On a scale of 0 to 5, 5 being best, Zenith rates this company's Management's Discussion as a 5.

OVERVIEW

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

The Utility’s base revenue requirements are set by the CPUC in its GRC and GT&S 
rate case based on forecast costs. Differences between forecast costs and 
actual costs can occur for numerous reasons, including the volume of work 
required and the impact of market forces on the cost of labor and materials. 
Differences in costs can also arise from changes in laws and regulations at 
both the state and federal level. Generally, differences between actual costs 
and forecast costs affect the Utility’s ability to earn its authorized return 
(referred to as “Utility Revenues and Costs that Impacted Earnings” in Results 
of Operations below). The Utility’s base transmission revenue requirements are 
recovered through a formula rate approved by FERC that trues up forecast and 
actual costs. However, for certain operating costs, such as costs associated 
with pension benefits, the Utility is authorized to track the difference 
between actual amounts and forecast amounts and recover or refund the 
difference through rates (referred to as “Utility Revenues and Costs that did 
not Impact Earnings” in Results of Operations below). The Utility also collects 
revenue requirements to recover certain costs that the CPUC has authorized the 
Utility to pass on to customers, such as the costs to procure electricity or 
natural gas for its customers. Therefore, although these costs can fluctuate, 
they generally do not impact net income (referred to as “Utility Revenues and 
Costs that did not Impact Earnings” in Results of Operations below).

This is a combined report of PG&E Corporation and the Utility, and includes 
separate Consolidated Financial Statements for each of these two entities.

Chapter 11 Proceedings

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

Going Concern

The accompanying Consolidated Financial Statements to this Annual Report on 
Form 10-K have been prepared on a going concern basis, which contemplates the 
continuity of operations, the realization of assets and the satisfaction of 
liabilities in the normal course of business. However, PG&E Corporation and the 
Utility 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. As a result of these challenges, such realization of 
assets and satisfaction of liabilities are subject to uncertainty.

Management has concluded that uncertainty regarding these matters raises 
substantial doubt about PG&E Corporation’s and the Utility’s ability to 
continue as going concerns, and their independent registered public accountants 
have included an explanatory paragraph in their auditors’ reports 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. The Consolidated Financial Statements do not include any adjustments 
that might result from the outcome of this uncertainty.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net loss attributable to common shareholders were $7.7 
billion in 2019, compared to $6.9 billion in 2018. PG&E Corporation recognized 
charges of $11.4 billion for claims in connection with the 2018 Camp fire, the 
2017 Northern California wildfires and the 2015 Butte fire for the year ended 
December 31, 2019, compared to charges of $14.0 billion, net of probable 
insurance recoveries of $2.2 billion, associated with third-party claims and 
legal and other costs related to the 2018 Camp fire and the 2017 Northern 
California wildfires during the year ended December 31, 2018.

Key Factors Affecting Financial Results

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

•The Outcome of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, 
PG&E Corporation’s and the Utility’s business is subject to the risks and 
uncertainties of bankruptcy. For example, the Chapter 11 Cases could adversely 
affect the Utility’s relationships with suppliers and employees which, in turn, 
could adversely affect the value of the business and assets of PG&E Corporation 
and the Utility. PG&E Corporation and the Utility also have incurred and expect 
to continue to incur increased legal and other professional costs associated 
with the Chapter 11 Cases and the reorganization. At this time, it is not 
possible to predict with certainty the effect of the Chapter 11 Cases on their 
business or various creditors, or whether or when PG&E Corporation and the 
Utility will emerge from bankruptcy. PG&E Corporation’s and the Utility’s 
future financial condition, results of operations, liquidity and cash flows 
depend upon confirming, and successfully implementing, on a timely basis, a 
plan of reorganization. Although PG&E Corporation and the Utility have entered 
into settlement agreements to resolve the claims of the major classes of 
claimholders, including Utility debtholders, individual wildfire victims, 
holders of subrogated insurance claims and certain public entities, 
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 PG&E Corporation’s and the 
Utility’s control. In addition, PG&E Corporation’s and the Utility’s ability to 
emerge from Chapter 11 is dependent on their ability to satisfy the conditions 
set forth in AB 1054, as determined by the CPUC. PG&E Corporation and the 
Utility believe the Proposed Plan meets the requirements of AB 1054 by, among 
other things, satisfying wildfire claims through settlements consistent with 
the terms of AB 1054, by keeping rates neutral, on average, for the Utility’s 
customers, and by providing for the assumption of all power-purchase 
agreements, community-choice aggregation servicing agreements, and collective 
bargaining agreements. Finally, in order to emerge from Chapter 11, PG&E 
Corporation and the Utility must finance the Proposed Plan. There are numerous 
uncertainties related to such financings, including the ability to successfully 
raise equity or debt in the public or private markets, the ability to satisfy 
the terms and conditions set forth in the debt and equity commitment letters 
and the Noteholder RSA, the ability to collect insurance proceeds and the 
amount of additional capital that could be obtain to finance the Proposed Plan, 
including through securitization.

