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Pacific Gas Electric Co (75488) SEC Filing 10-K Annual report for the fiscal year ending Tuesday, December 31, 2019

Pacific Gas Electric Co

CIK: 75488

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Investor Relations Contact: 415.972.7080 | Media Inquiries Contact: 415.973.5930 | www.pgecorp.com
February 18, 2020

PG&E Corporation Reports Full-Year and Fourth-Quarter 2019 Financial Results; Provides Five-Year Financial Forecast and Chapter 11 Proceeding Update

Recorded GAAP losses were $14.50 per share for the year and $6.84 per share for the fourth quarter of 2019, compared to losses of $13.25 and $13.24 per share for the same periods respectively in 2018.
In anticipation of its emergence from Chapter 11 reorganization, the company is filing a five-year financial forecast that includes capital and rate base growth projections.
PG&E remains on track to have its Chapter 11 Plan confirmed by June 30, 2020.

SAN FRANCISCO — PG&E Corporation (NYSE: PCG) full-year 2019 net loss attributable to common shareholders was $7.7 billion, or $14.50 per share, as reported in accordance with generally accepted accounting principles (“GAAP”). This compares with net loss attributable to common shareholders of $6.9 billion, or $13.25 per share, for the full-year 2018. For the fourth quarter of 2019 net loss attributable to common shareholders was $3.6 billion, or $6.84 per share, compared with net loss attributable to common shareholders of $6.9 billion, or $13.24 per share, for the fourth quarter of 2018.

GAAP results include non-core items that management does not consider representative of ongoing earnings, which totaled $4.0 billion after-tax, or $7.52 per share, for the quarter. This was primarily driven by an additional $5.0 billion pre-tax charge for estimated third-party claims related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. This additional charge reflects the previously announced agreements with individual wildfire victims.

Other wildfire-related non-core items for the fourth quarter of 2019 include an additional charge for the Wildfire Order Instituting Investigation (“Wildfire OII”) settlement and the bill credit compensating customers for the October 9, 2019 Public Safety Power Shutoff (“PSPS”), partially offset by the probable recoveries of insurance premiums incurred in 2018 above amounts included in authorized revenue requirements. Non-core items related to PG&E Corporation’s and Pacific Gas and Electric Company’s (“Utility”) reorganization cases under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”) include a reduction of interest expense on pre-petition debt, partially offset by legal and other costs. Other non-core items include enhanced and accelerated electric asset inspection costs and the Locate and Mark OII penalty.

Five-year Financial Forecast

As a milestone in the process of emerging from Chapter 11 reorganization, PG&E is also releasing a five-year financial forecast highlighting capital and rate base growth along with other material drivers of the business, as well as filing three-statement financials with the Bankruptcy Court. This financial forecast was developed for purposes of the formulation and negotiation of the Plan of Reorganization and to enable the stakeholders entitled to vote under the Plan to make an informed judgment about the Plan and should not be used or relied upon for any other purpose.



The following information was filed by Pacific Gas Electric Co on Tuesday, February 18, 2020 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-K Annual Report statement of earnings and operation as management may choose to highlight particular information in the press release.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________

FORM 10-K
(Mark One) 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2019
 
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 or Organization
IRS Employer
Identification Number
1-12609PG&E CORPORATIONCalifornia94-3234914
1-2348PACIFIC GAS AND ELECTRIC COMPANYCalifornia94-0742640

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77 Beale Street77 Beale Street
P.O. Box 770000P.O. Box 770000
San Francisco,California94117San Francisco,California94117
(Address of principal executive offices) (Zip Code)(Address of principal executive offices) (Zip Code)
415973-1000415973-1000
(Registrant’s telephone number, including area code)(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

Securities registered pursuant to Section 12(g) of the Act: none




Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo

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:YesNo
Pacific Gas and Electric Company:YesNo
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):
PG&E CorporationPacific Gas and Electric Company
Large accelerated filerLarge accelerated filer
Non-accelerated filerNon-accelerated filer
Smaller reporting companySmaller reporting company
Accelerated filerAccelerated filer

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:YesNo
Pacific Gas and Electric Company:YesNo

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2019, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock
                    $12,130 million
Pacific Gas and Electric Company common stock                    Wholly owned by PG&E Corporation




Common Stock outstanding as of February 13, 2020:
PG&E Corporation:529,254,082shares
Pacific Gas and Electric Company:264,374,809shares (wholly owned by PG&E Corporation)
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the Joint Proxy Statement relating to the 2020 Annual Meetings of ShareholdersPart III (Items 10, 11, 12, 13 and 14)




Contents
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UNITS OF MEASUREMENT
1 Kilowatt (kW)=One thousand watts
1 Kilowatt-Hour (kWh)=One kilowatt continuously for one hour
1 Megawatt (MW)=One thousand kilowatts
1 Megawatt-Hour (MWh)=One megawatt continuously for one hour
1 Gigawatt (GW)=One million kilowatts
1 Gigawatt-Hour (GWh)=One gigawatt continuously for one hour
1 Kilovolt (kV)=One thousand volts
1 MVA=One megavolt ampere
1 Mcf=One thousand cubic feet
1 MMcf=One million cubic feet
1 Bcf=One billion cubic feet
1 MDth=One thousand decatherms

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GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2019 Form 10-KPG&E Corporation’s and Pacific Gas and Electric Company’s combined Annual Report on
Form 10-K for the year ended December 31, 2019
2019 Wildfire Mitigation 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
ARAMaverage rate assumption method
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
BPPbundled procurement plan
CAISOCalifornia Independent System Operator
Cal FireCalifornia Department of Forestry and Fire Protection
CARBCalifornia Air Resources Board
CCACommunity Choice Aggregator
CCPACalifornia 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
CHTCustomer Harm Threshold
CPUCCalifornia Public Utilities Commission
CRRscongestion revenue rights
CUECoalition of California Utility Employees
CWSPCommunity Wildfire Safety Program
DADirect Access
DERdistributed energy resources
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
DOEU.S. Department of Energy
DRPDistribution Resource Plan
DTSCDepartment of Toxic Substances Control
EIMEnergy Imbalance Market
Effective Datethe effective date of the Proposed Plan
EPAU.S. Environmental Protection Agency
EPSearnings per common share
EVelectric vehicle
EVMenhanced vegetation management
FASBFinancial Accounting Standards Board
FEMAFederal Emergency Management Agency
FERCFederal Energy Regulatory Commission
FHPMAFire Hazard Prevention Memorandum Account
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Fire Victim Trust
A trust to be established pursuant to the Proposed Plan for the benefit of holders of the fire victim claims, as defined in Note 14 of the Notes to the Consolidated Financial Statements in Item 8
FRMMAFire Risk Mitigation Memorandum Account
GAAPU.S. Generally Accepted Accounting Principles
GHGgreenhouse gas
GRCgeneral rate case
GT&Sgas transmission and storage
HSMhazardous substance memorandum account
IOUsinvestor-owned utility(ies)
LCCLand Conservation Commitment
LIBORLondon Interbank Offered Rate
LSTCliabilities subject to compromise
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
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
NDTDiablo Canyon Nuclear Decommissioning Trust
NEILNuclear Electric Insurance Limited
NEMnet energy metering
Noteholder RSARestructuring Support Agreement dated as of January 22, 2020 with certain holders of indebtedness of the Utility, among others
NRCNuclear Regulatory Commission
OESState of California Office of Emergency Services
OIIorder instituting investigation
OIRorder instituting rulemaking
OSAOffice of the Safety Advocate, a division of the CPUC
PAOPublic Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)
PCIAPower Charge Indifference Adjustment
PDproposed decision
Petition DateJanuary 29, 2019
PFMpetition for modification
Proposed PlanPlan of Reorganization, as defined in Note 2 of the Notes to the Consolidated Financial Statements in Item 8
PSAplan support agreement
PSPSPublic Safety Power Shutoff
RAMPRisk Assessment Mitigation Phase
ROEreturn on equity
ROU assetright-of-use asset
RPSrenewable portfolio standard
RSArestructuring support agreement
SBSenate Bill
SECU.S. Securities and Exchange Commission
SEDSafety and Enforcement Division of the CPUC
Subrogation RSARestructuring Support Agreement dated September 22, 2019 with certain holders of insurance subrogation claims, as amended
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Tax ActTax Cuts and Jobs Act of 2017
TCCOfficial Committee of Tort Claimants
TCC RSARestructuring Support Agreement dated December 6, 2019 with the TCC and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended
TEtransportation electrification
TOtransmission owner
TURNThe Utility Reform Network
UCCOfficial 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)
VMvegetation management
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
Wildfires OIIOrder Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
WMPwildfire mitigation plan
WMPMAWildfire Mitigation Plan Memorandum Account

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;

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if the Proposed 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 Proposed 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 Proposed 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;

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

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 through rates; 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 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 AB 1054 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 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 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;

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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;

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 following the entry on January 16, 2020 of an order to show cause by the United States District Court for the Northern District of California, 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;

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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 CARB 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, 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;

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

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

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

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

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 7. 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.

PART I

ITEM 1. BUSINESS

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below in Item 6. Selected Financial Data.

The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules, and regulations.

At December 31, 2019, PG&E Corporation and the Utility had approximately 23,000 regular employees, approximately 12 of which were employees of PG&E Corporation. Of the Utility’s regular employees, approximately 15,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (IBEW) Local 1245; the Engineers and Scientists of California (ESC) IFPTE 20; and the Service Employees International Union. The collective bargaining agreements currently in effect will expire on December 31, 2021. As part of the bankruptcy plan of reorganization, the IBEW Local 1245, and the Utility reached a tentative agreement to extend the current collective bargaining agreement that is set to expire on December 31, 2021 through December 31, 2025. The tentative agreement increases wages annually by 3.75% from 2022 through 2025 and maintains current contributions to specified benefits. The IBEW represents approximately 50% of the Utility’s employee workforce, and supports several areas of the Utility’s business, including gas and electric operations. The Utility plans to work with its other unions, the Engineers and Scientists of California, Local 20, and Service Employees International Union, Local 24/7 to negotiate potential contract extensions.

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PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. 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 “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 websites are 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 such websites solely for the information of investors and do not intend the addresses to be an active link.

In 2019, 2018 and 2017, Northern California experienced major wildfires. For more information about the 2019 Kincade fire, the 2018 Camp fire and the 2017 Northern California wildfires, see Item 3. Legal Proceedings, Item 7. MD&A, and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

This 2019 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these 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 and the section entitled “Forward-Looking Statements” above.

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility filed for Chapter 11 protection. For more information about the Chapter 11 bankruptcy filings see Item 7. MD&A and Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection. Management has concluded that these circumstances raise substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns, and their independent registered public accountants have included an explanatory paragraph in their auditors’ report which states 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. For more information about these matters, see Item 7. MD&A and Note 1 of the Notes to the Consolidated Financial Statements in Item 8.

Regulatory Environment 

The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is subject to the jurisdiction of the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility.

PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

The California Public Utilities Commission

The CPUC is a regulatory agency that regulates privately owned public utilities in California. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transmission and storage services. The CPUC also has exercised jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electric and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

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The CPUC enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities.  The CPUC can impose penalties of up to $100,000 per day, per violation. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged.

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED has the discretion to either address each violation in a distinct citation or to include multiple violations in a single citation regardless of whether the violations occurred in the same incident or are of a similar nature. Penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and must not be recovered in rates or otherwise directly or indirectly charged to customers.

The California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to wildfires and wildfire cost recovery, increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, the establishment of energy storage procurement targets, and the development of a state-wide electric vehicle charging infrastructure. The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. The CPUC also conducts audits and reviews of the Utility’s accounting, performance, and compliance with regulatory guidelines.

The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. (For more information, see “Liquidity and Financial Resources” in Item 7. MD&A and Item 1A. Risk Factors.)

The Federal Energy Regulatory Commission and the California Independent System Operator

The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates the interconnections of the Utility’s transmission systems with other electric system and generation facilities, the tariffs and conditions of service of regional transmission organizations and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electric transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. FERC approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property. The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations.

The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory. The CAISO controls the operation of the electric transmission system in California and provides open access transmission service on a non-discriminatory basis. The CAISO is also responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generating capacity, ensuring that the reliability of the transmission system is maintained, and operating an interstate EIM.

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The Nuclear Regulatory Commission

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay. (See “Electricity Resources” below.) NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and substantial capital expenditures could be required in the future. (For more information about Diablo Canyon, see Item 3. Legal Proceedings below.)

Third-party Monitor

On April 12, 2017, the Utility retained a third-party monitor at the Utility’s expense as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, which sentenced the Utility to, among other things, a five-year corporate probation period and oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years.  The goal of the third-party monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations and maintains effective ethics, compliance, and safety related incentive programs on a Utility-wide basis. (For more information see Item 1A. Risk Factors and in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

Other Regulators

The CEC is the state’s primary energy policy and planning agency. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans and for adopting building and appliance energy efficiency requirements.

