopted rate base of $3.71 billion. This is compared to the Utility’s rate base request of $4.75 billion for 2019.

The PD proposes a rate base of $4.98 billion for 2020, $5.37 billion for 2021, and $5.71 billion for 2021. The rate base amounts also exclude approximately $576 million of capital spending subject to audit byfile with the CPUC related to 2011 through 2014 expenditures in excess of amounts adopted in the 2011a single “general rate case” application requesting integrated GRC and GT&S rate case pursuant to the 2015 GT&S rate case decision. The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be approved by the CPUCrelated revenue requirements for test year 2023 and included in the Utility’s future rate base.three attrition years.

The PD proposes the adoption of the Utility’s proposed Natural Gas Storage Strategy, with minor modifications related to the decommissioning or sale of the Utility’s Los Medanos and Pleasant Creek storage fields, and adopts a two-way balancing account for storage costs, which will be subject to a reasonableness review in the next GT&S rate case. The PD proposes to retain the one-way balancing account for transmission integrity management, and to adopt a number of new, one-way balancing accounts covering other operational areas.

If adopted, the PD also would resolve the second phase of the proceeding, which addressed the removal of officer compensation costs from the revenue requirement, which is required by SB 901. The PD proposes adoption of the joint stipulation offered by the Utility, PAO and TURN that reduces the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $0.455 million.

Opening comments on the PD were filed on August 5, 2019. The CPUC may vote on the PD, at the earliest, on August 15, 2019. The Utility is unable to predict the timing and outcome of this proceeding.

For moreadditional information, see the 20182019 Form 10-K.



Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

OnAs previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50 basis point ROE incentive adder for its continued participation in the CAISO. Those rate case decisions were remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion. If FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Alternatively, if FERC again concluded that the Utility should receive the 50 basis point ROE incentive adder and provides the additional explanation that the Ninth Circuit found the FERC’s prior decisions lacked, then the Utility would not owe any refunds for this issue for TO16 or TO17.

On February 28, 2018, the Utility filed a motion to establish procedures on remand requesting a hearing and additional briefing on the issues identified in the Ninth Circuit Court’s opinion. On August 20, 2018, FERC issued an order granting the Utility’s motion to allow for additional briefing. The order also consolidated the TO18 rate case with TO16 and TO17 for this issue. The Utility filed briefs on September 19, 2018 and reply briefs on October 10, 2018. On July 18, 2019, FERC issued its Orderorder on Remandremand reaffirming its prior grant of the Utility’s request for the 50 basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order.

Also as previously disclosed, on September 16, 2019, FERC extended the amount of time it has to consider the request for rehearing by issuing a tolling order for the limited purpose of further consideration of the matters raised in the request. On March 17, 2020, FERC issued its order denying the request for rehearing and re-affirming the Utility’s eligibility to receive the 50 basis point ROE incentive adder. The Utility is unable to predict the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

OnAs previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility is seekingsought a return on equity of 10.9%, which includesincluded an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects.

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and set it for hearing, but held the hearing procedures in abeyance for settlement procedures.  The order set an effective date for rates of March 1, 2017 and made the rates subject to refund following resolution of the case.  On March 17, 2017, the FERC issued an order terminating the settlement procedures due to an impasse in the settlement negotiations reported by the parties.  During the hearings held in January 2018, the Utility, intervenors, and the FERC trial staff, addressed questions relating to returnAlso, as previously disclosed, on equity, capital structure, depreciation rates, capital additions, rate base, operating and maintenance expense, administrative and general expense, and the allocation of common, general and intangible costs.

Additionally, on March 31, 2017, intervenors in the TO18 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO18 rate case. On November 16, 2017, the FERC dismissed the complaint. On December 18, 2017, the complainants filed a request for a rehearing of that order, which the FERC denied on May 17, 2018.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.83%2.96% compared to the Utility’s request of 3.25%. The ALJ also rejected the Utility’s method of allocating common plant between CPUC and FERC jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility’s rate base and revenue requirement. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s recommendations. Theinitial decision.

Once the FERC issues its decision, the Utility expects FERC to issue a decision in late-2019, but expects one or more parties to seek rehearing of that decision and then appeal it to the courts. The Utility is unable to predict the timing and outcome of when a final decision will be issued.this proceeding.

For additional information, see the 2019 Form 10-K.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

OnAs previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 iswas $6.9 billion.  The Utility is seekingsought an ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion.  On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 filing, subject to hearing and refund, and established March 1, 2018,

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Also, as the effective date for rate changes.  FERC also ordered that the hearings be held in abeyance pending settlement discussion among the parties. On May 14, 2018, the Utility filed a proposal to reflect the impact of the Tax Actpreviously disclosed, on its TO tariff rates effective March 1, 2018, in the resolution of the TO19 rate case. The tax impact reduces the TO19 requested revenue requirement from $1.79 billion to $1.66 billion.



On September 29, 2017, intervenors in the TO19 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO19 rate case. On October 17, 2017, the Utility requested that the FERC dismiss the complaint. On May 17, 2018, the FERC issued an order setting the complaint for hearing, settlement judge procedures, and consolidation with the TO19 proceeding.

On September 21, 2018, the Utility filed an all-party settlement with the FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, unappealablenon-appealable TO18 decision. Additionally, if the FERC determinedwere to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. On December 20, 2018, the FERC issued an order approving the all-party settlement. Additionally, on July 18, 2019, the FERC issued an Orderorder on Remandremand reaffirming its grant of the Utility’s request for the 50 basis point incentive adder for continued CAISO participation. On September 30, 2019, the FERC issued an order on rehearing that denied a pending request for rehearing of the FERC’s decision granting the 50 basis point ROE adder in the TO19 proceeding.

For additional information, see the 2019 Form 10-K.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

OnAs previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case at FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the effective date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. The Utility is unable to predict the timing and outcome of settlement discussions.

The formula rate replaces the “stated rate” methodology that the Utility used in its previous TO rate case filings. The formula rate methodology still includes an authorized revenue requirement and rate base for a given year, but it also provides for an annual update of the following year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenues, including Construction Work in Progress,revenue requirements will be updated to the actual cost of service annually.annually as part of the true-up process. Differences between amounts collected and determined under the formula rate will be either collected from or refunded to customers.

In the filing, the Utility forecasts a 2019 retail electric transmission revenue requirement of $1.96 billion. The proposed amount reflects an approximately 9.5% increase over the as-filed TO19 requested revenue requirement of $1.79 billion (a subsequent reduction to $1.66 billion was identified as a result of the Tax Act). The Utility forecasts that it will make investments of approximately $1.1 billion and $0.7 billion for 2018 and 2019, respectively, for various capital projects to be placed in service before the end of 2019. Including projects to be placed in service beyond 2019, the Utility forecasts total electric transmission capital expenditures of $1.4 billion in 2018 and $1.4 billion in 2019. The Utility’s forecasted rate base for 2019 is approximately $8 billion on a weighted average basis, compared to the Utility’s forecasted rate base of $6.9 billion in 2018. The Utility has requested that FERC approve a 12.5% return on equity (which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO), an increase from the 10.75% (also inclusive of a 50 basis point CAISO incentive adder) requested in its TO19 rate case. The parties conducted aseveral settlement conference onconferences throughout 2019.On March 14 to 15, 2019 and on June 13 to 14, 2019. The next settlement conference is scheduled for August 13 to 14, 2019.

On May 9, 2019,31, 2020, the Utility filed an applicationa partial settlement with FERC that resolves issues regarding the FERC requesting revisions to its TO20 rate caseinputs, and methods used in the formula rate modelconsistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to remove the impact of this non-cash charge on the ratio of common equity to total capital. The Utility indicates in its application that, because of the recording of the non-cash wildfire-related charges in connection with the 2017 Northern California wildfires and the 2018 Camp fire, the Utility’s financial statements reflected a ratio of common equity to total capital of approximately 41% as of December 31, 2018. The Utility indicates that the proposed revisions adjust the equity ratio to accurately reflect how the Utility financed thereview transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in rate base. The Utility’s currentTO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base was financed with an equity ratio of approximately 52%, rather than the 41% equity ratio. In addition, on May 9, 2019,CAISO register data base; and requires the Utility submitted a request to theseek FERC authorization before recovering claims related to exclude the Wildfire Charge from the Utility’s capital structure for the purpose of calculating its Allowance for Funds Used During Construction (AFUDC) effective January 1, 2019.

On July 10, 2019, the FERC accepted the Utility’s revisions to the formula rate to become effective December 9, 2019, subject to refund,2017 and established hearing and settlement judge procedures.

2018 fires. The Utility expectsis unable to file an annual update to its TO tariff on or before December 1predict the timing and outcome of each year beginning in December 2019, for rates and charges to become effective January 1 of the following year, consistent with the formula rate.this proceeding.

For moreadditional information, on the TO rate cases, see the 20182019 Form 10-K.



Nuclear Decommissioning Cost Triennial Proceeding

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

OnAs previously disclosed, on December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion which represents a total cost estimate to decommission the Diablo Canyon facilities.

On February 14, 2019,Also, as previously disclosed, on January 10, 2020, the CPUC issued a scoping memo authorizing addressingsettlement agreement that the scope of the NDCTP Proceeding to include reasonableness reviews of the Diablo Canyon decommissioning cost estimates, ratemaking proposals, proposed Diablo Canyon milestone framework, plans to address host community needs, reasonableness of Humboldt Bay Power Plant decommissioning costs, and reasonableness of preforming Diablo Canyon planning activities pre-shutdown including the proposed rate of recovery of these pre-planning activities addressed in Application 18-07-013.