•The Utility’s Ability to Fund Ongoing Operations and Other Capital Needs. In 
connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered 
into the DIP Credit Agreement, which was approved on a final basis on March 27, 
2019. For the duration of the Chapter 11 Cases, PG&E Corporation and the 
Utility expect that the DIP Credit Agreement, together with cash on hand and 
cash flow from operations, will be the Utility’s primary source of capital to 
fund ongoing operations and other capital needs and that they will have 
limited, if any, access to additional financing. In the event that cash on 
hand, cash flow from operations, and availability under the DIP Credit 
Agreement are not sufficient to meet liquidity needs, PG&E Corporation and the 
Utility may be required to seek additional financing, and can provide no 
assurance that additional financing would be available or, if available, 
offered on acceptable terms. The amount of any such additional financing could 
be limited by negative covenants in the DIP Credit Agreement, which include 
restrictions on PG&E Corporation’s and the Utility’s ability to, among other 
things, incur additional indebtedness and create liens on assets.

•The Impact of the 2018 Camp Fire and the 2017 Northern California Wildfires. 
PG&E Corporation and the Utility face several uncertainties in connection with 
the 2018 Camp fire and 2017 Northern California wildfires, related to:

?the amount of possible loss related to third-party claims (as of December 31, 
2019, the Utility’s best estimate of probable loss in connection with the 2018 
Camp fire, 2017 Northern California wildfires and 2015 Butte fire was $25.5 
billion), which amount is subject to change based on a number of factors, 
including whether existing settlements are upheld, whether any termination 
events are triggered under these agreements, whether the classification and 
treatment of claims in the Proposed Plan is successfully challenged by 
claimholders who are not party to a settlement agreement, how the claims filed 
by Federal, state and local entities are resolved, and the ongoing criminal 
investigation with respect to the 2018 Camp fire;

?whether, in light of the CPUC 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 a substantial recovery of costs related to the 2017 Northern 
California wildfires;

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

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

?the amount of punitive damages, fines and penalties, or damages in respect of 
future claims, which could be material;

?the applicability of the doctrine of inverse condemnation in the 2018 Camp 
fire and 2017 Northern California wildfires litigation;

?the applicability of other theories of liability, including negligence, 
related to the 2018 Camp fire and 2017 Northern California wildfire claims;

?the recoverability of the above-mentioned costs, even if a court decision 
imposes liability under the doctrine of inverse condemnation;

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

?the amount and recoverability of clean-up and repair costs (the Utility 
incurred costs of $1.13 billion for clean-up and repair of the Utility’s 
facilities through December 31, 2019).

(See Notes 4 and 14 of the Notes to the Consolidated Financial Statements in 
Item 8 and Item 1A. Risk Factors in Part I.)