The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. (See “Environmental Regulation - Air Quality and Climate Change” below.)

In addition, the Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy and/or use public property for the operation of the Utility’s business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. (For more information see Item 1A. Risk Factors.)

Ratemaking Mechanisms

The Utility’s rates for electric and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service and a return on invested capital (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount that the Utility will be authorized to collect from its customers (“revenue requirements”). The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Item 7. MD&A), including its costs to procure electricity, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.

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The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. Similarly, the authorized rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to fully collect its authorized base revenue requirements. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May - October) because of higher demand, driven by air conditioning loads.  Customer bills related to gas service generally increase during the winter months (November - March) to account for the gas peak due to heating.

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn some additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.
See “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC proceedings.

Base Revenues

General Rate Cases

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, including return on rate base, related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations. The CPUC generally conducts a GRC every three or four years. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). Attrition year rate adjustments are generally provided for cost increases related to increases in invested capital and inflation. Parties in the Utility’s GRC include the PAO and TURN, which generally represent the overall interests of residential customers, as well as numerous intervenors that represent other business, community, customer, environmental, and union interests.

On January 16, 2020, the CPUC 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 will combine its GRC and GT&S rate cases starting with the 2023 GRC and 2023 GT&S rate case. (For more information about the Utility’s GRC, see “Regulatory Matters 2017 General Rate Case” and “Regulatory Matters 2020 General Rate Case” in Item 7. MD&A.)

Natural Gas Transmission and Storage Rate Cases

The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in the GT&S rate case.  The CPUC generally conducts a GT&S rate case every three or four years.  Similar to the GRC, the CPUC approves the annual revenue requirements for the first year (or “test year”) of the GT&S rate case period and typically determines annual increases in revenue requirements for attrition years of the GT&S rate case period.  Parties in the Utility’s GT&S rate case include the PAO and TURN, who generally represent the overall interests of residential customers, as well as other intervenors who represent other business, community, customer, environmental, and union interests.

As previously mentioned, on January 16, 2020, the CPUC approved a final decision that requires the Utility to combine its GRC and GT&S rate cases starting with the 2023 GRC and 2023 GT&S rate case. (For more information, see “Regulatory Matters - 2015 Gas Transmission and Storage Rate Case” and “Regulatory Matters - 2019 Gas Transmission and Storage Rate Case” in Item 7. MD&A.)  

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Cost of Capital Proceedings

The CPUC periodically conducts a cost of capital proceeding to authorize the Utility’s capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. On December 19, 2019, the CPUC issued a final decision that authorizes the Utility’s capital structure through 2023, consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred stock. The CPUC also set the authorized ROE through 2023 at 10.25% and reset the cost of debt to 5.16%. The CPUC also authorized the continuation of an adjustment mechanism to allow the Utility’s cost of debt and ROE to be adjusted if the utility bond index changes by certain thresholds, which are reviewed annually. The CPUC has indicated it will determine in the OII to Consider PG&E Corporation’s and the Utility’s Proposed Plan of Reorganization if the Utility needs to submit a cost of capital application after it emerges from Chapter 11.

Electricity Transmission Owner Rate Cases

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 Utility has historically filed a TO rate case every year. 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. In 2018, the Utility filed a formula rate at FERC, which would be updated annually according to the formula. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates and by the CAISO in its Transmission Access Charges to wholesale customers. (For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7. MD&A.) The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations. These wholesale customers are charged individualized rates based on the terms of their contracts.

Memorandum Account Costs

Periodically, costs arise which could not be anticipated by the Utility during CPUC GRC rate requests or which are deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. While the Utility believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. (For more information, see “Regulatory Matters - Wildfire Expense Memorandum Account,” “Regulatory Matters - Catastrophic Expense Memorandum Account,” and “Regulatory Matters - Fire Hazard Prevention Memorandum Account” in Item 7. MD&A.)

Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California investor-owned electric utilities are responsible for procuring electrical capacity required to meet bundled customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electric contracts. The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”). In addition, the utilities are required to obtain CPUC approval of their BPPs based on long-term demand forecasts. In October 2015, the CPUC approved the Utility’s most recent comprehensive BPP. It was revised since its initial approval and will remain in effect as revised until superseded by a subsequent CPUC-approved plan. On February 8, 2019, the CPUC approved the Utility’s filing that permitted the Utility to temporarily manage certain elements of its current BPP as a result of its financial condition, effective as of January 16, 2019.  Additionally, on January 25, 2019, the Utility filed with the CPUC an update to its BPP to further refine how it manages certain elements of its procurement activity and provide detail of its sales framework.  The updated BPP was effective upon CPUC approval on May 30, 2019.

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved BPPs without further after-the-fact reasonableness review by the CPUC. The CPUC may disallow costs associated with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch. Additionally, the CPUC may disallow the cost of replacement power procured due to unplanned outages at utility-owned generation facilities.

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The Utility recovers its electric procurement costs annually primarily through balancing accounts. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.) Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement. The CPUC may adjust the Utility’s retail electric rates more frequently if the forecasted aggregate over-collections or under-collections in the energy resource recovery account exceed 5% of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the transactions recorded in the energy resource recovery account.

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved procurement plan, to meet mandatory renewable energy targets, and to comply with resource adequacy requirements. (For more information, see “Electric Utility Operations - Electricity Resources” below as well as Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

Natural Gas Procurement, Storage, and Transportation Costs

The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electric rates.

The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its core procurement incentive mechanism described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rate changes.

The core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio. Under the core procurement incentive mechanism, the Utility’s natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of these savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.
The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. The FERC approves the United States tariffs that shippers, including the Utility, pay for pipeline service, and the applicable Canadian tariffs are approved by the National Energy Board, a Canadian regulatory agency. The transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as a cost of electricity.

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Costs Associated with Public Purpose and Customer Programs

The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers.  These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters.  Additionally, the CPUC has authorized the Utility to provide discounted rates for specified types of customers, such as for low-income customers under the California Alternate Rates for Energy (“CARE”) program, which is paid for by the Utility’s other customers.

Nuclear Decommissioning Costs

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. Nuclear decommissioning costs are generally collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. The Utility files an application with the CPUC every three years requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear plants.

For costs related to Asset Retirement Obligations see “Nuclear Decommissioning Obligation” in Note 3 of the Notes to the Consolidated Financial Statements in item 8.

Electric Utility Operations

The Utility generates electricity and provides electric transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides “bundled” services (i.e., electricity, transmission and distribution services) to customers in its service territory. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. (For more information, see “Regulatory Matters” in Item 7. MD&A.)

Electricity Resources

The Utility is required to maintain capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is required to dispatch, or schedule all of the electric resources within its portfolio using least-cost dispatch.

The following table shows the percentage of the Utility’s total deliveries of electricity to customers in 2019 represented by each major electric resource, and further discussed below.

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Total 2019 actual electricity generated and procured (net) - 35,956 GWh (1):
Percent of Bundled Retail Sales (actual procurement)
Percent of Bundled Retail Sales (Power Content Label) (2)
Owned Generation Facilities
  Nuclear45.0 %41.7 %
Small Hydroelectric2.4 %2.2 %
Large Hydroelectric28.3 %26.3 %
Fossil fuel-fired17.6 %— %
  Solar0.8 %0.7 %
  Total94.1 %70.9 %
Qualifying Facilities
Renewable0.6 %0.6 %
Non-Renewable6.4 %— %
  Total7.0 %0.6 %
Irrigation Districts and Water Agencies
Small Hydroelectric0.1 %0.1 %
Large Hydroelectric— %— %
Total0.1 %0.1 %
Other Third-Party Purchase Agreements
  Renewable25.8 %23.8 %
Large Hydroelectric5.0 %4.6 %
Non-Renewable12.6 %— %
Total43.4 %28.4 %
Others, Net (2)(3)
(44.6)%— %
Total
100.0 %100.0 %
(1) This amount excludes electricity provided by direct access providers and CCAs that procure their own supplies of electricity for their respective customers.
(2) The allocation of bundled retail sale amounts and “Others, Net” in the “Power Content Label” column is consistent with current CEC guidelines, applied to specified electric generation and procurement volumes (i.e., fossil fuel-fired, nuclear, large hydroelectric, and renewable). Total reported generation and procurement volumes equate to actual electric retail sales.
(3) Amount is mainly comprised of net CAISO open market (sales)/purchases.

Renewable Energy Resources

California law established an RPS that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. In October 2015, the California Governor signed SB 350, the Clean Energy and Pollution Reduction Act of 2015 into law. SB 350 became effective January 1, 2016, and increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period, to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period, and in each three-year compliance period thereafter, unless changed by legislative action. SB 350 provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100 percent of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable from customers as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.

Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on actual procurement, which aligns with the methodology presented in the first column of the table above. Actual procurement from renewable energy sources was 29.7% in 2019. Per the Power Content Label methodology presented in the table above, 27.4% of the Utility’s energy deliveries were from renewable energy sources.

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The total 2019 renewable deliveries shown above were comprised of the following:
TypeGWhPercent of Bundled Retail Sales
Biopower1,322  3.7 %
Geothermal539  1.5 %
Wind3,412  9.5 %
RPS-Eligible Hydroelectric827  2.3 %
Solar4,574  12.7 %
Total10,674  29.7 %

Energy Storage

As required by California law, the CPUC established a multi-year energy storage procurement framework, including energy storage procurement targets to be achieved by each load-serving entity under the CPUC jurisdiction, including the Utility. Under the adopted energy storage procurement framework, the Utility is required to procure 580 MW of qualifying storage capacity by the end of 2021, with all energy storage projects required to be operational by the end of 2024.

The CPUC also adopted biennial interim storage targets for the Utility, beginning in 2014 and ending in 2020. Under the adopted framework, the Utility is required to submit biennial energy storage procurement plans to describe its strategy to meet its interim and total energy storage targets.

Through its procurements to date, the Utility has largely met its storage targets. The Utility expects to meet its remaining target through existing customer programs. This outcome may change in the future if projects under contract are terminated or if projects fail to be developed.

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Owned Generation Facilities

At December 31, 2019, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:
Generation TypeCounty LocationNumber of UnitsNet Operating Capacity (MW)
Nuclear (1):
  Diablo CanyonSan Luis Obispo 2,240  
Hydroelectric (2):
  Conventional16 counties in northern and central California102  2,679  
  Helms pumped storageFresno 1,212  
Fossil fuel-fired:
  Colusa Generating StationColusa 657  
  Gateway Generating Station Contra Costa 580  
  Humboldt Bay Generating StationHumboldt10  163  
Fuel Cell:
  CSU East Bay Fuel CellAlameda  
  SF State Fuel CellSan Francisco  
Photovoltaic (3):
Various13  152  
Total135  7,686  
(1) The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. The NRC operating licenses expire in 2024 and 2025, respectively. On January 11, 2018, the CPUC approved the Utility’s application to retire Unit 1 by 2024 and Unit 2 by 2025. (See “Diablo Canyon Nuclear Power Plant” in Item 7. MD&A and Item 3. Legal Proceedings.)
(2) The Utility’s hydroelectric system consists of 105 generating units at 66 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years.
(3) The Utility’s large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW ), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW). All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County.

Generation Resources from Third Parties

The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. (See “Ratemaking Mechanisms” above.) For more information regarding the Utility’s power purchase agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission

At December 31, 2019, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 33 electric transmission substations with a capacity of approximately 65,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO.

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Electricity Distribution

The Utility’s electric distribution network consists of approximately 107,000 circuit miles of distribution lines (of which, as of December 31, 2019, approximately 25% are underground and approximately 75% are overhead), 68 transmission switching substations, and 760 distribution substations, with a capacity of approximately 32,000 MVA. The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.

These distribution substations serve as the central hubs for the Utility’s electric distribution network. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution facilities to entities, such as municipal and other utilities, that resell the electricity. The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.
Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2017 to 2019 for electricity sold or delivered, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2019, 2018 or 2017.
201920182017
Customers (average for the year)5,457,101  5,428,318  5,384,525  
Deliveries (in GWh) (1) 
78,070  79,774  82,226  
Revenues (in millions):
   Residential$4,847  $5,051  $5,693  
   Commercial4,756  4,908  5,431  
   Industrial1,493  1,532  1,603  
   Agricultural1,106  1,234  1,069  
   Public street and highway lighting67  72  79  
   Other (2)
168  (720) (294) 
      Subtotal12,437  12,077  13,581  
Regulatory balancing accounts (3)
303  636  (344) 
Total operating revenues$12,740  $12,713  $13,237  
Selected Statistics:
Average annual residential usage (kWh)5,750  5,772  6,231  
Average billed revenues per kWh:
Residential$0.1762  $0.1838  $0.1936  
Commercial0.1585  0.1627  0.1716  
Industrial0.1015  0.1010  0.1055  
Agricultural0.2172  0.1968  0.2041  
Net plant investment per customer$8,375  $7,950  $7,486  
(1) These amounts include electricity provided by direct access providers and CCAs that procure their own supplies of electricity for their respective customers.
(2) This activity is primarily related to provisions for rate refunds and unbilled electric revenue, partially offset by other miscellaneous revenue items.
(3) These amounts represent revenues authorized to be billed.
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Natural Gas Utility Operations 

The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory.  Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as “core transport agents”).  When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers.  When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service.  Currently, more than 97% of core customers, representing approximately 82% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility generally does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility with which the Utility has a power purchase agreement that includes its generation fuel expense. The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers.  Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.  The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.
Natural Gas Supplies

The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility can also receive natural gas from fields in California. The Utility purchases natural gas to serve its core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have varied generally based on market conditions. During 2019, the Utility purchased approximately 282,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 20% of the total natural gas volume the Utility purchased during 2019.

