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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

pcg-20191231_g1.jpg
pcg-20191231_g2.jpg
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
4



5


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.

15


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