•The Impact of the 2019 Kincade Fire. Regardless of whether the Utility is 
determined to have caused the 2019 Kincade fire, the 2019 Kincade fire could 
have numerous adverse consequences to PG&E Corporation and the Utility, 
including, among others:

?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);

?depending on the number and type of structures damaged or destroyed by the 
2019 Kincade fire or the amount of post-petition claims against PG&E 
Corporation or the Utility as a result of the 2019 Kincade fire, PG&E 
Corporation and the Utility may not be able to satisfy, or obtain a waiver of, 
the conditions precedent to the commitments under the Backstop Commitment 
Letters or the Debt Commitment Letters, 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;

?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;

?the 2019 Kincade fire may 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 experience even greater difficulty in 
securing adequate insurance coverage for wildfire risks; and

?PG&E Corporation and the Utility expect to suffer additional reputational harm 
and face an even more challenging operating, political, and regulatory 
environment.

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

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

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

•The Uncertainties Regarding the Impact of Recent and Future Public Safety 
Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve 
substantial and ongoing expenditures and could involve other costs. The extent 
to which the Utility will be able to recover these expenditures and potential 
other costs through rates is uncertain. The PSPS program, one of the Utility’s 
wildfire risk mitigation initiatives outlined in the 2019 Wildfire Mitigation 
Plan, has been the subject of significant scrutiny and criticism by various 
stakeholders, including the California Governor, the CPUC and the court 
overseeing the Utility’s probation. On November 12, 2019, the CPUC issued an 
order to show cause why the Utility should not be sanctioned for alleged 
violations of law related to its communications with customers, coordination 
with local governments, and communications with critical facilities and public 
safety partners during the PSPS events in late 2019. On November 13, 2019, the 
CPUC instituted an OII to examine 2019 PSPS events carried out by California’s 
investor-owned utilities and to consider enforcement actions. PG&E Corporation 
and the Utility cannot predict the timing and outcome of the OII and order to 
show cause, and PG&E Corporation and the Utility could be subject to additional 
investigations, regulatory proceedings or other enforcement actions as well as 
to litigation and claims by customers, which could result in fines, penalties, 
customer rebates or other payments. On October 29, 2019, PG&E Corporation and 
the Utility announced that they would issue credits to customers with respect 
to the October 9, 2019 PSPS event. PG&E Corporation and the Utility recorded a 
charge of $86 million reflecting a one-time bill credit for customers impacted 
by the October 9, 2019 PSPS event in the fourth quarter of 2019. As of the date 
of this filing, PG&E Corporation and the Utility do not expect to issue any 
similar customer credits in connection with any other PSPS events (whether past 
events or in the future). 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), the aggregate amount of any such 
credits, rebates, or other payments could be substantial and 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 proposals of 
SB 378, which would impose penalties and other requirements on electric utility 
companies relating to PSPS events, could have a material effect on PG&E 
Corporation’s and the Utility’s financial condition, results of operations, 
liquidity, and cash flows. In addition to other requirements, SB 378 would 
impose on an electric utility company a civil penalty of at least $250,000 per 
50,000 affected customers for every hour that a PSPS event is in place, would 
require the CPUC to establish a procedure for customers, local governments and 
others to recover costs accrued during a PSPS event from the electric utility 
company, which cost recovery would be borne by shareholders, and would prohibit 
an electric utility company from billing customers for any nonfixed costs 
during a PSPS event. Further, the proposals of AB 1941 could have a material 
effect on PG&E Corporation’s and the Utility’s financial condition, results of 
operations, liquidity, and cash flows. AB 1941 proposes to suspend RPS 
requirements, determine the savings to electric utility companies from the 
suspension and direct those savings towards system hardening to mitigate 
wildfire risks and PSPS impacts, and would prohibit salary increases or bonuses 
to executive officers during the suspension of RPS requirements. In addition, 
the PSPS program has had an adverse impact on PG&E Corporation’s and the 
Utility’s reputation with customers, regulators and policymakers and future 
PSPS events may increase these negative perceptions. In addition to the 2019 
PSPS events, the Utility expects that PSPS events will be necessary in 2020 and 
future years.