Natural Gas System Assets

The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2019, the Utility’s natural gas system consisted of approximately 43,300 miles of distribution pipelines, over 6,300 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.

The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. interconnecting downstream with TransCanada Foothills Pipe Lines Ltd., B.C. System. The Foothills system interconnects at the border to the pipeline system owned by Gas Transmission Northwest, LLC, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility also has firm transportation agreements with Ruby Pipeline, LLC to transport natural gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border. Similarly, the Utility has a firm transportation agreement with Transwestern Pipeline Company, LLC to transport natural gas from supply points in the Southwestern United States to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona. (For more information regarding the Utility’s natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

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The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s transmission system.  The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later withdrawal.  In addition, four independent storage operators are interconnected to the Utility’s northern California transmission system. In 2019, the CPUC approved the discontinuation (through closure or sale) of operations at two gas storage fields. (For more information, see “Regulatory Matters - 2019 Gas Transmission and Storage Rate Case” in Item 7. MD&A.)

In 2019, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and continued its work on the final NTSB recommendation from its San Bruno investigation to hydrostatically test all high consequence pipeline mileage. The Utility currently plans to complete this NTSB recommendation by 2022 for remaining short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines.

Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2017 through 2019 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2019, 2018 or 2017.
201920182017
Customers (average for the year) (1)
4,518,209  4,495,279  4,467,657  
Gas purchased (MMcf)227,621  219,061  234,181  
Average price of natural gas purchased$2.08  $2.02  $2.3  
Bundled gas sales (MMcf):
  Residential162,876  156,917  160,969  
  Commercial54,479  51,357  50,329  
Total Bundled Gas Sales217,355  208,274  211,298  
Revenues (in millions):
Bundled gas sales:
  Residential$2,325  $2,042  $2,298  
  Commercial605  537  541  
  Other123  75  (25) 
Bundled gas revenues3,053  2,654  2,814  
Transportation service only revenue1,249  1,151  976  
      Subtotal4,302  3,805  3,790  
  Regulatory balancing accounts (2)
87  242  221  
Total operating revenues$4,389  $4,047  $4,011  
Selected Statistics:
Average annual residential usage (Mcf)38  38  38  
Average billed bundled gas sales revenues per Mcf:
  Residential$13.88  $12.67  $14.27  
  Commercial9.72  9.04  11.36  
Net plant investment per customer$3,522  $3,417  $3,093  
(1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.
(2) These amounts represent revenues authorized to be billed.

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Competition

Competition in the Electricity Industry

California law allows qualifying non-residential electric customers of investor-owned electric utilities to purchase electricity from energy service providers rather than from the utilities up to certain annual and overall GWh limits that have been specified for each utility. This arrangement is known as “direct access,” or DA. In 2018, the California legislature passed a bill to expand the statewide DA cap by 4,000 GWh, and directed the CPUC to consider whether DA should be further expanded, and to present a report on this matter to the legislature by June 30, 2020. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate and/or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility. On June 3, 2019, the CPUC issued an order implementing the 4,000 GWh increase for DA transactions, including an apportionment to the Utility’s service area of approximately 1,873 GWh. The CPUC is currently conducting a study to inform its recommendations to the legislature on implementing a further direct transaction reopening schedule and plans to issue a proposed decision on these issues on May 22, 2020.

The Utility continues to provide transmission, distribution, metering, and billing services to direct access customers, although these customers can choose to obtain metering and billing services from their energy service provider. The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of direct access and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers. SB 520 (codified at Section 387 of the Public Utilities Code), which was signed by the governor and became law on October 2, 2019, allows for a request to transfer the responsibilities of the provider of last resort obligation from investor-owned utilities to other entities.

The Utility is also impacted by the increasing viability of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering (“NEM”), which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, are increasing, putting upward rate pressure on remaining customers. New NEM customers are required to pay an interconnection fee, utilize time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. The CPUC has indicated that it intends to commence a new proceeding to revisit its rules related to NEM customers in 2020.

Further, in some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, may seek to acquire the Utility’s distribution facilities, through eminent domain (although eminent domain is stayed while the Utility is in Chapter 11, unless the Bankruptcy Judge lifts the stay). In 2019, three entities communicated an interest in acquiring certain Utility assets through a voluntary sale during the bankruptcy. It is also possible that some of the governmental entities interested in acquiring the Utility’s assets will construct duplicate distribution facilities to serve existing or potential new Utility customers.

The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.

The effect of such types of retail competition generally is to reduce the number of utility customers, leading to a reduction in the amount of electricity purchased from the Utility.

(For risks in connection with increasing competition, see Item 1A. Risk Factors.)

Competition in the Natural Gas Industry

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

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Environmental Regulation

The Utility’s operations are subject to extensive federal, state and local laws and requirements 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 activities, including the remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of CO2 and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. (See Item 1A. Risk Factors.) Generally, the Utility recovers most of the costs of complying with environmental laws and regulations in the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a ratemaking mechanism described in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

The Utility’s facilities are subject to various regulations adopted by the U.S. Environmental Protection Agency (EPA), including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended. The Utility is also subject to the regulations adopted by other federal agencies responsible for implementing federal environmental laws. The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies. These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors. Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, monitoring and paying for the harm caused to natural resources, and paying for the costs of health studies.

The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former manufactured gas plant sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.

For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Air Quality and Climate Change

The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, CO2, sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and other emissions.

Federal Regulation

At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions.

The federal administration of President Donald Trump has generated significant uncertainty with regard to what further actions may occur regarding climate change at the federal level. In the absence of policy at the federal level, the State of California has indicated that it intends to continue and enhance its leadership on climate change nationally and globally.

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State Regulation

California’s AB 32, the Global Warming Solutions Act of 2006, provides for the gradual reduction of state-wide GHG emissions to 1990 levels by 2020. The CARB has approved various regulations to achieve the 2020 target, including GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy.

The cap-and-trade program’s first compliance period, which began on January 1, 2013, applied to the electric generation and large industrial sectors. In the subsequent compliance period, which began on January 1, 2015, the scope of the regulation was expanded to include the natural gas and transportation sectors, effectively covering all of the state economy’s major sectors through 2020. The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than large natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation. In 2017, AB 398 extended the program through January 1, 2031. During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Entities with a compliance obligation can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside of the entities’ facilities through CARB-qualified offset projects such as reforestation or biomass projects.

SB 32 (2016) requires that CARB ensure a 40% reduction in greenhouse gases by 2030 compared to 1990 levels. In 2017, AB 398 extended the cap-and-trade program through 2030. The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers. The California RPS program that requires the utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California. In September 2018, SB 100 was signed into law, which accelerated the state’s 50% RPS target to December 31, 2026, increased the RPS target to 60% by December 31, 2030, and further amended the RPS statute to set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045.

Climate Change Resilience Strategies

During 2019, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to plan for the actions that it will need to take to increase its resilience in light of the impacts of climate change on the Utility’s operations. The Utility regularly reviews the most relevant scientific literature on climate change such as rising sea levels, major storm events, increasing temperatures and heatwaves, wildfires, drought and land subsidence, to help the Utility identify and evaluate climate change-related risks and develop the necessary resilience strategies. The Utility maintains emergency response plans and procedures to address a range of near-term risks, including wildfires, extreme storms, and heat waves and uses its risk-assessment process to prioritize infrastructure investments for longer-term risks associated with climate change. The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.

The Utility is working to better understand the current and future impacts of climate change. In 2017, the Utility filed its first RAMP submittal with the CPUC, which examined Utility safety risks. The Climate Resilience RAMP model indicated potential additional Utility safety consequences due to climate change, including in the near term. The Utility is conducting foundational work to help anticipate and plan for evolving conditions in terms of weather and climate-change related events. This work is guiding efforts to design a Utility-wide climate change risk integration strategy. This strategy will inform resource planning and investment, operational decisions, and potential additional programs to identify and pursue mitigations that will incorporate the resilience and safety of the Utility’s assets, infrastructure, operations, employees, and customers.

With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme, persistent, and frequent hot weather. The Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage are effective strategies for adapting to the expected changes in demand for electricity. The Utility is making substantial investments to build a more modern and resilient system that can better withstand extreme weather and related emergencies. Over the long term, the Utility also faces the risk of higher flooding and inundation potential at coastal and low elevation facilities due to projected sea level rise combined with high tides, storm runoff and storm surges. As the state continues to face increased risk of wildfires, the Utility’s activities, including vegetation management, will continue to play an important role to help reduce the risk of wildfire and its impact on electric and gas facilities.

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Climate scientists predict that climate change will result in varying temperatures and levels of precipitation in the Utility’s service territory. This could, in turn, affect the Utility’s hydroelectric generation. To plan for this potential change, the Utility is engaging with state and local stakeholders and is also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and collaborating on research and new modeling tools.

With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting.  In addition, the Utility continues to achieve reductions in methane emissions by implementing improvements in leak detection and repair, upgrades at metering and regulating stations, and maintenance and replacement of other pipeline materials.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2018, which is the most recent data available, totaled about 47 million metric tonnes of CO2 equivalent, more than three-quarters of which came from customer natural gas use. The following table shows the 2018 GHG emissions data the Utility reported to the CARB under AB 32, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.
Source
Amount (metric tonnes CO2 equivalent)
Fossil Fuel-Fired Plants (1)
2,512,130  
Natural Gas Compressor Stations and Storage Facilities (2)
299,256  
Distribution Fugitive Natural Gas Emissions 497,299  
Customer Natural Gas Use (3)
41,664,525  
(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.
(2) Includes emissions from compressor stations and storage facilities that are reportable to CARB.
(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the exception of gas delivered to other natural gas local distribution companies.

The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2018, which is the most recent data available, as compared to the national average for electric utilities:
Amount (pounds of CO2 per MWh)
U.S. Average (1)
998  
Pacific Gas and Electric Company (2)
206  
(1) Source: EPA eGRID.
(2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s estimated emissions rate.

Air Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised more than one-half of the Utility’s delivered electricity in 2018. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.
20182017
Total NOx Emissions (tons)134  155  
NOx Emissions Rate (pounds/MWh)0.010.01
Total SO2 Emissions (tons)
15  14  
SO2 Emissions Rate (pounds/MWh)
0.001  0.001  

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Water Quality

In 2014, the EPA issued final regulations to implement the requirements of the federal Clean Water Act that require cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts. Various industry and environmental groups challenged the federal regulations and they were upheld by the U.S. Court of Appeals for the Second Circuit. California’s once-through cooling policy adopted by the California Water Board in 2010 is considered to be at least as stringent as the new federal regulations and therefore governs implementation in California.

The California Water Board’s policy generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. The policy also provided for an alternative compliance approach for nuclear plants if certain criteria were met. As required by the policy, the California Water Board appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at Diablo Canyon. The committee’s consultant submitted its final report to the California Water Board in September 2014. The report addressed feasibility, costs and timeframes to install alternative technologies at Diablo Canyon, such as cooling towers.

On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon’s two nuclear power reactor units at the expiration of their current operating licenses in 2024 and 2025. The CPUC approved the retirement in January 2018. As a result of the planned retirement, the California Water Board will no longer need to address alternative compliance measures for Diablo Canyon. As required under the policy, the Utility will continue to pay an annual interim mitigation fee until operations cease in 2025.

Additionally, the Utility expects that its decision to retire Diablo Canyon will affect the terms of a final settlement agreement between the Utility, the Central Coast Regional Water Quality Control Board and the California Attorney General’s Office regarding the thermal component of the plant’s once-through cooling discharge. (For more information, see “Diablo Canyon Nuclear Power Plant” in Item 3. Legal Proceedings below.)

Nuclear Fuel Disposal

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities’ customers. The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay. As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel.