On March 7, 2019, the CPUC amended the scoping memo to combine A.18-07-013, which seeks authorization for the Utility to establish the Diablo Canyon Decommissioning Memorandum Account to track funding for Diablo Canyon pre-shutdown decommissioning planning activities with the NDCTP A.18-12-008. The CPUC approved the Utility to establish an interim mechanism to track decommissioning planning activity expenses in the Diablo Canyon Decommissioning Memorandum Account. Any Memorandum Account recovery of such expenses is subject to the authorization and approval of the CPUC which will be discussed in this year’s NDCTP Proceeding. The CPUC will hold a public participation hearing for residents and organizations in and near San Luis Obispo to give their perspective and input to the CPUC about the Utility’s request to track costs of Diablo Canyon Decommissioning Planning Activities. The public participation hearing is scheduled for August 7 to 8, 2019.

On July 15, 2019, intervenorsparties had reached in this proceeding submitted their testimonies. Rebuttal Testimony is due August 15, 2019.was filed with the CPUC, along with a joint motion for adoption of settlement agreement.

TheUnder the proposed settlement agreement, the Utility seeks towould collect $383.7annual revenue requirements of $112.5 million and $3.9 million for the funding of the Diablo Canyon tax qualifiednon-qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, under the Utility seeks cost recovery of pre-planning activities commencing January 1, 2020, of $30 million for the 3-year period 2020 to 2022 and a $44 million revenue requirements for the 2-year period 2023 to 2024; by an annual expense only balancing account. The Utility is also defending the reasonableness and prudence ofproposed settlement agreement, the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to date.date would be deemed reasonable.

Wildfire Expense Memorandum AccountThe Utility is unable to determine the timing and outcome of this proceeding.

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For additional information, see the 2019 Form 10-K.

Petition for Modification of CPUC Decision Approving Retirement of Diablo Canyon Power Plant

On June 21,20, 2016, the Utility entered into a joint proposal with certain parties, including the Alliance for Nuclear Responsibility, to retire Diablo Canyon’s two nuclear power reactor units at the expiration of their current operating licenses in 2024 and 2025. On January 11, 2018, the CPUC approved the planned retirement by 2024 and 2025, but required legislative authorization for certain key aspects of the joint proposal. On November 29, 2018, in response to SB 1090, the CPUC issued a further decision grantingaddressing the Utility’s requestkey remaining goals of the Diablo Canyon joint proposal agreement.

On October 1, 2019, the Alliance for Nuclear Responsibility filed a PFM of the CPUC’s January 11, 2018 decision approving the planned retirement of Diablo Canyon. The PFM argues that above-market costs attributable to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. InDiablo Canyon under the WEMA, the Utility can record costs related to wildfires, including: (1) payments to satisfy wildfire claims, including any deductibles, co-insurance and other insurance expense paidPower Charge Indifference Adjustment methodology, when combined with decreasing bundled load by the Utility, but excludingcreate material changed circumstances that undermine the reasonableness of incurring costs to operate Diablo Canyon until its retirement. On October 31, 2019, the Utility filed a joint response with Friends of the Earth, Natural Resources Defense Council, CUE, and IBEW Local 1245, which argued that have already been forecastedmodification of the CPUC’s initial decision is not warranted and adoptedis not in the Utility’s GRC; (2) outside legal costs incurred inpublic interest. On February 7, 2020, the defense of wildfire claims; (3) insurance premium costs not in rates;ALJ issued a PD denying the Alliance for Nuclear Responsibility’s PFM. On March 18, 2020, the CPUC approved the PD and (4)closed the cost of financing these amounts.  Insurance proceeds, as well as any payments received from third parties, or through FERC authorized rates, will be credited toproceeding.

For additional information, see the WEMA as they are received.  The WEMA will not include the Utility’s costs for fire response and infrastructure costs which are tracked in the CEMA.  The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. (See Notes 4 and 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)2019 Form 10-K.

As of June 30, 2019, the Condensed Consolidated Financial Statements include long-term regulatory assets of $127 million, consisting of insurance premium costs that are probable of recovery. Should PG&E Corporation and the Utility conclude in future periods that recovery of insurance premiums in excess of amounts included in authorized revenue requirements is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached.



Catastrophic Event Memorandum Account Applications

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. While the Utility believes such costs are recoverable through CEMA, itsThe Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 34 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2019 CEMA Application

On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with thirteen catastrophic events that included twelve wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire. A prehearing conference was held on November 4, 2019 and a scoping memo was issued on December 6, 2019. On March 10, 2020, the Utility filed a Motion for Interim Rate Relief, requesting $135.4 million of interim rates to be recovered starting August 2020. On April 7, 2020, the ALJ granted the Utility’s request to withdraw the motion without prejudice. The Utility may refile it should the 2019 CEMA schedule be delayed. A final decision is expected by the end of 2020.

PG&E Corporation and the Utility are unable to predict the outcome of this overall proceeding.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The 2018 CEMA application originally sought cost recovery of $555 million on a forecast basis, subject to true-up if actual costs were greater or less than the forecast, for additional tree mortality and fire risk mitigation work anticipated in 2018 and 2019. However, on April 25, 2019, the CPUC adopted a decision denying cost recovery on a forecast basis for the 2018 and 2019 costs requested.

On November 2, 2018, the assigned ALJ denied the Utility’s July 25, 2018 motion requesting interim rate relief for $441 million, which represents 75% of the costs incurred in 2016 and 2017 related to storms, wildfires and tree mortality response work. Subsequently, on December 4, 2018, the Utility filed a renewed motion for interim rate relief, due to worsening financial conditions. The renewed motion for interim relief sought approximately $588 million, which represents 100% of the total costs incurred in 2016 and 2017 for the activities referenced above. The Utility requested that cost recovery occur over a one-year period, with the amounts collected to be subject to refund based on the authorized amount in the proceeding. On April 25, 2019, the CPUC authorizedapproved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017)., compared to $588 million requested by the Utility. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On July 1, 2019, the Utility filed a motion requesting approval to: (i) revise the 2018 CEMA testimony and workpapers to exclude forecast costs, (ii) include 2018 recorded tree mortality and fire risk reduction costs, and (iii) assist with the hiring of an independent auditor for the recorded tree mortality costs included in the 2018 CEMA. The assigned Commissioner and ALJs issued three separate rulings on July 31, 2019, granting the Utility’s requests pertaining to the removal of the forecast costs and revisions and the inclusion of 2018 recorded tree mortality costs, and directed the Utility to assist with the hiring of an independent auditor in conjunction with the CPUC Energy Division. On August 7, 2019, the Utility filed a Revised Application, Revised Testimony and Revised Workpapers, reflecting a new revenue requirement request of $669 million. The $669 million, incorporates (i) the removal of forecast tree mortality costs (reduction of approximately $555 million); (ii) inclusion of the 2018 Tree Mortality and Fire Risk Reduction activities (increase of approximately $90.318 million); and (iii) other corrections and updates found since the filing (reduction of approximately $9 million), as comparedpursuant to the Utility’s original request of $1.14 billion.CPUC ruling allowing these changes.

The 2018 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.
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PG&E Corporation
On March 9, 2020, the CPUC issued a modified scoping memo and ruling, requiring the Utility areto file by June 30, 2020 a revised application that would include actual 2019 vegetation management costs and an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.

The Utility is unable to predict the timing and outcome of the overallthis proceeding.

For additional information, see the 2019 Form 10-K.

Fire Hazard Prevention Memorandum Account

The CPUC allows utilities to track and record costs associated with implementing regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. The Utility currently is authorized to tracktracked such costs in the FHPMA through the end of 2019. During 2018,

On December 17, 2019, the Utility, recorded $262the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire. Pursuant to the settlement agreement, the Utility agrees, among other things, to not seek recovery of $36 million of costswildfire-related expenses recorded in the FHPMA. For more information on the settlement agreement, see Note 11 of the Notes to the FHPMA, correspondingCondensed Consolidated Financial Statements.

Other than the amounts subject to vegetation management work performed to complythe settlement agreement, as modified by the Decision Different issued on April 20, 2020, in connection with CPUC Decemberthe OII into the 2017 fire safety regulations. WhileNorthern California Wildfires and the 2018 Camp Fire, the Utility believes such costs are recoverable but rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC.


For the amount recorded to this memorandum account as of March 31, 2020, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

Fire Risk Mitigation Memorandum Account

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized by SB 901 and AB 1054 to capture mitigation costs incurredof activities not included in advance of the CPUC’s approval of the Utility’sa CPUC approved Wildfire Mitigation Plan.  The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Mitigation Plan to record costs of wildfire mitigation activities that were beyond the initial identified scope of work.

WhileOn December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agrees, among other things, not to seek recovery of $236 million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For more information on the settlement agreement, see Note 11 of the Notes to the Condensed Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement, as modified by the Decision Different issued on April 20, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility intends to seek recovery of the FRMMA balance in a future application, which rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Safety PlanWMP recorded in the FRMMA, whichFRMMA.