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

While PG&E Corporation and the Utility are committed to taking aggressive 
wildfire mitigation actions, if additional requirements are imposed that go 
beyond current expectations, such requirements could have a substantial impact 
on PG&E Corporation's and the Utility's financial condition, results of 
operations, liquidity and cash flows. The Court in the Utility’s probation 
proceeding in connection with the Utility’s federal criminal proceeding has 
imposed numerous obligations on the Utility related to its business and 
operations, including full compliance with all applicable laws concerning 
vegetation management and clearance requirements, submission to regular, 
unannounced inspections by the Monitor of the Utility’s vegetation management 
efforts and equipment inspection, enhancement and repair efforts and the 
maintenance of traceable, verifiable, accurate and complete records of the 
Utility’s vegetation management efforts and monthly reports to the Monitor on 
the status and progress of vegetation management efforts. On January 16, 2020, 
the Court proposed to require the Utility to materially expand its vegetation 
management program, including through the hiring of additional employees. PG&E 
Corporation and the Utility also face uncertainties in connection with the 
amount and recoverability of enhanced and accelerated inspection costs of the 
Utility’s electric transmission and distribution assets (the Utility incurred 
costs of $773 million for enhanced and accelerated inspection and repair costs 
for the year ended December 31, 2019).

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and 
Other Government Proposals. The Utility’s financial results may continue to be 
impacted by the outcome of other current and future enforcement, litigation (to 
the extent not stayed as a result of the Chapter 11 Cases), and regulatory 
matters, including those described above as well as the outcome of the locate 
and mark OII, the outcome of the safety culture OII, the sentencing terms of 
the Utility’s January 27, 2017 federal criminal conviction, including the 
oversight of the Utility’s probation and the potential recommendations by the 
Monitor, and potential penalties in connection with the Utility’s safety and 
other self-reports. (See Note 15 of the Notes to the Consolidated Financial 
Statements in Item 8.) In addition, the Utility’s business profile and 
financial results could be impacted by the outcome of recent calls for 
municipalization of part or all of the Utility’s businesses, offers by 
municipalities and other public entities to acquire the electric assets of the 
Utility within their respective jurisdictions and calls for state intervention, 
including the possibility of a state takeover of the Utility. PG&E Corporation 
and the Utility cannot predict the nature, occurrence, timing or extent of any 
such scenario, and there can be no assurance that any such scenario would not 
involve significant ownership or management changes to PG&E Corporation or the 
Utility, including by the state of California.

•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial 
results may be impacted by the timing and outcome of its 2020 GRC, FERC TO18, 
TO19, and TO20 rate cases, and its ability to timely recover costs not 
currently in rates, including costs already incurred and future costs tracked 
in its CEMA, WEMA, FHPMA, WMPMA, and FRMMA that are incurred in connection with 
the Utility’s 2019 Wildfire Mitigation Plan, the amount of which is 
approximately $2.6 billion. The outcome of regulatory proceedings can be 
affected by many factors, including intervening parties’ testimonies, potential 
rate impacts, the Utility’s reputation, the regulatory and political 
environments, and other factors. (See Notes 4 and 15 of the Notes to the 
Consolidated Financial Statements in Item 8 and “Regulatory Matters” below.)

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


RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s 
operating results for 2019, 2018, and 2017. See “Key Factors Affecting 
Financial Results” above for further discussion about factors that could affect 
future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to 
the Utility, which are discussed in the “Utility” section below.

PG&E Corporation’s net income (loss) increased in 2019, as compared to 2018, 
primarily due to the impacts of the Chapter 11 Cases in 2019, with no 
corresponding activities in 2018.

PG&E Corporation’s net income (loss) decreased in 2018, as compared to 2017, 
primarily due to the impact of the San Bruno Derivative Litigation in 2017 with 
no corresponding activity in 2018, partially offset by additional income taxes 
in 2017.