In September 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  The claim for the period June 1, 2018 through May 31, 2019, totaled approximately $19 million and is currently under review by the DOE.  Amounts reimbursed by DOE are refunded to customers through rates. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

ITEM 1A. RISK FACTORS

PG&E Corporation’s and the Utility’s financial results can be affected by many factors, including estimates and assumptions used in the critical accounting policies described in MD&A, that can cause their actual financial results to differ materially from historical results or from anticipated future financial results.  The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2019 Form 10-K.  Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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Risks Related to Chapter 11 Proceedings and Liquidity

PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 and are subject to the risks and uncertainties associated with their bankruptcy cases.

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. For the duration of the Chapter 11 Cases, the financial condition, results of operations, liquidity, and cash flows of PG&E Corporation and the Utility will be subject to various risks, including but not limited to the following:

the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility during the Chapter 11 Cases that satisfies all applicable legal requirements, including the requirements of AB 1054;

the ability to develop and obtain applicable Bankruptcy Court, creditor, and regulatory approval of a successful plan of reorganization and the effect of any alternative proposals, views, and objections of official committees, creditors, state and federal regulators, and other stakeholders, which may make it difficult to develop and consummate a successful plan of reorganization in a timely manner and by June 30, 2020;

the risk that the Noteholder RSA, the Subrogation RSA, the TCC RSA or the PSAs could be terminated;

the risk that the Backstop Commitment Letters or Debt Commitment Letters could be terminated or that the conditions precedent to funding thereunder are not satisfied or waived;

the risk that, if the CPUC fails to approve any settlements between PG&E Corporation and the Utility and the CPUC, PG&E Corporation’s and the Utility’s exit financing may be terminated, making it more difficult for PG&E Corporation and the Utility to emerge from Chapter 11 in a timely manner;

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

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

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

the ability to maintain or obtain sufficient financing sources for ongoing operations during the pendency of the Chapter 11 Cases or thereafter or to fund a plan of reorganization and meet future obligations, including the initial and annual contributions to the Wildfire Fund and commitments outlined in the Utility’s 2020 GRC, 2020-2022 WMP, and other regulatory proceedings;

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

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

risks associated with the potential liability arising from the 2019 Kincade fire and any other future post-petition wildfires or catastrophic events during the pendency of the Chapter 11 Cases;

risks associated with claims filed in the Chapter 11 Cases, including claims that have not yet been asserted, that do not specify an amount or in which the asserted amount exceeds the actual value of the claim, which present the potential for delays in the Chapter 11 Cases and which may make it difficult to assess the actual amount of the liability of PG&E Corporation or the Utility;

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

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potential increased difficulty in retaining and motivating key employees and potential increased difficulty in attracting new employees during the pendency of the Chapter 11 Cases and thereafter, including as a result of the challenging political and operating environment facing the company;

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

the ability to continue as a going concern.

PG&E Corporation and the Utility currently are and will continue to be subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have claims or interests in the Chapter 11 Cases that may be inconsistent with PG&E Corporation’s and the Utility’s plans. These risks and uncertainties could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows in various ways that cannot be predicted and may significantly increase the time PG&E Corporation and the Utility have to operate in Chapter 11. Because of the risks and uncertainties associated with the Chapter 11 Cases, it is not possible to predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, nor is it possible to predict the ultimate impact that events occurring during the Chapter 11 Cases may have on PG&E Corporation’s and the Utility’s corporate and capital structure.

PG&E Corporation and the Utility currently are and will continue to be required to seek approvals of the Bankruptcy Court and certain regulators in connection with the Chapter 11 Cases, and certain parties may object, intervene and protest approval, absent the imposition of terms or conditions to resolve their concerns. Such approvals may be denied, conditioned or delayed.

Operating under Chapter 11 may continue to restrict the ability of PG&E Corporation and the Utility to pursue strategic and operational initiatives.

Under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit PG&E Corporation’s and the Utility’s ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. These limitations include, among other things, PG&E Corporation’s and the Utility’s ability to:

make capital investments outside the normal course of business;

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

grant liens; and

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

PG&E Corporation and the Utility may continue to experience increased levels of employee attrition as a result of the filing of the Chapter 11 Cases.

As a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility have experienced and may continue to experience increased levels of employee attrition, and their employees will continue to face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation’s and the Utility’s ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with PG&E Corporation or the Utility, as applicable, through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of retention and incentive programs under the Bankruptcy Code. The loss of members of senior management could impair PG&E Corporation’s and the Utility’s ability to execute their strategies and implement operational initiatives, which would likely 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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As a result of the Chapter 11 Cases, PG&E Corporation’s and the Utility’s historical financial information may not be indicative of future financial performance.

PG&E Corporation’s and the Utility’s capital structure will likely be significantly altered under any plan of reorganization confirmed by the Bankruptcy Court. Under fresh-start accounting rules that may apply to PG&E Corporation and the Utility upon the effective date of a plan of reorganization, their assets and liabilities would be adjusted to fair value. Accordingly, if fresh-start accounting rules apply, PG&E Corporation’s and the Utility’s financial condition and results of operations following emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in their historical financial statements. In connection with the Chapter 11 Cases and the development of a plan of reorganization, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

If PG&E Corporation and the Utility are not able to consummate a consensual plan of reorganization, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by a protracted restructuring.

PG&E Corporation and the Utility commenced the Chapter 11 Cases without the benefit of a restructuring support agreement or agreed consensual plan of reorganization with any of its creditors or other key constituents. On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed their competing Ad Hoc Noteholder Plan. In connection with the Noteholder RSA (as defined below), the competing Ad Hoc Noteholder Plan was withdrawn on February 5, 2020. If the Noteholder RSA were to be terminated, or if a new competing plan of reorganization were filed by any constituents, the resulting competing plan process could reduce the likelihood that the plan of reorganization that is ultimately confirmed by the Bankruptcy Court is the Proposed Plan and, in any event, could have 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. Additionally, any RSAs entered into in connection with the Chapter 11 Cases are likely to be highly conditional on circumstances outside the control of PG&E Corporation and the Utility.

Accordingly, no assurance can be provided as to the length of time during which the Chapter 11 Cases will be pending, whether the Proposed Plan can be successfully consummated, how the terms of the Proposed Plan may change, whether the Proposed Plan will be the plan of reorganization that is ultimately consummated, how the proposed post-emergence capital structure may change, and what the effect of the Proposed Plan or any other plan of reorganization that is confirmed would have on PG&E Corporation and the Utility or on any of their respective equity, debt and other stakeholders, including as to matters of taxation and recovery or distributions upon consummation of any plan of reorganization.

Even if PG&E Corporation and the Utility are successful in obtaining confirmation of the Proposed Plan, the process has been, and will continue to be lengthy, costly and disruptive. A contested plan of reorganization proceeding would likely have a more pronounced material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows than a consensual plan of reorganization. Even if PG&E Corporation and the Utility are able to obtain requisite stakeholder approval, the Bankruptcy Court may not confirm a plan of reorganization.

The uncertainty surrounding the prolonged restructuring may also have other material effects on PG&E Corporation and the Utility including, but not limited to:

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

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

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

the ability of PG&E Corporation and the Utility to make capital expenditures, including to invest in initiatives necessary to ensure the continued safe operation of the business;

whether the Utility can qualify for the benefits under AB 1054, including obtaining the required state approvals by the statutory deadline;

whether PG&E Corporation is required to transfer control or ownership of the Utility or its business to a third party, such as the State of California or a third party monitor or receiver that is not accountable to PG&E Corporation’s board of directors or shareholders;

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

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

PG&E Corporation and the Utility may be subject to claims that will not be discharged in their Chapter 11 Cases, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all claims arising prior to its filing under Chapter 11. With few exceptions, all claims that arose prior to PG&E Corporation’s and the Utility’s Chapter 11 Cases: (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. PG&E Corporation and the Utility face several significant potential liabilities that arose after the start of the Chapter 11 Cases, including potential liabilities associated with the 2019 Kincade fire and the PSPS Program. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows on a post-reorganization basis and may cast substantial doubt on PG&E Corporation’s and the Utility’s ability to continue as a going concern.

The DIP Facilities may be insufficient to fund PG&E Corporation’s and the Utility’s cash requirements through their emergence from bankruptcy.

PG&E Corporation’s and the Utility’s liquidity, including PG&E Corporation’s and the Utility’s ability to meet their ongoing operational obligations, is dependent upon, among other things: (i) PG&E Corporation’s and the Utility’s ability to comply with the terms and conditions of any post-petition financing and cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 Cases, including the financing orders entered with respect to the DIP Credit Agreement, (ii) PG&E Corporation’s and the Utility’s ability to maintain adequate cash on hand, (iii) PG&E Corporation’s and the Utility’s ability to generate cash flow from operations, (iv) PG&E Corporation’s and the Utility’s ability to develop, confirm and consummate a plan of reorganization or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, PG&E Corporation and the Utility will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund any plan of reorganization and meet future obligations, and (ii) increased legal and other professional costs associated with the Chapter 11 Cases and the reorganization.

PG&E Corporation and the Utility have entered into the DIP Credit Agreement. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities (as defined below) on a final basis, authorizing the Utility 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 (as defined below), in each case subject to the terms and conditions of the DIP Credit Agreement. 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. For more information on the DIP Credit Agreement, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

The DIP Credit Agreement 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.

PG&E Corporation and the Utility have faced and will continue to face uncertainty regarding the adequacy of their liquidity and capital resources during the pendency of the Chapter 11 Cases, and have limited, if any, access to additional financing. PG&E Corporation and the Utility cannot provide assurance that cash on hand, cash flow from operations, distributions received from their subsidiaries and borrowings available under the DIP Credit Agreement will be sufficient to continue to fund operations during the pendency of the Chapter 11 Cases. Although the DIP Credit Agreement is expected to be sufficient to address liquidity needs for the expected duration of the Chapter 11 Cases, if the Chapter 11 Cases last longer than expected (particularly if the Proposed Plan is not confirmed by June 30, 2020) there can be no assurance that the DIP Credit Agreement will provide adequate liquidity for such scenario. The ability of PG&E Corporation and the Utility to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond their control. 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.

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The DIP Credit Agreement imposes a number of restrictions on PG&E Corporation and the Utility that may, among other things, limit their ability to conduct their business, or pursue new business opportunities and strategies. Additionally, PG&E Corporation and the Utility may be unable to comply with the covenants imposed by the DIP Credit Agreement. Such non-compliance could result in an event of default under the DIP Credit Agreement that, if not cured or waived, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The DIP Credit Agreement imposes a number of restrictions on PG&E Corporation and the Utility, including, among other things, affirmative covenants requiring PG&E Corporation and the Utility to provide financial information, cash flow forecasts, variance reports and other information to the administrative agent. The DIP Credit Agreement also contains general affirmative covenants such as compliance with all applicable laws, maintenance of licenses from necessary governmental authorities, maintenance of property and preservation of corporate existence. Negative covenants contained in the DIP Credit Agreement include restrictions on PG&E Corporation’s and the Utility’s ability to, among other things, incur additional indebtedness, create liens on assets, make investments, loans or advances, engage in mergers, consolidations, sales of assets and acquisitions, pay dividends and distributions, and make payments in respect of junior or pre-petition indebtedness, in each case subject to customary exceptions. The Utility’s ability to borrow under the DIP Credit Agreement is subject to the satisfaction of certain customary conditions precedent set forth therein. For more information on the DIP Credit Agreement, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

As a result of these covenants and restrictions, PG&E Corporation and the Utility may be limited in their ability to conduct their business, and respond to changing business, market, and economic conditions. These provisions may also limit PG&E Corporation’s and the Utility’s ability to pursue new business opportunities and strategies.

PG&E Corporation’s and the Utility’s ability to comply with these provisions may be affected by events beyond their control and their failure to comply, or obtain a waiver in the event PG&E Corporation or the Utility cannot comply with a covenant, could result in an event of default under the agreements governing the DIP Credit Agreement that, if not cured or waived, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Backstop Commitment Letters and the Debt Commitment Letters provide a number of conditions precedent to the obligations of the Backstop Parties and the Commitment Parties to fund the Proposed Plan as well as a number of termination rights for the Backstop Parties and the Commitment Parties. There can be no assurance that the conditions precedent will be satisfied or waived, or that events or circumstances will not occur that give rise to the termination rights. If the conditions precedent to funding cannot be satisfied or waived, or if the Backstop Commitment Letters or the Debt Commitment Letters are terminated, it could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Backstop Commitment Letters impose a number of conditions that must be satisfied before the Backstop Parties are obligated to fund the Proposed Plan. In addition, the Backstop Parties have certain termination rights under the Backstop Commitment Letters, which may be triggered by events beyond the control of PG&E Corporation and the Utility. The Debt Commitment Letters are also subject to numerous conditions precedent and termination rights, including certain conditions precedent and termination rights similar to those included in the Backstop Commitment Letters, as well as certain other conditions precedent, including that the Utility shall have received investment grade senior secured debt ratings. For more information on the Backstop Commitment Letters and the Debt Commitment Letters, including a summary of conditions precedent and termination rights, see “Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt Commitment Letters” in Note 2 of the Notes to the Consolidated Financial Statements.