For the Utility expects will be substantial.amount recorded to this memorandum account as of March 31, 2020, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

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Wildfire Mitigation Plan Memorandum Account

OnAs previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WPMAWMPMA (also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The purpose of the WPMAWMPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation Plan, as required by Public Utilities Code Sections 8386 et seq, as modified by SB 901.901 and subsequent bills including AB 1054, AB 111, SB 70, SB 167, SB 247, and SB 560. The WPMAWMPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. Upon approval ofThe CPUC approved the memorandum account on August 5, 2019, so the Utility will record any costs incurred in implementing an approved Wildfire Mitigation Pan.Plan as of the effective date, June 5, 2019.

TheAlso, as previously disclosed, other than the amounts subject to the settlement agreement, as modified by the Decision Different issued on April 20, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility anticipates that the recovery of the costs recorded to the WPMAWMPMA would occur through a general rate case or future application at which time the CPUC would review the costs for reasonableness as required by SB 901.AB 1054. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire SafetyMitigation Plan recorded in the WPMA,WMPMA, which the Utility expects will be substantial.

For the amount recorded to this memorandum account as of March 31, 2020, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections

In response to the COVID-19 pandemic, on April 16, 2020, the CPUC issued a Resolution ordering utilities to implement a number of emergency customer protections for one year beginning on March 4, 2020:

•waive deposit requirements for residential customers seeking to reestablish service for one year and expedite move in and move out service requests;

•stop estimated usage for billing attributed to the time period when a home/unit was unoccupied as a result of the emergency;

•identify the premises of affected customers whose utility service has been disrupted or degraded, and discontinue billing these premises without assessing a disconnection charge;

•prorate any monthly access charge or minimum charges;

•implement payment plan options for residential customers;

•suspend disconnection for nonpayment and associated fees, waive deposit and late fee requirements for residential customers;

•support low-income residential customers by:

◦freezing all standard and high-usage reviews for the CARE program eligibility for 12 months and potentially longer, as warranted;

◦contacting all community outreach contractors, the community-based organizations that assist in enrolling hard-to-reach low-income customers into CARE, to help better inform customers of these eligibility changes;

◦partnering with the program administrator of the customer funded emergency assistance program for low-income customers and increasing the assistance limit amount for the next 12 months; and

◦indicate how the energy savings assistance program can be deployed to assist customers;

•suspending all CARE and Federal Emergency Relief Administration program removals to avoid unintentional loss of the discounted rate during the period for which the customer is protected under these customer protections;
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•discontinuing generating all recertification and verification requests that require customers to provide their current income information;

•offering repair processing and timing assistance and timely access to utility customers;

•including these customer protections as part of their larger community outreach and public awareness plans;

•meeting and conferring with the Community Choice Aggregators as early as possible to discuss their roles and responsibilities for each emergency customer protection.

The Resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the Resolution.

Other Regulatory Proceedings

Application for Post-Emergence Securitization Transaction

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of temporary Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date. Specifically, the application requests administration of the Stress Test Methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are Stress Test Costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application asks that the CPUC proceed with reviewing the Utility’s requests while the Utility is still in Chapter 11 because the CPUC would issue a decision applying the Stress Test only after the Utility emerges from Chapter 11 and because, given the developments in the Chapter 11 proceeding and related Chapter 11 Proceedings OII that have occurred since the CHT decision, the CPUC and other parties now have access to information to assess the Utility’s “financial status” pursuant to the Stress Test. The application also contemplates a customer credit designed to insulate customers from the charge on customer bills associated with the bonds. The Utility proposes to fund the customer credit through a trust that consists of shareholder assets including: (1) an initial contribution of $1.8 billion; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; and (3) investment returns on the assets in the trust. The Utility anticipates that this will be sufficient to ensure that the customer credits equal the bond charges over the life of the bonds. The Utility also proposes to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

The foregoing description of anticipated post-emergence securitization transaction includes “forward-looking statements” within the meaning of Section 27A of the Securities Act, including statements about the expected sources and uses of funding, expected financing transactions (including the potential securitization) and projected balances of assets and liabilities (including cash on hand, accrued interest, trade payables and other amounts). This description reflects PG&E Corporation’s and the Utility’s expectations as of the date of this filing and remains subject to change. (See “Forward-Looking Statements” above).

2019 Wildfire SafetyMitigation Plan

OnAs previously disclosed, on October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. This OIR provided guidance on the form and content of the initial wildfire mitigation plans, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of wildfire mitigation plans to be filed in future years. In this proceeding the CPUC will consider,determined, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as whetherwhat additional elements beyond those required in SB 901 should be included in the wildfire mitigation plans. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation’s electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to wildfire mitigation plans, which SB 901 requires to be addressed in separate rate recovery applications.

On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 Wildfire SafetyMitigation Plan”) with the CPUC. The 2019 Wildfire Safety Plan describes forecasted workCPUC, and investments in 2019 that are designed to help further reduce the potential for wildfire ignitions associated with the Utility’s electrical equipment in high fire-threat areas. The 2019 Wildfire Safety Plan specifically addresses wildfire risk factors that occur most frequently and have potential to start or spread a fire. The 2019 Wildfire Safety Plan focusesamended it subsequently on the measures the Utility proposes to take in 2019, but includes longer-term plans, while acknowledging that the Utility may modify these plans based upon new information or conditions as the Utility implements these measures. The new and ongoing safety measures being pursued include:

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;



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 reclosers and circuit breakers in high fire-threat areas with remote control capabilities;

Expanding the Public Safety Power Shutoff Program (PSPS) to include all transmission and distribution lines in Tier 2 and Tier 3 High Fire-Threat District (HFTD) areas;

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.

On February 12, February 14, and April 25, 2019.
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For additional information, see the 2019 Form 10-K.

2020-2022 Wildfire Mitigation Plan

As previously disclosed, on February 7, 2020, the Utility filed amendments topublicly posted its 2020 Wildfire Mitigation Plan and utility survey. The Utility’s 2020 Wildfire Mitigation Plan describes the 2019 Wildfire Safety Plan with the CPUC to correct inadvertent errors in the cost table attached to the 2019 Wildfire Safety Plan; refine language in the 2019 Wildfire Safety Plan; and modify certain 2019 Wildfire Safety Plan targets in light of external conditions, enhance other targets basedUtility’s wildfire safety programs, which are focused on early learnings, and clarify targets to minimizethree key areas: reducing the potential for misinterpretation, respectively.

On May 30, 2019,fires to be started by electrical equipment, reducing the CPUC approved two decisions relatedpotential for fires to spread, and minimizing the Utility’s 2019 Wildfirefrequency, scope and duration of Public Safety Plan. The first decision was specific to the Utility’s plan and generally approved the plan, subject to certain reporting,Power Shut-off events, as well as providing historical data gathering, and other requirements set forth in the decision. The Utility-specific decision did not approve the amendment filedrequested by the Utility on April 25, 2019. The second decision was a guidance decision for all ofguidelines.

On March 18, 2020, the utilities that submitted wildfire mitigation plans. This guidance decision included additional reporting, data gathering, and other requirements and provided that the Utility’s April 25th amendment will be examined in Phase 2 of this proceeding.  On June 14, 2019, the Assigned Commissioner and ALJCPUC issued a decision implementing Phase 2 ofin this proceeding, clarifying that the OIR, announcing Phase 2 workshops to develop metrics and templates to evaluate the Utility’s 2019CPUC’s newly created Wildfire Safety Plan and report data consistently and a processDivision will review 2020 wildfire mitigation plans, present resolutions for submission ofCPUC consideration on the 2020 plans. The decision also announced that the CPUC would evaluate the Utility’s April 25th amendment in Phase 2, as well as the process forPlans, and oversee independent evaluation of the Utility’sand other compliance activity with itsregard to both 2019 plan.and 2020 Plans.

Also, as previously disclosed, PG&E Corporation and the Utility are unableexpect the CPUC to predict the timing and outcome of this proceeding.issue a decision on its 2020-2022 WMP by June 2020. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire SafetyMitigation Plan, and the 2020-2022 Wildfire Mitigation Plan recorded in the FRMMA and WPMA,WMPMA, which the Utility expects will be substantial.

For additional information, see the 2019 Form 10-K.

OIR Regarding Microgrids

As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to Implement Public Utilities Code Section 451.2examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC is seeking to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by Spring or Summer 2020, if not sooner. A decision giving direction for mitigation measures ready for implementation by September 1, 2020 is expected to be voted on by the CPUC as early as June 11, 2020. At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal contains three components for which it is seeking scope and cost recovery authorization of up to approximately $379 million in both expense and capital. On April 1, 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it is seeking to approximately $257 million. The Utility described in its supplemental testimony that it was focusing in 2020 on the use of temporary, mobile generation solutions to power microgrids and that the Utility had suspended its solicitation for permanent generation located at substations with online dates in 2020. The Utility’s supplemental testimony also attached contracts the Utility had executed with mobile generation vendors for over 300 megawatts of capacity for use in 2020. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying on procedural grounds the Utility’s motion to supplement its proposal. On April 29, 2020, the CPUC issued a proposed decision that would conditionally approve the Utility’s proposal and would allow the Utility to track costs in the FRMMA. The proposed decision would require the Utility to seek recovery in a future application, which would require CPUC reasonableness review and authorization in a separate proceeding or through a GRC.

Failure to obtain a substantial or full recovery of costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

For additional information, see the 2019 Form 10-K.

OIR Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901

As previously disclosed, on July 8, 2019, the CPUC issued a decision in the CHT proceeding, which adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or 5% of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
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For additional information, see the 2019 Form 10-K.

OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization

As previously disclosed, on October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications “that will result from the confirmation of a plan of reorganization and other regulatory approvals necessary to resolve” the Chapter 11 Cases (the “Chapter 11 Proceedings OII”).

On January 22, 2020, the Utility entered into a RSA with members of the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility and, consistent with that agreement, on January 23, 2020, the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility filed a motion to withdraw from the proceeding. On January 30, 2020, the ALJ issued a ruling allowing the Ad Hoc Committee of Senior Unsecured Noteholders to withdraw as a party.

On January 31, 2020, parties submitted opening testimony, and on February 21, 2020, parties submitted reply testimony. On February 18, 2020, the Assigned Commissioner issued a ruling that includes proposals for changes to the Utility’s financials and operational structure and a proposed schedule for comments on the proposals. Evidentiary hearings began on February 25, 2020 and concluded on March 4, 2020. On March 13, 2020, parties filed post-hearing opening briefs and comments on the Assigned Commissioner’s February 18, 2020 proposals, and on March 26, 2020, parties filed post-hearing reply briefs and reply comments on the February 18, 2020 proposals.

On April 20, 2020, the assigned ALJ issued a proposed decision in this proceeding. If approved, the proposed decision would approve PG&E Corporation’s and the Utility’s Plan of Reorganization with certain conditions and modifications related to topics, including but not limited to, governance, operational structure, safety performance, and financial condition. Among other things, the proposed decision:

•Board of Directors: provides for certain corporate governance changes, including:

◦a requirement of consultation with the CPUC regarding Board member candidates for at least seven years following emergence from Chapter 11; and

◦a requirement to classify the Boards of Directors into two classes, with directors serving two-year terms (an arrangement that would phase out over time, such that all directors elected in 2024 would be elected to one-year terms).

•Safety and Operational Metrics: does not adopt or approve specific safety and operational metrics for the Utility, but directs that such metrics would be developed in a future CPUC proceeding;

•Penalties: directs the Utility to ensure that its Plan of Reorganization provides that “neither confirmation nor consummation of the plan shall affect any pending or future Commission proceeding or investigation, including any adjudication or disposition thereof, and any liability of the Debtors or Reorganized Debtors, as applicable, arising therefrom shall not be discharged, waived, or released,” which could relate to a potential CPUC investigation or proceeding regarding the 2019 Kincade fire;

•Regional Restructuring: orders the Utility to file by June 30, 2020 an application for approval of a regional restructuring plan;

•Enhanced Enforcement Process: adopts an Enhanced Oversight and Enforcement Process for the Utility;

•Financial Issues: authorizes the Utility to issue debt consistent with its Plan of Reorganization and to update its authorized cost of debt, finding that recovery of the Utility’s estimated $154 million in financing-related costs is consistent with AB 1054’s “neutral, on average, to ratepayers” requirement, subject to the condition that the Utility demonstrate they are “neutral, on average” when it requests rate recovery;

•Capital Structure: grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure;

•Earnings Adjustment Mechanism: does not adopt an earnings adjustment mechanism;

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•Executive Compensation: imposes certain requirements regarding executive compensation, including:

◦a presumption that a material portion of executive incentive compensation shall be withheld if the Utility’s equipment is determined to be the ignition source of a catastrophic wildfire; and

◦a requirement to maintain policies that include provisions that limit or cancel severance payments for executives in the event of certain felony criminal convictions on the part of the Utility.

•Structural Proposals: declines to adopt a moratorium on considering proposals for potential changes to the Utility’s corporate structure and authorizations to operate as a utility, however, the proposed decision states that:

◦separating the Utility “into gas and electric utilities or selling the gas assets … is less of a priority today;”

◦the Enhanced Oversight and Enforcement Process supersedes prior proposals to establish periodic review of the Utility’s certificate of public convenience and necessity; and

◦the existing holding company structure is left in place.

Comments on the ALJ’s proposed decision are due May 11, 2020 and reply comments are due May 18, 2020. A final decision is expected in May 2020.

For additional information, see the 2019 Form 10-K.

Wildfire Fund Non-Bypassable Charge

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of a non-bypassable charge to support the Wildfire Fund.  On October 24, 2019, the CPUC issued a final decision finding that the imposition of the non-bypassable charge is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the investor-owned utilities as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision proposes revenue requirements for the Utility of $404.6 million, which is based on average annual collections and shall expire at the end of the year 2035.

On November 25, 2019, an individual intervenor filed an application for rehearing of the decision arguing that the decision constitutes a constitutional violation of procedural due process and an unjust and unreasonable rate increase. On March 2, 2020, the CPUC issued a decision denying the application for rehearing.

For additional information, see the 2019 Form 10-K.

Transportation Electrification

SB 350 requires the CPUC, in consultation with the CARB and the California Energy Resources Conservation and Development Commission, to direct electrical corporations to file applications for programs and investments to accelerate widespread transportation electrification. In September 2016, the CPUC directed the Utility and the other large IOUs to file transportation electrification applications that include both short-term projects (of up to $20 million in total) and two-to-five year programs with a requested revenue requirement determined by the Utility.

As previously disclosed, on May 31, 2018, the CPUC issued a final decision approving the Utility’s two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters. This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs’ transportation electrification investments, and vehicle-grid integration. A prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the assigned commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding.

For additional information, see the 2019 Form 10-K.
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OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas Planning

On January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the greenhouse gas reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding will examine whether recent industry related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including but not limited to, gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders.

The Utility filed opening comments on the preliminary scope on February 26, 2020 and reply comments on March 12, 2020. The assigned ALJ and assigned commissioner held a prehearing conference on March 24, 2020. The Utility filed a post-prehearing conference Statement on April 1, 2020. On April 23, 2020, the assigned commissioner issued a ruling setting the final scope, schedule and categorization for phase 1 (Tracks 1A and 1B). Initial workshops are scheduled for July 2020.

For additional information, see the 2019 Form 10-K.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings.

On October 24, 2019, the CPUC adopted a final decision on a portion of phase one (Topic 1 and 2), defining climate change adaptation for California’s energy utilities as “adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations.” In addition, this decision provides guidance on what data should be used by the investor-owned utilities to perform all climate impact, climate risk, and climate vulnerability analyses undertaken with respect to their infrastructure assets, operations, and customer impacts. Finally, this decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers.

On October 22, 2019, The CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed utilities to research and develop a new form of risk assessment, a CVA. CVAs instruct utilities to “examine the risks posed by climate change to their core lines of business, including generation, transmission, distribution, and storage, irrespective of who owns the assets.” In addition, the staff proposal provides guidance regarding the data sources used in the CVA, outreach and coordination with the community, and incorporation of CVA findings into RAMP and GRC filings. The Utility provided opening and reply comments on February 18 and March 3, 2020, respectively.

The remaining topics in phase one of this proceeding are still under consideration and will be subject to a separate decision. Those issues include: guidance on how climate adaptation should be incorporated into the investor-owned utilities’ investment plans, program design, and operations and how climate change might affect vulnerable and disadvantaged communities. The CPUC decision on such issues is anticipated no earlier than mid-2020.

OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California.

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8.

On January 30, 2020, the CPUC proposed new guidelines. Parties submitted opening and reply comments on the guidelines on February 19, 2020 and February 26, 2020, respectively.
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On April 27, 2020, the CPUC issued a proposed decision on Phase 2 of the proceeding (relating to PSPS guidelines), which proposes new guidelines, including requiring utilities to complete energy restoration within 24 hours after the end of a PSPS event; to provide back-up generation to critical infrastructure during PSPS events; and to support access and functional needs populations during PSPS events. Comments on the proposed decision are due May 18, 2020.

As discussed above, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The Utility and other entities (including other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. The CPUC’s April 27, 2020, proposed decision did not act on this motion. PG&E Corporation and the Utility are unable to predict the timing and the outcome of this request.

For additional information, see the 2019 Form 10-K.

Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions issued an order to show cause directing the Utility to show cause why it should not be sanctioned for violations of law or CPUC decisions related to the PSPS events of October 9-12, 2019 and October 23-November 1, 2019.

The Utility filed its testimony with the CPUC on February 5, 2020.Parties filed testimony on February 28, 2020; concurrent rebuttal was filed on April 7, 2020; and hearings have been suspended indefinitely pending the COVID-19-related restrictions.

The Utility is unable to predict the timing or outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

OII to Examine the Late 2019 Public Safety Power Shutoff Events

On November 13, 2019, the CPUC issued an OII to determine “whether California’s investor-owned utilities prioritized safety and complied with the Commission’s regulations and requirements with respect to their Public Safety Power Shutoff (PSPS) events in late 2019.” The first phase of this proceeding will assess for each utility, among other things, (1) the effectiveness of the utility’s procedures to notify the public of the PSPS events, (2) the utility’s communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utility’s management of its resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary.

The Utility is unable to predict the timing or outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

Power Charge Indifference Adjustment OIR

In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the PCIA, a cost recovery mechanism to ensure that customers that leave the Utility’s bundled service for a non-Utility provider pay their fair share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf. The above market costs of the Utility’s generation portfolio are calculated using benchmarks for energy, resource adequacy (RA) and RPS attributes.

As previously disclosed, on October 11, 2018, the CPUC approved a phase one decision to modify the PCIA methodology. The Utility implemented a revised PCIA reflecting this decision in rates as of July 1, 2019.