Utility

The table below shows certain items from the Utility’s Consolidated Statements 
of Income for 2019, 2018, and 2017. The table separately identifies the 
revenues and costs that impacted earnings from those that did not impact 
earnings. In general, expenses the Utility is authorized to pass through 
directly to customers (such as costs to purchase electricity and natural gas, 
as well as costs to fund public purpose programs) and the corresponding amount 
of revenues collected to recover those pass-through costs, do not impact 
earnings. In addition, expenses that have been specifically authorized (such as 
energy procurement costs) and the corresponding revenues the Utility is 
authorized to collect to recover such costs, do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by 
the CPUC and the FERC to recover the Utility’s costs to own and operate its 
assets and to provide the Utility an opportunity to earn its authorized rate of 
return on rate base. Expenses that impact earnings are primarily those that the 
Utility incurs to own and operate its assets.


Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2019, 
2018, and 2017, focusing on revenues and expenses that impacted earnings for 
these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted 
earnings increased $988 million, or 9%, in 2019 compared to 2018, primarily due 
to increased base revenues authorized in the 2017 GRC, 2019 GT&S, and TO20 rate 
cases.

The Utility’s electric and natural gas operating revenues that impacted 
earnings increased $39 million in 2018 compared to 2017, primarily due to 
increased base revenues authorized in the 2017 GRC, partially offset by tax 
benefits resulting from the Tax Act expected to be returned to customers.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings 
increased $1,692 million, or 31%, in 2019 compared to 2018, primarily due to 
$773 million in costs related to enhanced and accelerated inspections and 
repairs of transmission and distribution assets, with no similar charges in the 
same period in 2018. Additionally, the Utility recorded $398 million in 2019 
related to the Wildfires OII settlement, with no similar charge in the same 
period in 2018. Also, the Utility recorded $237 million in disallowed costs for 
previously incurred capital expenditures in excess of adopted amounts in the 
2019 GT&S rate case, with no similar charges in 2018.

The Utility’s operating and maintenance expenses that impacted earnings 
increased $363 million, or 7%, in 2018 compared to 2017, primarily due to $209 
million for clean-up and repair costs relating to the 2017 Northern California 
wildfires and the 2018 Camp fire, as compared to $17 million relating to the 
2017 Northern California wildfires charged in 2017. Also, the Utility recorded 
charges of $187 million in additional legal and other costs relating to the 
2017 Northern California wildfires and the 2018 Camp fire (the Utility recorded 
$205 million for legal and other costs relating to the 2017 Northern California 
wildfires and the 2018 Camp fire in 2018, as compared to $18 million in 2017). 
The Utility also recorded charges of $121 million reflecting the additional 
write off of insurance premiums for single event coverage policies (the Utility 
recorded $185 million in 2018 for the write off of insurance premiums, as 
compared to $64 million in 2017). These increases were partially offset by a 
$38 million reduction to the estimated disallowance for gas-related capital 
costs that were expected to exceed authorized amounts in 2018, compared to a 
$47 million disallowance recorded in 2017 related to the Diablo Canyon 
settlement. Additionally, the increases were offset by a decrease in legal and 
other costs relating to the 2015 Butte fire of $20 million in 2018 compared to 
2017 (the Utility recorded $40 million for legal and other costs relating to 
the 2015 Butte fire in 2018 as compared to $60 million in 2017).

Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings decreased by $336 million in 
2019 compared to 2018. The Utility recognized charges of $11.4 billion and 
$11.8 billion in 2019 and 2018, respectively, for wildfire-related claims, net 
of probable insurance recoveries, primarily associated with the 2018 Camp fire 
and 2017 Northern California wildfires.

Costs related to wildfires that impacted earnings increased by $11.8 billion in 
2018 compared to 2017. In 2018, the Utility recognized charges of $14 billion, 
offset by probable insurance recoveries of $2.2 billion associated with the 
2018 Camp fire and 2017 Northern California wildfires. In 2017, the Utility 
recognized a charge of $350 million, offset by probable insurance recoveries of 
$350 million related to the 2015 Butte fire.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses 
increased by $197 million, or 6%, in 2019 compared to 2018, primarily due to 
capital additions. The Utility’s depreciation, amortization, and 
decommissioning expenses increased by $182 million, or 6%, in 2018 compared to 
2017, primarily due to capital additions.