If PG&E Corporation and the Utility fail to complete a monetization transaction utilizing any net operating losses or tax deductions resulting from the payment of pre-petition wildfire-related claims as contemplated in the Backstop Commitment Letters, 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, and PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

There can be no assurance that the conditions precedent set forth in the Backstop Commitment Letters or the Debt Commitment Letters will be satisfied or waived, or that events or circumstances will not occur that give rise to termination rights of the Backstop Parties or the Commitment Parties, which may be beyond the control of PG&E Corporation and the Utility.

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If the conditions precedent to funding under the Backstop Commitment Letters or the Debt Commitment Letters cannot be satisfied or waived, or if the Backstop Commitment Letters or Debt Commitment Letters are terminated, PG&E Corporation’s and the Utility’s ability to finance the Proposed Plan could be jeopardized, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Additionally, there can be no assurance that PG&E Corporation and the Utility would be able to obtain alternative financing to the transactions contemplated by the Backstop Commitment Letters and the Debt Commitment Letters.

PG&E Corporation’s and the Utility’s Consolidated Financial Statements have been prepared assuming that PG&E Corporation and the Utility will continue as going concerns. PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred during the past several years.  Uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. In addition, there is inherent uncertainty regarding the outcome of the Chapter 11 Cases. PG&E Corporation and the Utility have not included any financial statement adjustments that might result from the outcome of these uncertainties.

The accompanying Consolidated Financial Statements to this Annual Report on Form 10-K have been prepared assuming that PG&E Corporation and the Utility will continue as going concerns. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection. Management has concluded that these circumstances raise substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns, and their independent registered public accountants have included an explanatory paragraph in their auditors’ report which states certain conditions exist that raise substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns in relation to the foregoing. In addition, there is inherent uncertainty regarding the outcome of the Chapter 11 Cases. For further discussion of such uncertainty, see the risk factors above in “Risks Related to Chapter 11 Proceedings and Liquidity” in this Item 1A. PG&E Corporation’s and the Utility’s plans in regard to these matters are described in Note 2 of the Notes to the Consolidated Financial Statements in Item 8. The Consolidated Financial Statements do not include any adjustments that might result from the outcome of these uncertainties. See “Report of Independent Registered Public Accounting Firm” in Item 8.

Trading in PG&E Corporation’s and the Utility’s securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks.

Trading in PG&E Corporation’s and the Utility’s securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. The ultimate recovery, if any, by holders of PG&E Corporation’s or the Utility’s securities in the Chapter 11 Cases could differ substantially from any value that may be implied by the trading prices of such securities at any particular time during the pendency of the Chapter 11 Cases.

Risks Related to Wildfires

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the 2018 Camp fire, the 2017 Northern California wildfires and other pre-petition fires (including the 2015 Butte fire), notwithstanding the commencement of the Chapter 11 Cases.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the 2018 Camp fire, the 2017 Northern California wildfires and other pre-petition fires (including the 2015 Butte fire), notwithstanding the commencement of the Chapter 11 Cases. As disclosed below in Note 14 of the Notes to Consolidated Financial Statements in Item 8, PG&E Corporation and the Utility are subject to numerous lawsuits in connection with the 2018 Camp fire, the 2017 Northern California wildfires and other pre-petition fires by various plaintiffs, including wildfire victims, insurance carriers, and various government entities, under multiple theories of liability. These lawsuits generally assert that the Utility’s alleged failure to maintain and repair its distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire and 2017 Northern California wildfires.

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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. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. If the Subrogation RSA, TCC RSA or PSAs were to be terminated and litigation relating to the 2018 Camp fire, the 2017 Northern California wildfires and other pre-petition wildfires were to recommence, and the Utility’s facilities, such as its electric distribution and transmission lines, were 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, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility, including on PG&E Corporation’s and the Utility’s ability to develop and consummate a successful plan of reorganization. (See “The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows” below.) In addition to such 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, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility, including on PG&E Corporation’s and the Utility’s ability to develop and consummate a successful 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, non-consenting claimholders may still be able to challenge and otherwise impede the Proposed Plan. These settlement agreements could be terminated under various circumstances, some of which are beyond the PG&E Corporation’s and the Utility’s control. As described below in Note 14 of the Notes to Consolidated Financial Statements in Item 8, PG&E Corporation and the Utility have entered into agreements with major claimholders or their representatives to settle all pre-petition liabilities related to the 2018 Camp fire and 2017 Northern California wildfires (and in certain cases, other pre-petition fires) for an aggregate amount of $25.5 billion. These agreements are subject to numerous conditions and termination rights in favor of third parties, including, among others, (i) certain breaches by PG&E Corporation or the Utility, (ii) if PG&E Corporation or the Utility become insolvent, (iii) if the Proposed Plan is inconsistent with the terms of these agreements, (iv) if certain milestones are not met and (v) failure of the Proposed Plan or the treatment of claims contemplated thereby to be consistent with AB 1054. Certain of these agreements contain additional termination rights that are beyond the control of PG&E Corporation or the Utility. For example, the PSA with Supporting Public Entities may be terminated by the Supporting Public Entities if FEMA or the OES fail 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. If one or more of these settlement agreements is terminated, PG&E Corporation’s and the Utility’s aggregate liability related to the 2018 Camp fire and 2017 Northern California wildfires (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.

In addition, the TCC RSA is an agreement among PG&E Corporation and the Utility, the TCC, the Shareholder Proponents, and the Consenting Fire Claimant Professionals. No government entity (including FEMA and OES/Cal Fire) is party to the TCC RSA. Accordingly, there can be no assurance that such government entities will support the Proposed Plan or the treatment of their Fire Victim Claims in the Chapter 11 Cases as provided in the Proposed Plan. If FEMA, OES/Cal Fire, or other government entities that are not Supporting Public Entities do not support the Proposed Plan or treatment of their Fire Victim Claims, such claims could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 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 of 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.

Absent the settlement agreements noted above, potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various 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 and other damages the Utility may be responsible for if found negligent. Notwithstanding the Bar Date and the settlement agreements entered into as of the date of this filing, there remain 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 and the treatment of such claims in the Chapter 11 Cases.

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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 that may be imposed by government entities on PG&E Corporation and the Utility, the amount of such punitive damages, fines, penalties or restitution orders that may result from any criminal charges brought could be significant and could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as PG&E Corporation’s and the Utility’s ability to develop and consummate a successful plan of reorganization. In connection with the Wildfires OII, the Utility has agreed to remedies that will result in substantial capital expenditures that will not be subject to cost recovery. The Utility has 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 natural gas explosion that occurred in the City of San Bruno 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 or 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.

In addition, PG&E Corporation and the Utility could be the subject of additional lawsuits on account of obligations arising after the commencement of the Chapter 11 Cases and of additional investigations, citations, fines or enforcement actions in connection with the 2018 Camp fire and 2017 Northern California wildfires.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire and any future post-petition wildfire during the pendency of the Chapter 11 Cases.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire and future post-petition wildfires during the pendency of the Chapter 11 Cases.

As described below in Note 14 to the Consolidated Financial Statements under the heading “2019 Kincade fire,” while the cause of the 2019 Kincade fire remains under Cal Fire’s investigation and there are a number of unknown facts surrounding the cause of the 2019 Kincade fire, the Utility could be subject to significant liability in excess of insurance coverage that would 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. PG&E Corporation and the Utility have received and are responding to data requests from the CPUC’s SED relating to the Kincade fire. PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire.

Additionally, regardless of whether the Utility is ultimately determined to have caused the 2019 Kincade fire or any future post-petition wildfire during the pendency of the Chapter 11 Cases, PG&E Corporation’s and the Utility’s bankruptcy timing and process and the ability of the Utility to participate in the Wildfire Fund could be materially affected as a result of claims arising out of the 2019 Kincade fire. PG&E Corporation’s and the Utility’s ability to consummate the Proposed Plan by June 30, 2020 (or at all) could be impaired, and PG&E Corporation and the Utility may not be able to amend the Proposed Plan, or develop another alternative to the Proposed Plan, that could be confirmed by June 30, 2020 or at all. The Backstop Commitment Letters and the Debt Commitment Letters contain certain conditions precedent and termination rights that could be implicated by the 2019 Kincade fire and any future post-petition wildfire during the pendency of the Chapter 11 Cases. PG&E Corporation and the Utility may not be able to satisfy, or obtain a waiver of, such conditions precedent to the commitments, or the Backstop Parties or the Commitment Parties, respectively, may have the right to terminate such commitments, which would jeopardize PG&E Corporation’s and the Utility’s ability to finance the Proposed Plan. PG&E Corporation and the Utility may not be able to obtain alternative financing to the transactions contemplated by the Backstop Commitment Letters and the Debt Commitment Letters, and may not be able to obtain financing for an alternative plan that may be proposed by PG&E Corporation and the Utility after the impact of the 2019 Kincade fire is better known.

Finally, the 2019 Kincade fire or a future post-petition wildfire could have adverse consequences on the Utility’s probation proceeding, the Utility’s proceedings with the CPUC and FERC (including the Safety Culture OII and the Chapter 11 Proceedings OII), the criminal investigation into the 2018 Camp fire and future regulatory proceedings, including future applications for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment. For more information about the 2018 Camp fire and 2017 Northern California wildfires, see “2018 Camp fire and 2017 Northern California wildfires” in Note 14 of the Notes to Consolidated Financial Statements in Item 8.

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The amount of potential losses resulting from the impact of the 2018 Camp fire and 2017 Northern California wildfires is expected to greatly exceed the amount of PG&E Corporation’s and the Utility’s insurance coverage for wildfire events. The amount of potential losses resulting from the impact of the 2019 Kincade fire could also exceed the amount of PG&E Corporation’s and the Utility’s insurance coverage for wildfires. Securing liability insurance in future years is expected to be increasingly difficult and expensive, if available at all.

The amount of potential losses resulting from the impact of the 2018 Camp fire and 2017 Northern California wildfires is expected to greatly exceed the amount of PG&E Corporation’s and the Utility’s insurance coverage for wildfire events. The amount of potential losses resulting from the impact of the 2019 Kincade fire could also exceed the amount of PG&E Corporation’s and the Utility’s insurance coverage for wildfire events. Even if the Utility satisfies the eligibility and other requirements to participate in the Wildfire Fund under AB 1054, the recovery of any such excess losses from the Wildfire Fund would be capped at 40%.

PG&E Corporation and the Utility had 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. Further, PG&E Corporation and the Utility have 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 of August 1, 2019 through July 31, 2020, and $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. In addition, coverage limits within these wildfire insurance policies could result in further material self-insured costs in the event each fire were deemed to be a separate occurrence under the terms of the insurance policies.

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 September 2, 2020 is approximately $212 million, compared to the approximately $50 million that the Utility recovered in rates during the year ended December 31, 2019. 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. In addition, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and 2017 Northern California wildfires will greatly exceed their available insurance, and the Utility could also be subject to significant liability in excess of insurance in connection with the 2019 Kincade fire. For a discussion of the potential magnitude of PG&E Corporation’s and the Utility’s liability, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the 2018 Camp fire and the 2017 Northern California wildfires and other pre-petition fires (including the 2015 Butte fire), notwithstanding the commencement of the Chapter 11 Cases” and “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire and any future post-petition wildfire during the pendency of the Chapter 11 Cases.” above.

PG&E Corporation and the Utility also expect to face increasing difficulty securing liability insurance in future years due to availability and to face significantly increased insurance costs.

If the Utility is unable to recover all or a significant portion of its excess costs in connection with the 2019 Kincade fire, the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire through ratemaking mechanisms and in a timely manner, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

As of December 31, 2019, the Utility incurred substantial costs in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire in excess of costs currently in rates, some of which currently are or are expected to be recorded in the future in its WEMA account. The Utility could similarly incur substantial costs in excess of insurance coverage in the future in connection with the 2019 Kincade fire.

There can be no assurance that the Utility will be allowed to recover costs in excess of insurance, including costs recorded in those accounts in the future, 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.

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SB 901, signed into law on September 21, 2018, required the CPUC to establish a 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. SB 901 also authorized 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 CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs, as the bill does not address fires that occurred in 2018.

After a CPUC July 8, 2019 decision determined that a utility that has filed for relief under Chapter 11 cannot access the CHT, on August 7, 2019, the Utility submitted to the CPUC an application for rehearing of that decision, the outcome of which is uncertain. For more information on the OIR, see “OIR to Implement Public Utilities Code Section 451.2 Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901” in Item 7. MD&A.