Also, as previously disclosed, on October 10, 2019, the CPUC approved a final decision that finalized the true-up for the new PCIA methodology.

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On March 26, 2020, the CPUC approved a final decision on departing load forecasting and PCIA bill presentation issues, establishing that the IOUs shall show a PCIA line item in their tariffs and bill summary tables on all customer bills, which shall be implemented by the last business day of 2021.

The proceeding is now examining structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the Utility’s portfolios. A PD is expected in the third quarter of 2020.

For additional information, see the 2019 Form 10-K.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a customer harm threshold,CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service (the “Customer Harm Threshold”).CHT. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold.CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10,For additional information, see the 2019 the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.Form 10-K.

On March 29, 2019, the Assigned Commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding.



On July 8, 2019, the CPUC issued a decision in the Customer Harm Threshold proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility from access to relief under the Customer Harm Threshold during the pendency of the Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm Threshold based on: (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential maximum regulatory adjustment of either 20% of the Customer Harm Threshold or 5% of the total disallowed wildfire liabilities, whichever is greater; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the Customer Harm Threshold. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

Transportation Electrification

California law SB 350 requires the CPUC, in consultation with the California Air Resources Board and the CEC, to direct electrical corporations to file applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the other large IOUs to file TE applications that include both short-term projects (of up to $20 million in total) and two-to-five year programs with a requested revenue requirement determined by the Utility.

On May 31, 2018, the CPUC issued a final decision approving the Utility’s two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets. In the EV Fleet program, the Utility has a goal of providing make-ready infrastructure at 700 sites supporting 6,500 vehicles, conducting operation and maintenance of installed infrastructure, and educating customers on the benefits of electric vehicles. The final decision gives customers the option of self-funding, installing, owning, and maintaining the make-ready infrastructure installed beyond the customer meter in lieu of utility ownership, after which they would receive a utility rebate for a portion of those costs. The EV Fast Charge program has a goal to install utility-owned make-ready infrastructure at approximately 52 public charging sites amounting to roughly 234 DC fast chargers.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters (R.18-12-006). This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs’ transportation electrification investments, and vehicle-grid integration. A prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the Assigned Commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed electric DRP for approval by the CPUC.  The Utility’s DRP identifies its approach for identifying optimal locations on its electric distribution system for deployment of DERs.  The Utility’s DRP approach is designed to allow distributed energy technologies to be integrated into the larger grid while continuing to provide customers with safe, reliable, and affordable electric service.



As part of the Utility’s DRP approach, on June 1, 2018, the Utility filed its first annual distribution grid needs assessment report with the CPUC, and on September 4, 2018, the Utility filed its first distribution deferral opportunity report. The distribution deferral report proposes cost effective electric distribution investments that can be deferred through deployment of dispatchable third-party-owned DERs, or non-wire alternative solutions, to operate during specific grid events.  The Utility convened a distribution planning advisory group comprised of CPUC staff, ratepayer and environmental advocates, and DER market participants, to review and provide advisory input to the Utility on its distribution deferral identification process and to identify distribution deferral opportunities.  After incorporating the advisory group’s input, on November 28, 2018, the Utility filed a proposal with the CPUC for competitively procuring distribution services from third-party owned DERs to defer selected distribution projects.  Following the CPUC’s approval of the Utility’s procurement plan on February 5, 2019, the Utility launched a competitive solicitation and is currently evaluating offers. The Utility’s next annual distribution grid needs assessment and distribution deferral opportunity reports will be filed and served on August 15, 2019.

On March 26, 2018, the CPUC issued a final decision requiring the Utility to include a grid modernization plan for integrating DERs in the Utility’s GRC.  The grid modernization plan for DERs must include a narrative 10-year vision for investments needed to support DER growth, while ensuring safety and service reliability.  On June 25, 2018, the Utility hosted a public grid modernization workshop for integrating DERs to provide a high-level overview of its vision and 10-year plan and incorporate stakeholder input.  On December 13, 2018, the Utility filed its 2020 GRC Application, which includes the Utility’s grid modernization vision and plan. On June 28, 2019, PAO submitted testimony recommending changes to the Utility’s grid modernization vision and plan in the Utility’s 2020 GRC application. See summary of PAO’s overall 2020 GRC testimony in “2020 General Rate Case” above.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings.  Phase one will focus on how to integrate climate change adaptation into the IOUs’ existing planning and operations to ensure utility safety and reliability.

The CPUC OIR will consider:

how to define climate change adaptation for the IOUs;

the climate-driven risks facing the IOUs;

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

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

On October 10, 2018, the CPUC issued a scoping memo and established a procedural schedule. A final decision is expected in late 2019.

OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California. This proceeding has focused on the following issues:

examining conditions in which proactive and planned de-energization is practiced;

developing best practices and ensuring an orderly and effective set of criteria for evaluating de-energization programs;

ensuring electric utilities coordinate with state and local level first responders, and align their systems with the Standardized Emergency Management System framework;

mitigating the impact of de-energization on vulnerable populations;

examining whether there are ways to reduce the need for de-energization;



ensuring effective notice to affected stakeholders of possible de-energization and follow-up notice of actual de-energization; and

ensuring consistency in notice and reporting of de-energization events.

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8. The CPUC also provided clarity on phase two issues; however, a final determination of phase two issues will be conveyed in the phase two scoping memo. Phase 2 will take a more comprehensive look at de-energization practices, including mitigation, additional coordination across agencies, further refinements to findings in phase 1, re-energization practices, and other matters.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a Customer Harm Threshold (as defined herein), directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the Customer Harm Threshold. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires. On March 29, 2019, the Assigned Commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding. On July 8, 2019, the CPUC issued a decision in the OIR, which establishes a methodology to establish the Customer Harm Threshold in future applications under Section 451.2(a), but determines that a utility that has filed for relief under Chapter 11 cannot access the Customer Harm Threshold. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

(See “Regulatory Matters - OIR to Implement Public Utilities Code Section 451.2 Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901” above.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC.  The wildfire mitigation plan must include the components specified in SB 901, such as identification and prioritization of wildfire risks, and drivers for those risks; plans for vegetation management; actions to harden the system, prepare for, and respond to events; and protocols for disabling reclosers and deenergizing the system.  The CPUC has three months to approve a utility’s plan, with the ability to extend the deadline.  The CPUC will conduct an annual compliance review, which will be supported by an independent evaluator’s report.  The CPUC will complete the compliance review within 18 months.  SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan.  Costs associated with the wildfire mitigation plan are tracked in a memorandum account, and the costs of implementing the plan will be assessed in each utility’s GRC proceeding, or other application proceedings.  The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities.



Assembly Bill 1054

On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Sectionsection 3293 of the Public Utilities Code, added by AB 1054.

Each of California’sCalifornia large investor-owned electric utility companies that areis not currently subject to Chapter 11 (Southern California Edison Company and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

The Wildfire Fund to be established under AB 1054 will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund. The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

In order to participate in the Wildfire Fund, within 60 days of the effective date of AB 1054, the Utility must obtain the Bankruptcy Court’s approval of the Utility’s election to pay the initial and annual Wildfire Fund contributions upon emergence from Chapter 11. The Utility would then be required to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11, and meet certain eligibility requirements listed below, in order to participate in the Wildfire Fund. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases. There are several additional eligibility requirements for the Utility, including that by June 30, 2020, the following conditions are satisfied:

the Utility’s Chapter 11 Case has been resolved pursuant to a plan of reorganization or similar document not subject to a stay;

the Bankruptcy Court has determined that the resolution of the Utility’s Chapter 11 Case provides funding or otherwise provides for the satisfaction of any pre-petition wildfire claims asserted against the Utility in the Chapter 11 Case, in the amounts agreed upon in any settlement agreements, authorized by the Bankruptcy Court through an estimation process or otherwise allowed by the Bankruptcy Court;



the CPUC has approved the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case, including the Utility’s resulting governance structure as being acceptable in light of the Utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC;

the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case are (i) consistent with California’s climate goals as required pursuant to the California Renewables Portfolio Standard Program and related procurement requirements and (ii) neutral, on average, to the Utility’s ratepayers; and

the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case recognize the contributions of ratepayers, if any, and compensate them accordingly through mechanisms approved by the CPUC, which may include sharing of value appreciation.

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

If the Utility satisfies the requirements to participate in the Wildfire Fund, the Utility will be required to fund its initial contribution upon its emergence from Chapter 11. The Utility’s required contributions to the Wildfire Fund will be substantial. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.  The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions.  The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases. The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, consummate or implement any such plan, which will ultimately require Bankruptcy Court, creditor and regulatory approval. Further, there can be no assurance that the expected benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs.

AB 1054 includes certain modifications to the “just and reasonable” standard to be utilized by the CPUC in determining applications for recovery of wildfire-related costs. These modifications will apply to wildfires occurring following the effective date of AB 1054. AB 1054 provides that costs and expenses arising from any such wildfires “are just and reasonable if the conduct of the electrical corporation related to the ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available to the electrical corporation at the relevant point of time.” Further, in applying such standard, the CPUC is directed to take into account factors “both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.” Finally, AB 1054 modifies the circumstances under which an electric utility company bears the burden of demonstrating that its conduct was reasonable in accordance with the above standard.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three investor-owned electric utility companies on fire risk mitigation capital expenditures included in their respective approved wildfire mitigation plans will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the investor-owned electric utility companies in accordance with their Wildfire Fund allocation metrics (described above). AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

In response to directives in AB 1054, on July 26,For additional information, see the 2019 the CPUC opened a new rulemaking to consider the authorization of a non-bypassable charge to support the Wildfire Fund.  Comments on issues (e.g., the just and reasonableness of such a charge) are expected to be due in late August, 2019.  A final decision in the proceeding is expected in October 2019.Form 10-K.