Interest Income

The Utility’s interest income increased by $8 million, or 11%, in 2019 compared 
to 2018. The Utility’s interest income increased by $44 million, or 147%, in 
2018 as compared to 2017. The Utility’s interest income is primarily affected 
by changes in regulatory balancing accounts and changes in interest rates.

Interest Expense

The Utility’s interest expense decreased by $2 million, or 0%, in 2019 compared 
to 2018. Beginning January 29, 2019 in connection with the Chapter 11 Cases, 
the Utility ceased recording interest on outstanding pre-petition debt subject 
to compromise. In the fourth quarter of 2019, following the Bankruptcy Court’s 
December 30, 2019 memorandum decision in which it ruled that the UCC is 
entitled to post-petition interest at the Federal Judgment Rate of 2.59%, and 
pursuant to the terms of the Noteholder RSA, the Utility concluded that 
interest was probable of being an allowed claim and resumed recording interest 
on pre-petition debt subject to compromise. The Utility’s interest expense 
increased by $37 million, or 4%, in 2018 compared to 2017, primarily due to the 
issuance of long-term debt.

Other Income, Net

The Utility’s other income, net decreased by $41 million, or 39%, in 2019 
compared to 2018, primarily due to a decrease in AFUDC due to equity ratio 
decreases resulting from the Chapter 11 filing and wildfire loss accruals. The 
Utility’s other income, net increased by $39 million, or 60%, in 2018 as 
compared to 2017, primarily due to an increase in AFUDC as the average balance 
of construction work in progress was higher in 2018 as compared to 2017.

Reorganization items, net

Reorganization items, net increased by $320 million in 2019 compared to 2018, 
due to $370 million of expenses directly associated with the Utility’s Chapter 
11 filing, partially offset by interest income of $50 million, with no 
corresponding charges in 2018.


Income Tax Provision

The Utility’s income tax benefit increased $112 million in 2019 compared to 
2018, primarily due to higher pre-tax losses.

The Utility’s income tax provision decreased $3.7 billion in 2018 compared to 
2017. The decrease in the income tax provision and increase in the effective 
tax rate were primarily the result of pre-tax losses in 2018 versus pre-tax 
income in 2017, partially offset by a decrease in the corporate income tax rate 
from 35% to 21% as a result of the Tax Act.

Utility Revenues and Costs that did not Impact Earnings

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

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from 
third parties (including renewable energy resources), transmission, fuel used 
in its own generation facilities, fuel supplied to other facilities under power 
purchase agreements, costs to comply with California’s cap-and-trade program, 
and realized gains and losses on price risk management activities. Cost of 
electricity also includes net sales (Utility owned generation and third 
parties) in the CAISO electricity markets. (See Note 10 of the Notes to the 
Consolidated Financial Statements in Item 8.) The Utility’s total purchased 
power is driven by customer demand, net CAISO electricity market activities 
(purchases or sales), the availability of the Utility’s own generation 
facilities (including Diablo Canyon and its hydroelectric plants), and the 
cost-effectiveness of each source of electricity.

Cost of purchased power, net decreased for the year ended December 31, 2019, 
compared to 2018, primarily due to lower Utility electric customer demand, 
driven by customer departures to CCAs and DA providers, and by higher net sales 
in the CAISO electricity markets.


Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage 
and transportation of natural gas, costs to comply with California’s 
cap-and-trade program, and realized gains and losses on price risk management 
activities. (See Note 10 of the Notes to the Consolidated Financial Statements 
in Item 8.) The Utility’s cost of natural gas is impacted by the market price 
of natural gas, changes in the cost of storage and transportation, and changes 
in customer demand.


Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact earnings include certain 
costs that the Utility is authorized to recover as incurred such as pension 
contributions and public purpose programs costs. If the Utility were to spend 
more than authorized amounts, these expenses could have an impact to earnings. 
For 2019, 2018, and 2017, no material amounts were incurred above authorized 
amounts.