The inability to recover all or a significant portion of costs in excess of insurance through increases in rates and by collecting such rates 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.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of further non-compliance with the terms of probation or in the event of further modifications to the conditions of probation.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of further non-compliance with the terms of probation or in the event of further modifications to the conditions of probation. On January 26, 2017, following the federal criminal trial against the Utility in connection with the San Bruno explosion, in which the Utility was found guilty on six felony counts, the Utility was sentenced to, among other things, a five-year corporate probation period and oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years. 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 a third-party monitor at the Utility’s expense. The goal of the third-party 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.

In 2018 and 2019, the court overseeing the Utility’s probation issued various orders related to the Utility’s probation, including a finding that the Utility had violated a condition of its probation with respect to reporting requirements, and imposing new conditions of probation. For more information about the Utility’s probation and the court’s orders, see “U.S. District Court Matters and Probation” in Item 3. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases.

The Utility could incur material costs, not recoverable through rates, in the event of further non-compliance with the terms of its probation and in connection with the monitorship (including but not limited to costs resulting from recommendations of the third-party monitor). The Utility could also incur material costs, not recoverable through rates, in the event of further modifications to the conditions of its probation, such as those proposed by the court overseeing the Utility’s probation on January 16, 2020, relating to the hiring of additional contractors to ensure full compliance with certain vegetation management conditions.

The outcome of probation could harm the Utility’s relationships with customers, regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management. Further, it could negatively affect the outcome of future ratemaking and regulatory proceedings and result in increased regulatory or legislative scrutiny, including with respect to various aspects of how the Utility’s business is conducted or organized. (See “Enforcement and Litigation Matters” in Item 7. MD&A.)

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The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

California law includes a doctrine of inverse condemnation that is routinely invoked in California. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines. 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 benefitted from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Plaintiffs have asserted the doctrine of inverse condemnation in lawsuits related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire, and courts have ruled that the doctrine can apply to PG&E Corporation and the Utility in those matters. While the Utility currently continues to litigate this issue, there can be no assurance that the Utility will be successful in overturning the rulings that inverse condemnation applies in the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire or other litigation against PG&E Corporation or the Utility.

Furthermore, a court could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. Although the imposition of liability under the doctrine of inverse condemnation is premised on the assumption that utilities have the ability to automatically recover these costs from their customers, there can be no assurance that the CPUC would authorize cost recovery whether or not a previous court decision had imposed liability on a utility under the doctrine of inverse condemnation. (In December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to the CPUC’s prudent manager standard. That determination was challenged by San Diego Gas & Electric as well as by the Utility and Southern California Edison. In October 2019, the U.S. Supreme Court declined to review the case, effectively ending the challenge.)

If PG&E Corporation or the Utility were to be found liable for damages under the doctrine of inverse condemnation, but the Utility was unable to secure a cost recovery decision from the CPUC to pay for such costs through increases in rates or to collect such rates in a timely manner, the financial condition, results of operations, liquidity, and cash flows of PG&E Corporation and the Utility would be materially affected by potential losses resulting from the impact of the 2019 Kincade fire, and, if the TCC RSA, Subrogation RSA, or PSAs were to be terminated, the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. (See “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the 2018 Camp fire, the 2017 Northern California wildfires and other pre-petition fires (including the 2015 Butte fire), notwithstanding the commencement of the Chapter 11 Cases,” and “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire and any future post-petition wildfire during the pendency of the Chapter 11 Cases” above.)

PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of the Utility’s implementation of its PSPS program.

As outlined in the 2019 Wildfire Mitigation Plan, PG&E Corporation and the Utility have adopted the PSPS program to proactively de-energize lines that traverse areas under elevated and extreme risks for wildfire when forecasts predict extreme fire-threat conditions. In addition to the 2019 PSPS events, the Utility expects that PSPS events will be necessary in 2020 and future years. Approximately 5.4 million electric customer premises may potentially be impacted by PSPS events.

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Since June 2019, PG&E Corporation and the Utility have carried out several PSPS events. These PSPS events have been subject to 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. The Utility also is the subject of a class action litigation in connection with the 2019 PSPS events that was filed in the Bankruptcy Court in December of 2019. On January 24, 2020, the assigned ALJ issued a proposed decision in the 2020 Energy Resource Recovery Account (ERRA) Forecast proceeding that, if finalized, would require the Utility to include in its application for the 2019 ERRA Compliance Review an accounting of the PSPS events that occurred in its service territory in 2019 and how the PSPS impacted its revenue collections. Also, on January 27, 2020, the California state senate approved SB 378 that, if passed by the assembly and then enacted into law, would require the CPUC, on or before June 1, 2021, to establish a procedure for customers, local governments, and others affected by a de-energization event to recover specified costs incurred as a result of the de-energization event from an electrical corporation within specified time periods. The bill would also require the CPUC to establish rules determining whether these payments can be recovered from ratepayers.

In addition, the proposal 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 specified costs incurred 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.

PG&E Corporation and the Utility cannot predict the timing and outcome of the OII, order to show cause, the class action litigation, and pending litigation. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility’s implementation of its PSPS program, including with respect to the October 9, 2019 PSPS event, which could result in fines, penalties, customer rebates or other payments. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future)) or liability for damages 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 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.

Risks Related to the Outcome of Other Enforcement Matters, Investigations, and Regulatory Proceedings

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. After a CPUC July 8, 2019 decision determined that a utility that has filed for relief under Chapter 11 cannot access the CHT, on August 7, 2019, the Utility submitted to the CPUC an application for rehearing of that decision, the outcome of which is uncertain. 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 7. 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.  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 7. MD&A.)

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On July 12, 2019, the California Governor signed into law AB 1054, which, among other policy reforms, provides for the establishment of a statewide fund that is 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 and even if the Utility were eligible to do so, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including 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, and that the Wildfire Fund has sufficient remaining funds.

The costs of participating in the Wildfire Fund (should the Utility be eligible to do so) are expected to exceed $6.7 billion over the anticipated ten-year life of the fund. The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the timing of resolution of the Chapter 11 Cases. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on 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 participating electric utility. 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 revised some of the SB 901 requirements regarding wildfire mitigation plans, including creating a Wildfire Safety Division to review future plans and that plans should cover a three-year period.

Also, in June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. On October 11, 2019, the State of California announced proposed regulations which provide guidance on the requirements of the CCPA. 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. Failure to comply with the CCPA could result in fines imposed on PG&E Corporation and the Utility that could be material.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by the ability of PG&E Corporation and the Utility to participate in the Wildfire Fund under AB 1054, which is subject to numerous uncertainties and which could involve significant organizational or governance changes.

The Utility’s ability to participate in the Wildfire Fund is subject to numerous eligibility and other requirements set forth in AB 1054, including, among others, (a) the Utility’s Chapter 11 Case has been resolved pursuant to a plan of reorganization by June 30, 2020, (b) the CPUC has approved the Utility’s plan of reorganization, 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, and (c) the CPUC has determined that the Utility’s plan of reorganization is (i) consistent with California’s climate goals and (ii) neutral, on average, to the Utility’s ratepayers. (See “Assembly Bill 1054” in Item 7. MD&A.) There can be no assurance that PG&E Corporation and the Utility will be able to meet these eligibility and other requirements for participating in the Wildfire Fund, including that the CPUC will issue the necessary approvals or make the necessary determinations.

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”). The scope of the Chapter 11 Proceedings OII includes, among others, any regulatory approvals required in order for PG&E Corporation and the Utility to become eligible to participate in the Wildfire Fund and any other regulatory approvals required by AB 1054. PG&E Corporation and the Utility cannot predict the outcome of the Chapter 11 Proceedings OII.

Additionally, PG&E Corporation’s and the Utility’s ability to meet the eligibility and other requirements may be adversely impacted by the California Governor’s review of the Proposed Plan that PG&E Corporation and the Utility filed with the Bankruptcy Court on January 31, 2020.

Failure to meet the eligibility conditions to access relief under the Wildfire Fund, including satisfaction of the eligibility requirements described above and the Utility making its 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, and 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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The Utility is subject to extensive regulations and the risk of enforcement proceedings in connection with compliance with such regulations. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by the outcomes of the CPUC’s investigative enforcement proceedings against the Utility, other known enforcement matters, and other ongoing state and federal investigations and requests for information.

The Utility is subject to extensive regulations, including federal, state and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with the Wildfires OII, the locate and mark OII, the order to show cause related to the 2019 PSPS events, the safety culture OII, and other matters that the CPUC’s SED may be investigating. The SED could launch investigations at any time on any issue it deems appropriate. Such proceedings are likely 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.

The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it may impose the maximum statutory penalty of $50,000, per penalty, per day, with an administrative limit of $8 million per citation issued. For offenses occurred after January 1, 2019, the maximum statutory penalty is $100,000, per penalty, per day. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED may also issue multiple citations per violation or address multiple violations in a single citation. While it is uncertain how the CPUC would calculate the number of violations or the penalty for any violations, such fines or penalties could be significant and materially affect PG&E Corporation’s and the Utility’s liquidity and results of operations. (See “Regulatory Environment” in Item 1. Business and Note 15 to the Consolidated Financial Statements in Item 8.)

The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and resource adequacy requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC general orders or other applicable CPUC decisions or regulations; federal electric reliability standards; and environmental compliance. CPUC staff could also impose penalties on the Utility in the future in accordance with its authority under the gas and electric safety citation programs. The amount of such fines, penalties, or customer refunds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. (See “Risks Related to Wildfires,” above.) The Utility is unable to predict the outcome of pending investigation, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.

If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties the amount of which could be substantial and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the Utility’s violations. (See also “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of non-compliance with the terms of probation or in the event of modifications to the conditions of probation” above.)

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PG&E Corporation’s and the Utility’s financial results primarily depend on the outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its operating expenses and capital expenditures so that it is able to earn its authorized rate of return in a timely manner.

As a regulated entity, the Utility’s rates are set by the CPUC or the FERC on a prospective basis and are generally designed to allow the Utility to collect sufficient revenues to recover reasonable costs of providing service, including a return on its capital investments. PG&E Corporation’s and the Utility’s financial results could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility to safely and reliably serve its customers and earn its authorized ROE. The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services. Further, an increase in the amount of capacity located in the Utility’s service territory that is procured by the CAISO under Reliability Must Run (“RMR”) contracts could increase the Utility’s costs of procuring capacity needed for reliable service to its customers.

In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility’s actual costs to safely and reliably serve its customers differ from authorized or forecast costs. The Utility may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), or compliance with new state laws or policies. Although the Utility may be allowed to recover some or all of the additional costs, there may be a substantial delay between when the Utility incurs the costs and when the Utility is authorized to collect revenues to recover such costs. Alternatively, the CPUC or the FERC may disallow costs that they determine were not reasonably or prudently incurred by the Utility.

The Utility also is required to incur costs to comply with legislative and regulatory requirements and initiatives, such as those relating to the development of a state-wide electric vehicle charging infrastructure, the deployment of distributed energy resources, implementation of demand response and customer energy efficiency programs, energy storage and renewable energy targets, underground gas storage, and the construction of the California high-speed rail project. The Utility’s ability to recover costs, including its investments, associated with these and other legislative and regulatory initiatives will depend, in large part, on the final form of legislative or regulatory requirements, and the associated ratemaking mechanisms associated with these initiatives, including the timely adjustment of such mechanisms to reflect any lowered customer demand for the Utility’s electricity and natural gas services.

PG&E Corporation’s and the Utility’s financial results depend upon the Utility’s continuing ability to recover “pass-through” costs, including electricity and natural gas procurement costs, from customers in a timely manner. The CPUC may disallow procurement costs for a variety of reasons. In addition, the Utility’s ability to recover these costs could be affected by the loss of Utility customers and decreased new customer growth, if the CPUC fails to adjust the Utility’s rates to reflect such events.

The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility’s own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market.  The Utility must manage these sources using the commercial and CPUC regulatory principles of “least cost dispatch” and prudent administration of power purchase agreements in compliance with its CPUC-approved long-term procurement plan. The CPUC could disallow procurement costs incurred by the Utility if the CPUC determines that the Utility did not comply with these principles or if the Utility did not comply with its procurement plan.

Further, the contractual prices for electricity under the Utility’s current or future power purchase agreements could become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to adverse economic conditions or the loss of the Utility’s customers to other retail providers. Despite the CPUC’s current approval of the contracts, the CPUC could disallow contract costs in the future if it determines that the terms of such contracts, including price, do not meet the CPUC reasonableness standard.

The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by whether the CAISO wholesale electricity market continues to function effectively. Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended which could result in excessive market prices.  The CPUC could prohibit the Utility from passing through the higher costs of electricity to customers.