Power Charge Indifference Adjustment OIR

On October 11, 2018, the CPUC approved a decision to modify the PCIA methodology, which was developed after the 2001 California energy crisis, which adjusts how customers that leave the Utility’s bundled service for CCA or DA service pay for their share of the costs associated with long-term power purchase commitments made on their behalf. The decision better enables utilities to recover their above market costs from departing customers as compared to the previous methodology, by:

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.

The Utility implemented a revised PCIA in rates as of July 1, 2019.

On December 19, 2018, a prehearing conference was held to initiate phase two of the PCIA proceeding, to further develop proposals for future consideration by the CPUC. On February 1, 2019, the assigned commissioner issued a phase two scoping memo and ruling, which sets forth the category, issues, need for hearing, schedule, and other matters. As indicated in the scoping memo and ruling, Phase Two of this proceeding will primarily rely upon a stakeholder working group process to further develop a number of PCIA-related proposals for consideration by the CPUC. Working Group One, which is co-facilitated by the Utility and the California Community Choice Association, focuses on developing benchmarks and a true-up mechanism that reflect the current market value of brown power, resource adequacy, and renewable energy credits (Issues 1 to 7); and load forecasting, rate design mechanics, and customer bill presentation (Issues 8 to 12). Working Group Two focuses on CCA and DA prepayment options; and Working Group Three focuses on portfolio optimization and cost reduction, allocation and auctions, and whether the CPUC should consider new or modified shareholder responsibility for future portfolio mismanagement. The schedule included in the scoping memo and ruling indicates that the CPUC is expected to issue two decisions impactful to 2020 rates in late 2019 concerning benchmark true-ups and PCIA rate design mechanics. Proposed decisions addressing matters relevant to the prepayment working group and the portfolio optimization and cost reduction, and allocation and auction working group are anticipated in 2020.

On May 31, 2019, the Working Group One co-leads filed the Final Report on Issues 1 to 7. On July 1, 2019, the Working Group One co-leads filed the Final Report on Issues 8 to 12. On July 9, 2019, the assigned ALJ modified the procedural schedule allowing parties to file comments on the July 1 Final Report, and updated the date for parties to request evidentiary hearings on the Final Report of Working Group One on Issues 8 to 12.  Opening comments on issues 8 to 12 were filed on July 19, 2019, reply comments were filed on July 26, 2019, and motions for evidentiary hearings were due August 2, 2019. In accordance with the current schedule, a proposed decision on Working Group One issues 1 to 7 would be issued in September 2019, a proposed decision on Working Group One issues 8 to 12 would be issued in Fall 2019, and final decisions on each of those matters would be voted 30 days after those proposed decisions.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHGgreenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel.  (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K.)


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CONTRACTUAL COMMITMENTS
CONTRACTUAL COMMITMEN
TS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities.  (See “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1).  Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing.  For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and MD&A “Contractual Commitments” in Item 7 of the 20182019 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 1415 of the Notes to the Consolidated Financial Statements in Item 8 of the 20182019 Form 10-K (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.  The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes.  The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments.  Some contracts are accounted for as leases.  The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate.  Credit limits and credit quality are monitored periodically.  These activities are discussed in detail in the 20182019 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the sixthree months ended June 30, 2019.March 31, 2020.

RECENT DEVELOPMENTS

New Chief Executive Officer and Board Members

On April 3, 2019, PG&E Corporation announced the appointment of 10 new directors to the Board of Directors of PG&E Corporation, with seven of the 10 then-incumbent directors stepping down, to be effective later that month. On April 22, 2019, Richard C. Kelly resigned from the Boards of PG&E Corporation and the Utility. Also, PG&E Corporation entered into a Settlement Agreement (the “Settlement Agreement”) with Blue Mountain Credit Alternatives Master Fund L.P. (together with its affiliates, “BlueMountain”), who had previously nominated candidates for election to PG&E Corporation’s Board of Directors. In connection with the execution and delivery of the Settlement Agreement, among other things, Frederick W. Buckman was appointed to the Boards of Directors of PG&E Corporation and the Utility and BlueMountain withdrew its nominations. The full text of the Settlement Agreement with BlueMountain is attached as an exhibit to PG&E Corporation’s Current Report on Form 8-K filed with the SEC on April 23, 2019. As of May 2, 2019, the Boards of Directors of PG&E Corporation and the Utility were each constituted with the following individuals: Richard R. Barrera, Jeffrey L. Bleich, Nora Mead Brownell, Frederick W. Buckman, Cheryl F. Campbell, Fred J. Fowler, William D. Johnson (Utility Board only), Michael J. Leffell, Kenneth Liang, Dominique Mielle, Meridee A. Moore, Eric D. Mullins, Kristine M. Schmidt and Alejandro D. Wolff.

In addition, William D. Johnson joined PG&E Corporation as its new Chief Executive Officer and President, effective May 2, 2019. In connection with the Settlement Agreement, PG&E Corporation agreed to engage Christopher A. Hart, a former chairman of the National Transportation Safety Board, to provide consulting services to Mr. Johnson regarding matters of safety.  

PG&E Corporation and the Utility expect that these leadership changes will have a significant impact on their operations and financial performance in the future.



CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  In addition to those items listed below, PG&E Corporation and the Utility consider their accounting policies for LSTC, regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, and pension and other post-retirement benefitsbenefit plans to be critical accounting policies.  These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates.  Actual results may differ materially from these estimates.estimates and assumptions.  These accounting policies and their key characteristics are discussed in detail in the 20182019 Form 10-K.

Liabilities Subject to Compromise

As a result of the Chapter 11 Cases, the payment of pre-petition indebtedness is subject to compromise or other treatment under a plan of reorganization. The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise are preliminary and may be subject to future adjustments depending on the Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances.  These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions.  PG&E Corporation and the Utility are not able to predict all the factors that may affect future results.  Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

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, which could be adversely affected if the Exclusive Filing Period or the Exclusive Solicitation Period is terminated; 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;

whether, in light of the CPUC July 8, 2019 final decision in the Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, the Utility will be able to obtain a substantial recovery of costs related to the 2017 Northern California wildfires;



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;

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 impact of AB 1054 on potential losses in connection with future wildfires;

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

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; the timing and outcome of the 2017 Northern California Wildfires OII 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, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations;

the timing and outcome of any potential settlement with holders of wildfire-related claims;

the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise, which potential financings are not addressed by AB 1054 as it only applies to future wildfires;

the timing and outcome of claims arising from the 2015 Butte fire, including claims by the OES; the timing and outcome of any proceeding to recover related costs in excess of insurance through rates; and whether any regulatory enforcement proceedings in connection with the 2015 Butte fire will be opened and any additional fines or penalties imposed on the Utility;

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 future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility;

the outcome of the Utility’s CWSP 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, including the Utility’s ability to comply with the targets and metrics set forth in the 2019 Wildfire Safety Plan; 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;

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



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, FHPMA and FRMMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings;

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 items such as 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 enhanced and accelerated inspection of its electric transmission and distribution assets;

the implementation of the Safety Culture OII decision approved on November 29, 2018, and the outcome of the 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;

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;

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;

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 renewable portfolio standard-eligible or carbon-free resources by 2045;



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;

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;

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;

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;

the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs and DA providers, 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 its natural gas and electric services;

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;

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;

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.

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained elsewhere in MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab and links to certain documents and information related to the 2018 Camp fire, the 2017 Northern California wildfires, the 2015 Butte fire, and other updates which may be of interest to investors, at http://investor.pgecorp.com, under the “Wildfire Updates” tab, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices.  PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only.  Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates.  (See the section above entitled “Risk Management Activities” in MD&A and in Note 8 and Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of June 30, 2019,March 31, 2020, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2019,March 31, 2020, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION 

ITEM 1. LEGAL PROCEEDINGS

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s legal proceedings and contingencies, see Notes 2, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Enforcement and Litigation Matters.”



U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on 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 imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the 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 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 has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On November 27, 2018,Upon the court’s request, on March 2, 2020, the Utility provided to the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Officeits target number of contract tree trimmers for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions2020, information regarding the Utility’s compliance with2019 inspections of Tower 009/081 on the terms of its probation, including what requirements ofCresta-Rio Oso 230 kV Transmission Line (the “Cresta-Rio Oso Line”), information regarding the relationship between priority codes set forth in the Utility’s probation “might be implicated were any wildfire startedElectric Transmission Preventive Maintenance Manual and the safety factors specified in General Order 95 promulgated by reckless operation or maintenancethe CPUC, as well as the application of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reportingeach to the C-hooks of information about any wildfire by PG&E.” The court also orderedinterest on the Cresta-Rio Oso Line. In addition, on April 2, 2020, the Utility submitted a report to provide “an accuratethe court regarding the Utility’s March 19, 2020 collection of equipment from the Cresta-Rio Oso Line. On April 10, 2020, the TCC in the Utility’s Chapter 11 bankruptcy case and complete statement of the role, if any, of PG&E in causingestimation proceedings filed a declaration from a TCC expert concerning Cresta-Rio Oso 230kV Transmission Line evidence collection and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). removal on March 19, 2020.