Other Income, Net

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

LIQUIDITY AND FINANCIAL RESOURCES

Overview

On the Petition Date, PG&E Corporation and the Utility filed voluntary 
petitions for relief under Chapter 11 in the Bankruptcy Court. In connection 
with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the 
DIP Credit Agreement. The DIP Credit Agreement provides for $5.5 billion in 
senior secured superpriority debtor in possession credit facilities in the form 
of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the 
“DIP Revolving Facility”), including a $1.5 billion letter of credit 
subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 
billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term 
loan facility in an aggregate principal amount of $500 million (the “DIP 
Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and 
the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms 
and conditions set forth therein. On March 27, 2019, the Bankruptcy Court 
approved the DIP Facilities on a final basis, authorizing the Utility to borrow 
up to the remainder of the DIP Revolving Facility (including the remainder of 
the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan 
Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to 
the terms and conditions of the DIP Credit Agreement.

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

During 2018 and January 2019, PG&E Corporation’s and the Utility’s credit 
ratings were subject to multiple downgrades by Fitch, S&P and Moody’s including 
to ratings below investment grade and ultimately to “D” or low “C” ratings. In 
the first quarter of 2019, Moody’s and Fitch withdrew each of their credit 
ratings for PG&E Corporation and the Utility as a result of the Chapter 11 
Cases. As a result of PG&E Corporation’s and the Utility’s credit ratings 
ceasing to be rated at investment grade, the Utility has been required to post 
collateral under its commodity purchase agreements and certain other 
obligations. In addition, PG&E Corporation and the Utility may be required to 
post additional collateral in respect of certain other obligations, including 
workers’ compensation and environmental remediation obligations.

Cash and Cash Equivalents

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

Financial Resources

Acceleration of Pre-Petition Debt Obligations

The commencement of the Chapter 11 Cases constituted an event of default or 
termination event with respect to, and caused an automatic and immediate 
acceleration of, the Accelerated Direct Financial Obligations. Accordingly, as 
a result of the commencement of the Chapter 11 Cases, the principal amount of 
the Accelerated Direct Financial Obligations, together with accrued interest 
thereon, and in case of certain indebtedness, premium, if any, thereon, 
immediately became due and payable. However, any efforts to enforce such 
payment obligations are automatically stayed as of the Petition Date, and are 
subject to the applicable provisions of the Bankruptcy Code and orders of the 
Bankruptcy Court.

DIP Credit Agreement

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

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

On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed 
Draw Term Loan Facility. As of February 13, 2020, the Utility had outstanding 
borrowings of $1.5 billion under the DIP Initial Term Loan Facility, $500 
million under the DIP Delayed Draw Term Loan Facility, and $751 million in face 
amount of letters of credit outstanding under the DIP Revolving Facility. As of 
February 13, 2020, there were undrawn commitments of $2.7 billion on the DIP 
Revolving Facility.


Debt Commitment Letters

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

In connection with the anticipated funding for the Proposed Plan and the 
anticipated amount of debt and equity to be used for funding thereunder, on 
February 14, 2020, the Debt Commitment Letters were amended to, among other 
things, (1) adjust the maximum amount of any roll-over, “take-back” or 
reinstated debt permitted under the Facilities from $30.0 billion to $33.35 
billion at the Utility and from $7.0 billion to $5.0 billion at PG&E 
Corporation, (2) reduce the amount of proceeds from the issuance of equity that 
PG&E Corporation has to receive as a condition to funding from $12.0 billion to 
$9.0 billion, and (3) increase the amount of proceeds from the issuance of debt 
securities or other debt for borrowed money as a condition to funding from $2.0 
billion at PG&E Corporation to $6.0 billion at the Utility.

In lieu of entering into the Facilities, PG&E Corporation and the Utility 
intend to obtain permanent financing on or prior to emergence from bankruptcy 
in the form of bank facilities, debt securities or a combination of the 
foregoing. (See “Anticipated Sources and Uses for Chapter 11 Emergence and 
Related Financings” below and “Plan of Reorganization, RSAs, Equity Backstop 
Commitments and Debt Commitment Letters” in Note 2 of the Notes to the 
Consolidated Financial Statements in Item 8.)