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Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreasing bundled load that occurs through municipalization of the Utility’s facilities, an increase in the number of CCAs that provide electricity to their residents, and an increase in the number of consumers who become direct access customers of alternative generation providers. (See “Competition in the Electricity Industry” in Item 1.) As the number of bundled customers (i.e., those customers who receive electricity and distribution service from the Utility) declines, the rates for remaining customers could increase as the Utility would have a smaller customer base from which to recover certain procurement costs. Although the Utility is permitted to collect non-bypassable charges for above market generation-related costs incurred on behalf of former customers, the charges may not be sufficient for the Utility to fully recover these costs. In addition, the Utility’s ability to collect non-bypassable charges has been, and may continue to be, challenged by certain customer groups. Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.

In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer NEM, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, puts upward rate pressure on remaining customers, who may incur significantly higher bills due to an increase in customers seeking alternative energy providers.

A confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments. If the number of the Utility’s customers decreases or grows at a slower rate than anticipated, the Utility’s level of authorized capital investment could decline as well, leading to a slower growth in rate base and earnings. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could materially affect PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows.
Further, changes in commodity prices also may have an adverse effect on the Utility’s ability to timely recover its operating costs and earn its authorized ROE.  Although the Utility generally recovers its electricity and natural gas procurement costs from customers as “pass-through” costs, a significant and sustained rise in commodity prices could create overall rate pressures that make it more difficult for the Utility to recover its costs that are not categorized as “pass-through” costs.  To relieve some of this upward rate pressure, the CPUC could authorize lower revenues than the Utility requested or disallow full cost recovery.

If the Utility is unable to recover a material portion of its procurement costs and/or if the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, the wide deployment of distributed generation, and the development of new electricity generation and energy storage technologies, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

Risks Related to Operations and Information Technology

The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system.  (See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. Business above.)  The Utility’s ability to earn its authorized ROE depends on its ability to efficiently maintain, operate, and protect its facilities, and provide electricity and natural gas services safely and reliably.  The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities.  In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives, and the CPUC approved retirement of Diablo Canyon by 2024 and 2025.

The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from:

the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption or other catastrophic events;

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

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

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

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

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

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

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

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

operator or other human error;

a motor vehicle incident involving a Utility vehicle (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences;

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

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

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

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

The occurrence of any of these events could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death.  As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties.  Any of such incidents also could lead to significant claims against the Utility.

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The adverse impact of the occurrence of any of these events may be exacerbated by the difficulty PG&E Corporation and the Utility may experience in making sufficient capital expenditure as a result of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, the Utility’s ability to finance capital expenditures and pay other ongoing expenses will primarily depend on the levels of its operating cash flows and availability under the DIP Credit Agreement. In the event that PG&E Corporation’s and the Utility’s capital needs increase materially due to unexpected events or transactions including but not limited to the events described above, additional financing outside of the DIP Facilities may be required, and there can be no assurance that PG&E Corporation and the Utility will be able to obtain such additional financing on favorable terms or at all, or that such additional financing will be approved by the Bankruptcy Court. In the event that PG&E Corporation and the Utility are unable to obtain such additional financing on favorable terms or at all, or are unable to obtain Bankruptcy Court approval of such additional financing, PG&E Corporation and the Utility may be unable to make necessary capital expenditures in connection with the occurrence of any of the above events. For more information on PG&E Corporation’s and the Utility’s material commitments for capital expenditures, see “Regulatory Matters” in Item 7. MD&A.

Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, the Utility may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders.  The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.

Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject.  An uninsured loss could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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 2019 Kincade fire, 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.

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The electric power and gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy.  The electric grid is a critical enabler of the adoption of new energy technologies that support California’s climate change and GHG reduction objectives, which continue to be publicly supported by California policymakers.  California's environmental policy objectives are accelerating the pace and scope of the industry change.  For instance, SB 100, which was signed into law on September 10, 2018, increases from 50% to 60%, the percentage of California’s electricity portfolio that must come from renewables by 2030. SB 100 establishes a further goal to have an electric grid that is entirely powered by clean energy by 2045. California utilities also are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies.  These developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid’s capacity, and interconnect DERs.

In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and state infrastructure modernization (e.g., rail and water projects).

To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs and, consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. The CPUC also authorized development of two new, five-year programs aimed at accelerating widespread electric vehicle adoption and combating climate change. The new programs will increase fast charging options for consumers as well as electric charging infrastructure for non-light-duty fleet vehicles.

In addition, in light of the state’s commitment to clean energy and carbon neutral economy by 2045, California has recently proposed public policies that prohibit or restrict the use and consumption of natural gas, for example in buildings, that will have for effect to reduce the use of natural gas. Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer be “used and useful,” potentially causing substantial investment value of gas assets to be stranded. (Under the CPUC rules, when an asset no longer meets the standard of “used and useful,” the utility no longer recovers the costs from its customers or earns the associated rate of return.) However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. Inability by the Utility to recover in rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

The industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

A cyber incident, cyber security breach, severe natural event or physical attack on the Utility’s operational networks and information technology systems could have a material effect on its financial condition, results of operations, liquidity, and cash flows.

The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks.  Private and public entities, such as the North American Electric Reliability Corporation, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency.  The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems.  Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.

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The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California’s electricity market related to grid modernization and customer choice. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.

The Utility and its third-party vendors have been subject to, and will likely continue to be subject to, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations.  None of these breaches or attempts has individually or in the aggregate resulted in a security incident with a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.  Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations.  Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents.  However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements change or the facilities cease operations before the licenses expire.

The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses 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 Utility may be required under federal law to pay up to $275 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States. 

On January 11, 2018, the CPUC approved the retirement of Diablo Canyon units by 2024 and 2025. However, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation. As a result, operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before their respective licenses expire in 2024 and 2025. In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge 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, in order to retain highly skilled personnel necessary to safely operate Diablo Canyon during the remaining years of operations, the Utility will incur costs in connection with (i) an employee retention program to ensure adequate staffing levels at Diablo Canyon, which program has been approved by the CPUC, and (ii) an employee retraining and development program, to facilitate redeployment of a portion of Diablo Canyon personnel to the decommissioning project and elsewhere in the Utility. There can be no assurance that the Utility will be successful in retaining highly skilled personnel under its employee programs.

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The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders.  (See “Regulatory Environment” in Item 1. Business above.)  If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial results could be materially affected.  The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions.  The Utility may incur a material charge if it ceases operations at Diablo Canyon’s two nuclear generation units before their respective licenses expire in 2024 and 2025. At December 31, 2019, the Utility’s unrecovered investment in Diablo Canyon was $1.6 billion.

The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives.  (See Note 3: Summary of Significant Accounting Policies - “Asset Retirement Obligations” of the Notes to the Consolidated Financial Statement in Item 8.)  The CPUC authorizes the Utility to recover its estimated costs to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.  If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

For certain critical technologies, products and services, the Utility relies on a limited number of suppliers and, in some cases, sole suppliers.  In the event these suppliers are unable to perform, the Utility could experience delays and disruptions in its operations while it transitions to alternative plans or suppliers.

The Utility relies on a limited number of sole source suppliers for certain of its technologies, products and services.  Although the Utility has long-term agreements with such suppliers, if the suppliers are unable to deliver these technologies, products or services, the Utility could experience delays and disruptions while it implements alternative plans and makes arrangements with acceptable substitute suppliers.  As a result, the Utility’s business, financial condition, and results of operations could be materially affected.  As an example, the Utility relies on Westinghouse Electric Company LLC (acquired in 2018 by Brookfield Business Partners L.P.) for its nuclear fuel assemblies, and Silver Spring Networks, Inc. and Aclara Technologies LLC as suppliers of proprietary SmartMeter™ devices and software, and of managed services, utilized in its advanced metering system that collects electric and natural gas usage data from customers.  If these suppliers encounter performance difficulties or are unable to supply these devices or maintain and update their software, or provide other services to maintain these systems, the Utility’s metering, billing, and electric network operations could be impacted and disrupted.

The Utility may be required to incur substantial costs in order to obtain or renew licenses and permits needed to operate the Utility’s business and the Utility may be subject to fines and penalties for failure to comply or obtain license renewal.

The Utility must comply with the terms of various governmental permits, authorizations, and licenses, including those issued by the FERC for the continued operation of the Utility’s hydroelectric generation facilities, and those issued by environmental and other federal, state and local governmental agencies. Many of the Utility’s capital investment projects, and some maintenance activities, often require the Utility to obtain land use, construction, environmental, or other governmental permits. These permits, authorizations, and licenses may be difficult to obtain on a timely basis, causing work delays. Further, existing permits and licenses could be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, the Utility often seeks periodic renewal of a license or permit, such as a waste discharge permit or a FERC operating license for a hydroelectric generation facility.

If a license or permit is not renewed for a particular facility and the Utility is required to cease operations at that facility, the Utility could incur an impairment charge or other costs. Before renewing a permit or license, the issuing agency may impose additional requirements that may increase the Utility’s compliance costs. In particular, in connection with a license renewal for one or more of the Utility’s hydroelectric generation facilities or assets, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility.

In addition, local governments may attempt to assert jurisdiction over various utility operations by requiring permits or other approvals that the Utility has not been previously required to obtain. 

The Utility may incur penalties and sanctions for failure to comply with the terms and conditions of licenses and permits which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, licenses, ordinances, or other requirements, or if the Utility cannot recover the increase in associated compliance and other costs in a timely manner, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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Risks Related to Environmental Factors

Severe weather conditions, extended drought and shifting climate patterns could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Extreme weather, prior extended drought and shifting climate patterns have intensified the challenges associated with wildfire management in California. The Utility’s service territory encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as prior drought conditions followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihood and severity of extraordinary wildfire events.  In California, over the past five years, inconsistent and extreme precipitation, coupled with more hot days, have increased the wildfire risk and made wildfire outbreaks increasingly difficult to manage.  In particular, the risk posed by wildfires has increased in the Utility’s service area as a result of a prior extended period of drought, bark beetle infestations in the California forest and wildfire fuel increases due to record rainfall following the drought, and strong wind events, among other environmental factors. Contributing factors other than environmental can include local land use policies and historical forestry management practices.  The combined effects of extreme weather and climate change also impact this risk. For example, in 2017, there were nearly double the number of wildfires in California than the annual average, including five of the most devastating wildfires in California’s history. On January 19, 2018, the CPUC approved a statewide fire-threat map that shows that approximately half of the Utility’s service territory is facing “elevated” or “extreme” fire danger. Approximately 25,000 circuit miles of the Utility’s nearly 81,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such high-fire threat areas, significantly more in total than other California IOUs.

Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, heat waves, drought, earthquakes, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, or other natural disasters such as wildfires, could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to PG&E Corporation and the Utility.  Any such event could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.  Any of such events also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices and/or the failure of electric and other equipment of the Utility.

Further, the Utility has been studying the potential effects of climate change (increased temperatures, changing precipitation patterns, rising sea levels) on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most significant.  Scientists project that climate change will increase electricity demand due to more extreme, persistent and hot weather.  As a result, the Utility’s hydroelectric generation could change and the Utility would need to consider managing or acquiring additional generation.  If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, flooding caused by rising sea levels could damage the Utility’s facilities, including gas, generation, and electric transmission and distribution assets.  The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries.  The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase.

Events or conditions caused by climate change could have a greater impact on the Utility’s operations than the Utility’s studies suggest and could result in lower revenues or increased expenses, or both.  If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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The Utility’s operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation’s and the Utility’s financial results.

The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, and orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife. The Utility incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations. The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions.

The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.

Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. (See “Environmental Regulation” in Item 1. and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial results. Their financial results also can be materially affected by changes in estimated costs and by the extent to which actual remediation costs differ from recorded liabilities.

State climate policy requires reductions in greenhouse gases of 40% by 2030 and 80% by 2050.  Various proposals for addressing these reductions have the potential to reduce natural gas usage and increase natural gas costs, which may impact the future of natural gas services. The future recovery of the increased costs associated with compliance is uncertain.

The CARB is the state’s primary regulator for GHG emission reduction programs.  Natural gas providers have been subject to compliance with CARB’s Cap-and-Trade Program since 2015, and natural gas end-use customers have an increasing exposure to carbon costs under the Program through 2030 when the full cost will be reflected in customer bills. CARB’s Scoping Plan also proposes various methods of reducing GHG emissions from natural gas.  These include more aggressive energy efficiency programs to reduce natural gas end use, increased renewable portfolio standards generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances, leading to further reduced demand.  These natural gas load reductions may be partially offset by CARB’s proposals to deploy natural gas to replace wood fuel in home heating and diesel in transportation applications.  CARB also proposes a displacement of some conventional natural gas with above-market renewable natural gas.  The combination of reduced load and increased costs could result in higher natural gas customer bills and a potential mandate to deliver renewable natural gas could lead to cost recovery risk. In addition, local city governments have passed ordinances restricting use of natural gas in new construction, and if other jurisdictions follow suit, this could affect future demand for the provision of natural gas.