On December 5, 2018,April 29, 2020, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018.

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the Atlas fire.  The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order.  On January 4, 2019, the court issued another order requiring that the Utility provide “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition.  The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire.  In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to addimposing new conditions of probation that would require the Utility, among other things, to:

prior•employ, on its own payroll, “a sufficient number of inspectors to June 21, 2019, “re-inspectmanage the outsourced tree-trimming work,” including pre-inspectors to “identify trees and limbs in violation of California clearance laws that require trimming” and post-inspectors to “spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed,” and submit a detailed plan to carry out this requirement by May 28, 2020;

•“keep records identifying the age of every item of equipment on every transmission tower and line,” ensuring that “every part [has] a recorded date of installation” and “[i]f the age of a part is unknown, [] conduct research and estimate the year of installation;”
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•“[i]n consultation with the monitor, [] design a new inspection system for assessing every item of equipment on all transmission towers,” using forms that are “precise enough to track what inspectors actually do, such as whether they touch or tug on equipment,” take videos of every inspection, and “submit plans for its electrical gridnew inspection system to the [court] for approval by May 28[, 2020];” and remove or trim

•“require all treescontractors performing such inspections to carry insurance sufficient to cover losses suffered by the public should their inspections be deficient and thereby start a wildfire.”

The order noted that could fall onto its power lines, poles or equipmentthe court will be flexible in high-windapproving any protocols submitted by May 28, 2020, that achieve the essence of the newly imposed 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;”

“documentof probation if the foregoing inspectionsCPUC, the federal monitor, and the work doneUtility unanimously recommend such protocols. While the Utility is in the early stages of analyzing the proposed probation conditions, such conditions, if implemented, could have a material effect on the Utility’s financial condition, results of operations, liquidity and . . . rate each segment’s safety under various wind conditions;” andcash flows.

at all times from and after June 21,For more information on the Utility’s probation, see the 2019 “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”Form 10-K.



The Utility was orderedexpects to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed.  The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019.  On January 30, 2019,continue receiving additional orders from the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Safety Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to:

“fully comply with all applicable laws concerning vegetation management and clearance requirements;”

“fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;”

submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;”

“maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and

“ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forgo issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.”

The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the Court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.”

Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond 5 years in light of the violation that has been adjudicated and whether the third-party Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue.

The court held a sentencing hearing on the probation violation related to reporting requirements in connection with the 2017 Honey fire on May 7, 2019. After that hearing, the court imposed two additional conditions of probation by order dated May 14, 2019: (1) requiring that PG&E’s Board of Directors, Chief Executive Officer, senior executives, the Monitor and U.S. Probation Officer visit the towns of Paradise and San Bruno “to gain a firsthand understanding of the harm inflicted on those communities;” and (2) requiring that a committee of PG&E’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety Plan and the additional terms of probation regarding wildfire safety, reporting in writing to the full Board at least quarterly. The court also stated that it was not going to rule at this time on whether the court has authority to extend probation and would leave that question “in abeyance.” The court did not discuss whether the Monitor reports should be made public. Members of PG&E Corporation’s Board of Directors and senior management attended site visits to the Town of Paradise on June 7, 2019 and the City of San Bruno on July 16, 2019, which were coordinated by the U.S. Probation Officer overseeing the Utility’s probation. In addition, the Compliance and Public Policy Committee, a committee of PG&E Corporation’s Board of Directors, will be responsible for tracking the Utility’s progress against the Utility’s wildfire mitigation plan, as approved by the CPUC, and compliance with the terms of the Utility’s probation regarding wildfire safety.



On July 10, 2019, the court ordered the Utility to respond to a Wall Street Journal article titled “PG&E Knew for Years Its Lines Could Spark Wildfires, and Didn’t Fix Them” on a paragraph-by-paragraph basis, stating the extent to which each paragraph in the article is accurate.  The court also ordered the Utility to disclose all political contributions made by the Utility since January 1, 2017, and provide additional explanations regarding those contributions and dividends distributed prior to filing the Chapter 11 Cases. The Utility filed its response with the court on July 31, 2019. In the response, the Utility disagreed with the Wall Street Journal article’s suggestion that the Utility knew of the specific maintenance conditions that caused the 2018 Camp fire and nonetheless deferred work that would have addressed those conditions.

future.

Order Instituting an Investigation into PG&E Corporation’sCorporation’s and the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The SED engaged a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment, and subsequently, to report on the implementation by the Utility of the consultant’s recommendations.

On May 8, 2017, the CPUC released the consultant’s report, accompanied by a scoping memo and ruling that directed the CPUC to evaluate the safety recommendations of the consultant and to consider all necessary measures, including, but not limited to, a potential reduction of the Utility’s return on equity. On November 17, 2017, the CPUC issued a further scoping memo and procedural schedule that directed the Utility to file testimony addressing a number of issues including: adoption of the safety recommendations from the consultant, the Utility’s implementation process for the safety recommendations of the consultant, the Utility’s Board of Director’s actions and initiatives related to safety culture and the consultant’s recommendations, the Utility’s corrective action program, and the Utility’s response to certain specified safety incidents that occurred in 2013 through 2015.

The Utility’s testimony was submitted to the CPUC on January 8, 2018 and stated that the Utility agrees with all the recommendations of the consultant and supports their adoption by the CPUC. Other parties’ responsive testimony was submitted on February 16, 2018, followed by the Utility’s rebuttal testimony on February 23, 2018.

On November 29, 2018, the CPUC issued a decision that directed the Utility to implement the recommendations set forth in the May 2017 consultant report no later than July 1, 2019, and to submit quarterly reports on the Utility’s implementation status beginning in the fourth quarter of 2018.

On December 21, 2018, the CPUC issued another scoping memo and ruling expanding the proceeding and directing that the CPUC “will examine [PG&E’s] current corporate governance, structure, and operations to determine if the utility is positioned to provide safe electrical and gas service, and will review alternatives to the current management and operational structures of providing electric and gas service in Northern California.”

The CPUC alleged that the Utility has had “serious safety problems with both its gas and electric operations for many years” and that despite penalties and other remedial measures in connection with these problems, PG&E Corporation and the Utility have failed to develop “a comprehensive enterprise-wide approach to addressing safety.” The scoping memo outlined a number of proposals to address the CPUC’s concerns regarding PG&E Corporation’s and the Utility’s safety culture, including, but not limited to, (i) replacement of all or part of PG&E Corporation’s and the Utility’s existing boards of directors and corporate management, (ii) separating the Utility’s gas and electric distribution and transmission businesses into separate companies, (iii) reorganizing the Utility into regional subsidiaries based on regional distinctions, (iv) reconstituting the Utility as a publicly owned utility or utilities, (v) providing for entities other than the Utility to provide generation services, and (vi) conditioning the Utility’s return on equity on safety performance. The scoping memo did not propose penalties and stated that this phase “is not a punitive phase.” The Utility submitted its background filing to the CPUC on January 16, 2019 and opening comments were filed on February 13, 2019. The Utility and other parties filed reply comments on February 28, 2019. Subsequently, the CPUC held workshops on some of the topics raised in the scoping memo on April 15, 2019 and April 26, 2019.

On June 13, 2019, the CPUC issued a decision that directed PG&E Corporation and the Utility to provide information about the safety experience and qualifications of each of the directors on their boards. PG&E Corporation and the Utility provided such information on July 3, 2019. The decision also established a Commission Advisory Panel on Corporate Governance.



On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating PG&E into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of PG&E’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking PG&E’s rate of return or return on equity to safety performance metrics.

Opening comments on the ruling were filed on July 19, 2019 and reply comments were filed on August 2, 2019.

For more information, see the 2019 Form 10-K.

Diablo Canyon Power Plant

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board, the Utility, and the California Attorney General’s Office, see Part I, Item 3. “Legal Proceedings” in the 20182019 Form 10-K.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the 20182019 Form 10-K and PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2019 entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of legislative and regulatory developments.

The Utility’s financial results could be materially affected as a result of SB 901 adopted in 2018 by the California legislature. In December 2018, the CPUC opened an OIR in connection with SB 901 that will adopt criteria and a methodology for use by the CPUC in future applications for cost recovery of wildfire costs. On July 8, 2019, the CPUC issued a decision in the Customer Harm Threshold proceeding.  The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).”  This determination effectively bars PG&E Corporation and the Utility from access to relief under the Customer Harm Threshold during the pendency of the Chapter 11 Cases.  On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. (See “Regulatory Matters - Other Regulatory Proceedings” in Item 2. MD&A.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC.  SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan.  The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities. Failure to substantially comply with the plan could result in fines and other penalties imposed on the Utility that could be material. (See “Regulatory Matters - Other Regulatory Proceedings” in Item 2. MD&A.)
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On July 12, 2019, the California Governor signed into law AB 1054, a bill which, among other policy reforms, provides for the establishment of a statewide fund that would be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Although PG&E Corporation and the Utility have delivered notice to the CPUC electing to participate in the Wildfire Fund, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s eligibility to access relief under the Wildfire Fund (which is dependent on, among other things, PG&E Corporation and the Utility emerging from Chapter 11 by June 30, 2020 and making its initial contribution thereto) and the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund are just and reasonable, subject to a disallowance cap. Failure to meet the eligibility conditions to access relief under the Wildfire Fund, including emerging from Chapter 11 by June 30, 2020 and making the initial contribution thereto, would preclude PG&E Corporation and the Utility from accessing the Wildfire Fund for future wildfire-related claims and any related benefits, including the disallowance cap.



The costs of participating in the Wildfire Fund (should the Utility be eligible to do so) are expected to exceed $6.7 billion. The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions.  The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.

Finally, AB 1054 does not apply to wildfires with an ignition date prior to the effective date of AB 1054. PG&E Corporation and the Utility may be dependent on additional legislative measures in order to facilitate the financing of costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires. There can be no assurance that any such legislative measures will be enacted or enacted in a form that would materially address PG&E Corporation’s and the Utility’s financing needs.

Also, in June 2018, the State of California enacted the CCPA, which will come into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. However, California legislators have stated that they intend to propose amendments to the CCPA, and it remains unclear what, if any, modifications will be made to the CCPA or how it will be interpreted. Failure to comply with the CCPA could result in fines imposed on PG&E Corporation and the Utility that could be material.

The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events, or may not be available at a reasonable cost, or available at all.

The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires and other risks that could arise from the Utility’s ordinary operations.  PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions and/or increased insurance costs in future years.  No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage.  Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates.  A loss that is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As a result of the potential application to investor-owned utilities of a strict liability standard under the doctrine of inverse condemnation, recent losses recorded by insurance companies, the risk of increased wildfires including as a result of climate change, the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at a reasonable cost, or at all.  In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.

If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to obtain insurance at a reasonable cost or recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected.significantly affected by the outbreak of the COVID-19 pandemic.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been (beginning in March 2020) and will continue to be significantly affected by the outbreak of COVID-19. In December 2019, a novel strain of coronavirus (COVID-19) was reported to have surfaced in Wuhan, China, resulting in significant disruptions to manufacturing, supply chain, markets, and travel world-wide. On January 30, 2020, the International Health Regulations Emergency Committee of the World Health Organization declared the COVID-19 outbreak a public health emergency of international concern and on March 12, 2020, announced the outbreak was a pandemic. On March 19, 2020, the California Governor instituted shelter-in-place measures that became effective state-wide on March 19, 2020. It is currently uncertain when and how the shelter-in-place measures will be lifted. On March 16, 2020, the CPUC directed electric utility companies to follow customer protection measures including a moratorium on service disconnections, retroactive to March 4, 2020. While the extent of the impact of the current COVID-19 coronavirus outbreak on PG&E Corporation and the Utility’s business and financial results is uncertain, the consequences of a continued and prolonged outbreak and resulting protective government and regulatory orders could have a further negative impact on the Utility’s financial condition, results of operations, liquidity and cash flows.

The outbreak of COVID-19 and the resulting economic conditions, including but not limited to the shelter-in-place order and resulting decrease in economic and industrial activity in the Utility’s service territory which has not been entirely offset by an increase in daytime household electrical use, have and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances impact and will continue to impact the Utility for a period of time that PG&E Corporation and the Utility are unable to predict. For example, the economic downturn has already resulted in a reduction in customer receipts and collection delays for March and April 2020.

As of the time of this filing, the Utility has also experienced a net decrease in total non-residential electrical load, leading to a reduction in revenues from non-residential customers. PG&E Corporation and the Utility are currently unable to quantify the potential impact of the changes in customer collections or changes in energy demand on earnings and cash flows.

The timing of regulatory relief, if any, and ultimately cost recovery, are uncertain. With respect to certain customer protections, on April 16, 2020, the CPUC adopted a resolution authorizing utilities to establish memorandum accounts to track incremental costs associated with an earlier CPUC order requiring the utilities to implement a number of emergency customer protections. The COVID-19 pandemic and resulting economic downturn have resulted and will continue to result in workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment. Although the Utility continues to prioritize customer and community safety, these disruptions necessitate changes to the Utility’s operating and capital expenditure plans, which could lead to project delays or service disruptions and otherwise adversely impact operations and planning. Delays in production and shipping of materials used in the Utility’s operations may also adversely impact operations. In addition, COVID-19 has the potential to cause delays and disruptions in various regulatory proceedings in which the Utility is involved. Following Department of Health guidance concerning restrictions on public gatherings, the CPUC has cancelled all public forums and has been conducting remote meetings for events it deems essential. A disruption in CPUC operations could impact the timing of PG&E Corporation’s and the Utility’s rate cases and other regulatory proceedings.

In addition, as discussed above, a group of local government entities and organizations filed a Joint Motion asking the CPUC to require utilities to comply with additional requirements when implementing PSPS events while local areas are sheltering-in-place due to COVID-19. A CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. Potential longer term impacts of COVID-19 on PG&E Corporation or the Utility include the potential for higher borrowing costs due to the increasing difference in the higher yield of lower-rated debt as compared to the lower yield of higher-rated debt of similar maturity and incremental financing needs. PG&E Corporation and the Utility’s analysis of the potential impact of COVID-19 is preliminary and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 situation and its effects on the business and general economic conditions in the State of California and the United States of America. PG&E Corporation and the Utility continue to monitor the potential impact of the COVID-19 pandemic.

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Market conditions resulting from the outbreak of COVID-19 may hinder PG&E Corporation’s and the Utility’s exit financing to emerge from Chapter 11.

The outbreak of COVID-19 and the resulting economic downturn have adversely affected the financial markets and the economy more generally and could result in an economic downturn. As of March 31, 2020, the S&P 500 had declined over 20% from its previous high close recorded on February 19, 2020. PG&E Corporation and the Utility are relying on the equity and debt capital markets in order to finance their emergence from Chapter 11. Although PG&E Corporation’s expected equity raise for approximately $9 billion of net cash proceeds is backstopped by the Backstop Commitment Letters, obtaining financing from the capital markets at higher price-to-earnings multiples than the multiple contemplated by the Backstop Commitment Letters would result in significantly less dilution to shareholders. In addition, it is possible that the commitments under the Backstop Commitment Letters are not available due to potential termination events or a default by one or more backstop parties. With respect to the debt financing, PG&E Corporation’s and the Utility’s issuances are supported by $11.9 billion of bridge commitments. The remaining $6 billion of debt financing in PG&E Corporation’s and the Utility’s Plan of Reorganization is not supported by committed capital and will be subject to market conditions. PG&E Corporation and the Utility could also fail to satisfy the conditions in their existing Debt Commitment Letters (as defined above). In any event, adverse capital market conditions related to COVID-19 (or otherwise) could make it more difficult or expensive, or even infeasible, to emerge from Chapter 11 through the use of one or more capital market financing transactions.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the quarter ended June 30, 2019,March 31, 2020, PG&E Corporation did not make any equity contributions to the Utility. Also during the quarter ended June 30, 2019,March 31, 2020, PG&E Corporation did not make any sales of unregistered equity securities in reliance on an exemption from registration under the Securities Act of 1933, as amended.

Issuer Purchasesof Equity Securities

During the quarter ended June 30, 2019,March 31, 2020, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended June 30, 2019,March 31, 2020, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.


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ITEM 6. EXHIBITS



EXHIBIT INDEX
3.1
10.13.2
Settlement3.3
3.4
3.5
10.1
Restructuring Support Agreement dated Aprilas of January 22, 2019,2020, by and betweenamong PG&E Corporation and BlueMountainPacific Gas and Electric Company, Apollo Global Management LLC, Elliott Management Corporation, Oaktree Capital Management L.P., Farallon Capital Management LLC, Capital Group, Värde Partners Inc., Davidson Kempner Capital Management LP, Canyon Capital Advisors LLC, Third Point LLC, Pacific Investment Management Company LLC, Citadel Advisors LLC and Sculptor Capital Investments, LLC, certain funds and accounts managed or advised by Abrams Capital Management, LP and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated April 22, 2019filed on January 23, 2020, (File No. 1-12609),1-12609, Exhibit 10.1)
10.2
10.3
10.4
10.5*
10.310.6
10.410.7
10.510.8
10.631.1
10.7
Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Calaveras County Water District (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.6)
*10.8
Form of Director and Officer Indemnification Agreement
*10.9
PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of June 3, 2019
*10.10
PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of June 3, 2019
*10.11
Separation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated June 3, 2019, revised as of June 5, 2019 and June 24, 2019
31.1
Certifications of Principal Executive Officer and Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2
32.1**32.1*
32.2**32.2*
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101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH101.SCXBRL Taxonomy Extension Schema Document
101.CAL101.CAXBRL Taxonomy Extension Calculation Linkbase Document
101.LABXBRL Taxonomy Extension Labels Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document


101.DE
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
*Management contract or compensatory agreement.
*This Form of Chapter 11 Plan Backstop Commitment Letter is substantially similar in all material respects to each Chapter 11 Plan Backstop Commitment Letter that is otherwise required to be filed as an exhibit, except as to the Backstop Party and the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Chapter 11 Plan Backstop Commitment Letter). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Chapter 11 Plan Backstop Commitment Letter, with a schedule identifying the Chapter 11 Plan Backstop Commitment Letters omitted and setting forth the material details in which each Chapter 11 Plan Backstop Commitment Letter differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Chapter 11 Plan Backstop Commitment Letter so omitted.

***Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION
/s/ JASON P. WELLS
Jason P. Wells

Executive Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY
/s/ DAVID S. THOMASON
David S. Thomason

Vice President, Chief Financial Officer and Controller
(duly authorized officer and principal financial officer)

Dated: August 9, 2019

Dated: May 1, 2020
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