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Other Risk Factors

Poor investment performance or other factors could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension plan, other postretirement benefits plans, and nuclear decommissioning trusts.

PG&E Corporation and the Utility provide defined benefit pension plans and other postretirement benefits for eligible employees and retirees. The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities. The performance of the debt and equity markets affects the value of plan assets and trust assets. A decline in the market value may increase the funding requirements for these plans and trusts. The cost of providing pension and other postretirement benefits is also affected by other factors, including interest rates used to measure the required minimum funding levels, the rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, future government regulation, and prior contributions to the plans. Similarly, funding requirements for the nuclear decommissioning trusts are affected by the rates of return on trust assets, changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements as well as changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment. (See Note 3: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in Item 8.) If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans or if actual nuclear decommissioning costs exceed the amount of nuclear decommissioning trust funds and the Utility is unable to recover the contributions or additional costs in rates, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

The Utility’s success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees. PG&E Corporation’s and the Utility’s results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.

The Utility’s workforce is aging and many employees are or will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may be faced with a shortage of experienced and qualified personnel. The majority of the Utility’s employees are covered by collective bargaining agreements with three unions. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements with the unions or if tentative new agreements are not ratified by their members. In addition, some of the remaining non-represented Utility employees could join one of these unions in the future.

PG&E Corporation and the Utility also may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the ongoing enforcement proceedings and the Chapter 11 Cases. Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility’s business activities are concentrated in one region, as a result of which, its future performance may be affected by events and factors unique to California.

The Utility’s business activities are concentrated in Northern California. As a result, the Utility’s future performance may be affected by events and economic factors unique to California or by regional regulation or legislation, including, for example, the doctrine of inverse condemnation. (See “The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation and the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows” above.)

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’s electricity and natural gas distribution facilities, electric generation facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, which are described in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.” The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies 11 million square feet of real property, including 9 million square feet owned by the Utility. The Utility’s corporate headquarters comprises approximately 1.7 million square feet located in several Utility-owned buildings in San Francisco, California.

PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease will expire in 2022.
 
The Utility currently owns approximately 158,000 acres of land, including approximately 128,000 acres of watershed lands. In 2002 the Utility agreed to implement its LCC to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations. The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Utility’s goal is to implement all the transactions needed to implement the LCC by the end of 2022, subject to securing all required regulatory approvals.

ITEM 3. 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 material lawsuits and proceedings, see Item 7. MD&A, and Notes 2, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8.

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, 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 what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance 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 accurate 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.

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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. 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 Mitigation 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.

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.”

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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 Corporation’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 Corporation’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Mitigation 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.

On July 26, 2019, the Monitor submitted a letter to the court regarding its VM field inspections, which were designed to evaluate the Utility’s compliance with aspects of its publicly-filed Wildfire Mitigation Plan’s EVM. The Monitor’s letter, which was filed on the public docket on August 14, 2019, provided its preliminary observations and preliminary findings, which included that (1) the Utility’s contractors had missed trees that should have been identified and worked under the EVM program; and (2) the Utility’s systems for recording, tracking and assigning EVM work were inconsistent and may have been contributing to the missed work. In its September 3, 2019 response to the Monitor’s letter, the Utility detailed its plan to address the concerns raised by the Monitor. The Monitor’s concerns and the Utility’s response were discussed at a hearing on September 17, 2019.

During the September 17, 2019 hearing, the court asked the Utility to provide information about: (1) its preparation for high wind season; and (2) the number of fires 10 acres or greater allegedly caused by the Utility to date in 2019. The Utility responded on October 1, 2019 by describing its efforts to strengthen its programs and infrastructure to maximize safety and mitigate the potential wildfire risk during high wind season. The Utility also responded that as of September 17, 2019, the Utility’s equipment may have contributed to nine ignitions in 2019 that resulted in fires 10 acres or greater. Two of these fires were potentially caused by vegetation and one was potentially caused by equipment. On October 2, 2019, the court asked the Utility for further information regarding the three fires potentially caused by vegetation and equipment. In its response, which was filed on October 9, 2019, the Utility provided information regarding certain fires, including but not limited to total acreage of the fire, ignition date, and potential causes.

On October 8, 2019, the court held a hearing related to the Utility’s San Bruno community service.

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On October 14, 2019, the court issued a request for information in connection with the PSPS event the Utility initiated on October 9, 2019 that shut off power to approximately 738,000 customers in 34 counties across Northern and Central California, asking the Utility to file a statement setting forth, among other information, “how many trees and limbs fell or blew onto the deenergized lines and how many of those would likely have caused arcing had the power been left on.” The Utility’s response was filed on October 30, 2019.

On November 4, 2019, the court issued a request for information in connection with PSPS events the Utility initiated in late October of 2019, asking the Utility to file a statement setting forth, among other information, the same type of information requested on October 14, 2019 in connection with the PSPS event initiated on October 9, 2019. The Utility filed its response on November 29, 2019.

On November 12, 2019, the court approved the request of the City of San Bruno to allow the Utility to satisfy the remainder of its community service requirements by making a $3 million payment to the City of San Bruno, and on November 27, 2019, the court signed an order in connection therewith. As a result, on December 10, 2019, the court paid $3 million to the City of San Bruno.

The Utility continued filing responses to the court’s additional requests in December 2019.

On December 20, 2019, the court ordered the Utility to state whether the Utility is in full compliance with two conditions of its probation: (1) the Utility must fully comply with all applicable laws concerning vegetation management and clearance requirements; and (2) the Utility must fully comply with the specific targets and metrics set forth in its wildfire mitigation plan. The Utility submitted its response to the court on January 15, 2020.

On January 16, 2020, the court issued an order to show cause noting that the Utility had admitted it was not in full compliance with the following conditions of probation: (1) fully complying with all applicable laws concerning vegetation management; and (2) fully complying with specific targets and metrics set forth in its wildfire mitigation plan. The court set a show cause hearing for February 19, 2020, to discuss why a further condition of probation should not be imposed requiring the Utility to hire sufficient crews to enable it to fully comply with the laws and its wildfire mitigation plan concerning vegetation management. The Utility submitted its response to the court on February 12, 2020.

On January 24, 2020, the court issued an additional order to show cause as to why, going forward, the Utility should not restrict all bonuses and other incentives for supervisors and above exclusively to achieving its wildfire mitigation plan and other safety goals. The Utility submitted its response to the court on February 12, 2020. A hearing in connection with this order is scheduled for February 19, 2020.

On February 4, 2020, the court issued an order directing the Utility to provide, by February 18, 2020, additional information in connection with the Utility’s prior responses dated November 29, 2019, December 19, 2019, and January 15, 2020, including regarding assets inspections and the condition of its electric assets.

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

Order Instituting an Investigation into PG&E Corporation’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 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.

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On May 8, 2017, the CPUC released the consultant’s report, accompanied by a scoping memo and ruling. The scoping memo established a second phase in the OII in which the CPUC evaluated the safety recommendations of the consultant. Phase two of the proceeding also considered 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 further a phase two scoping memo and procedural schedule. The scoping memo 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 approved 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. The CPUC held workshops 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 filed their response with the CPUC on July 3, 2019.

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 the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’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.

PG&E Corporation and the Utility are unable to predict whether additional fines, penalties, or other regulatory actions 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.

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Diablo Canyon Nuclear Power Plant

The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Regional Water Quality Control Board. In January 2000, the Central Coast Regional Water Quality Control Board issued a proposed draft cease and desist order alleging that, although the permit’s temperature limit had never been exceeded, the discharge was not protective of beneficial uses. This issue was resolved under a tentative global settlement addressing all aspects of the once-through cooling discharge that was initially approved in March 2003, but then later rejected by the Central Coast Regional Water Quality Control Board. Subsequently, in 2010 the California Water Board adopted a policy on once-through cooling that established specific compliance requirements. For Diablo Canyon, the policy set a compliance date of December 31, 2024, required an evaluation of the feasibility and cost of alternative technologies, and allowed for alternative compliance requirements. However, with the January 11, 2018 CPUC approval of Diablo Canyon’s retirement at the expiration of its existing NRC licenses, alternative compliance measures are no longer necessary. The policy still requires annual interim mitigation payments based on actual cooling water flow volume, which the Utility will continue to pay until operations cease in 2025.

The Utility expects that its decision to retire Diablo Canyon will affect the terms of a final settlement agreement between the Utility and the Central Coast Regional Water Quality Control Board regarding the thermal component of the plant’s once-through cooling discharge. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material effect on the Utility’s financial condition, results of operations, liquidity, and cash flows.


ITEM 4. MINE SAFETY DISCLOSURES

Not applicable. 

EXECUTIVE OFFICERS OF THE REGISTRANTS

The following individuals serve as executive officers of PG&E Corporation, as of February 18, 2020. Except as otherwise noted, all positions have been held at PG&E Corporation.
NameAgePositions Held Over Last Five YearsTime in Position
William D. Johnson66  Chief Executive Officer and PresidentMay 2, 2019 to present
President and Chief Executive Officer, Tennessee Valley Authority2012 to April 2019

John R. Simon55  Executive Vice President, Law, Strategy and PolicyJune 3, 2019 to present
Executive Vice PresidentMay 2, 2019 to June 2, 2019
Interim Chief Executive OfficerJanuary 14, 2019 to May 1, 2019
Executive Vice President and General CounselMarch 1, 2017 to January 13, 2019
Executive Vice President, Corporate Services and Human ResourcesAugust 18, 2015 to February 28, 2017
Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric CompanyApril 16, 2007 to August 17, 2015

Jason P. Wells42  Executive Vice President and Chief Financial OfficerMay 16, 2019 to present
Senior Vice President and Chief Financial Officer, PG&E Corporation January 1, 2016 to May 15, 2019
Vice President, Business Finance, Pacific Gas and Electric CompanyAugust 1, 2013 to December 31, 2015

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Andrew M. Vesey64  Chief Executive Officer and President, Pacific Gas and Electric CompanyAugust 19, 2019 to present
Advisor, AGL Energy LimitedSeptember 2018 to December 2018
Managing Director and Chief Executive Officer, AGL Energy LimitedFebruary 2015 to September 2018

Janet C. Loduca52  Senior Vice President and General Counsel, PG&E Corporation and Pacific Gas and Electric CompanyMay 2, 2019 to present
Senior Vice President and Interim General Counsel, PG&E Corporation and Pacific Gas and Electric CompanyJanuary 14, 2019 to May 1, 2019
Senior Vice President and Deputy General Counsel, Pacific Gas and Electric CompanyDecember 1, 2018 to January 13, 2019
Vice President and Deputy General Counsel, Counsel, Pacific Gas and Electric CompanyMarch 1, 2017 to November 30, 2018
Vice President, Investor RelationsJanuary 1, 2015 to February 28, 2017

The following individuals serve as executive officers of the Utility as of February 18, 2020. Except as otherwise noted, all positions have been held at the Utility.
NameAgePositions Held Over Last Five YearsTime in Position
Andrew M. Vesey64Chief Executive Officer and PresidentAugust 19, 2019 to present
Advisor, AGL Energy LimitedSeptember 2018 to December 2018
Managing Director and Chief Executive Officer, AGL Energy LimitedFebruary 2015 to September 2018

Michael A. Lewis57Senior Vice President, Electric OperationsJanuary 8, 2019 to present
Vice President, Electric Distribution OperationsAugust 1, 2018 to January 7, 2019
Senior Vice President and Chief Distribution Officer, Duke EnergySeptember 2016 to August 2018
Senior Vice President and Chief Transmission Officer, Duke EnergyJanuary 2015 to August 2016

Janet C. Loduca52  Senior Vice President and General Counsel, PG&E Corporation and Pacific Gas and Electric CompanyMay 2, 2019 to present
Senior Vice President and Interim General Counsel, PG&E Corporation and Pacific Gas and Electric CompanyJanuary 14, 2019 to May 1, 2019
Senior Vice President and Deputy General CounselDecember 1, 2018 to January 13, 2019
Vice President and Deputy General CounselMarch 1, 2017 to November 30, 2018
Vice President, Investor Relations, PG&E CorporationJanuary 1, 2015 to February 28, 2017

James M. Welsch64Senior Vice President, Generation and Chief Nuclear Officer August 10, 2019 to present
Senior Vice President and Chief Nuclear OfficerMay 16, 2019 to August 9, 2019
Vice President, Nuclear Generation and Chief Nuclear OfficerNovember 1, 2017 to May 15, 2019
Vice President, Nuclear GenerationNovember 4, 2016 to October 31, 2017
Site Vice President, Diablo Canyon Power Plant January 1, 2015 to November 3, 2016

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David S. Thomason44Vice President, Chief Financial Officer, and Controller, Pacific Gas and Electric CompanyJune 1, 2016 to present
Vice President and Controller, PG&E CorporationJune 1, 2016 to present
Senior Director, Financial Forecasting and Analysis