On October 23, 2019, PG&E Corporation and the Utility filed a motion with the 
Bankruptcy Court seeking approval of the Debt Commitment Letters and certain 
related matters. The hearing on PG&E Corporation’s and the Utility’s motion to 
approve the Backstop Commitment Letters, the Debt Commitment Letters and 
certain related matters is scheduled for February 26, 2020.

Equity Financings

There were no issuances under the PG&E Corporation February 2017 equity 
distribution agreement for the year ended December 31, 2019.

PG&E Corporation issued 8.9 million shares of common stock under the PG&E 
Corporation 401(k) plan and share-based compensation plans, for cash proceeds 
of $85 million, during the year ended December 31, 2019. The proceeds from 
these sales were used for general corporate purposes. Beginning January 1, 
2019, PG&E Corporation changed its default matching contributions under its 
401(k) plan from PG&E Corporation common stock to cash. Beginning in March 
2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing 
new shares in the PG&E Corporation common stock fund on the open market rather 
than directly from PG&E Corporation.

PG&E Corporation expects to issue new shares of PG&E Corporation common stock 
for up to $9.0 billion of proceeds at or prior to emergence from Chapter 11 in 
order to finance the Proposed Plan. The structure, terms and conditions of any 
such equity issuance are expected to be determined by PG&E Corporation and the 
Utility at a later time in the Chapter 11 process, subject to the terms and 
conditions of the Backstop Commitment Letters. There can be no assurance that 
any such equity offering would be successful. PG&E Corporation has obtained the 
Backstop Commitment Letters providing for equity funding of up to $12.0 billion 
to finance the transactions contemplated by the Proposed Plan. In the event 
that new equity offerings do not raise at least $9.0 billion of proceeds, or if 
additional capital is required, PG&E Corporation may draw on the Backstop 
Commitments for equity funding of up to $12.0 billion, subject to satisfaction 
or waiver by the Backstop Parties of the conditions set forth therein. (See 
“Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings” 
below and “Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt 
Commitment Letters” in Note 2 of the Notes to the Consolidated Financial 
Statements in Item 8.) The hearing on PG&E Corporation’s and the Utility’s 
motion to approve the Backstop Commitment Letters and certain related matters 
is scheduled for February 26, 2020.


Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings

PG&E Corporation and the Utility expect that the funding for the Proposed Plan 
will consist of both new debt and equity for both PG&E Corporation and the 
Utility as well as other sources of funding totaling approximately $58 billion.

Expected Sources

Equity issuance for cash represents expected proceeds from the sale of shares 
of common stock of PG&E Corporation through one or more public offerings, 
private offerings, a rights offering or drawings under the Backstop 
Commitments. The terms of any such issuance are governed by the terms of the 
Backstop Commitment Letters. Although the Proposed Plan contemplates $9.0 
billion of equity, the Backstop Commitment Letters permit up to $12.0 billion 
of equity to be drawn from the Backstop Commitments.

Equity issued to Fire Victim Trust represents new shares of common stock of 
PG&E Corporation to be issued to the Fire Victim Trust as provided in the 
Proposed Plan.

Reinstated Utility Debt represents pre-petition debt of the Utility that is 
expected to be reinstated on the Effective Date pursuant to the Proposed Plan.

New Utility Debt represents one or more issuances of new debt securities or 
bank debt of the Utility, expected to be comprised of (i) $6.2 billion of New 
Utility Long-Term Notes to be issued to holders of certain pre-petition senior 
notes of the Utility pursuant to the Proposed Plan, (ii) $1.75 billion of New 
Utility Short-Term Notes to be issued to holders of certain pre-petition senior 
notes of the Utility pursuant to the Proposed Plan, (iii) $3.9 billion of 
Utility Funded Debt Exchange Notes to be issued to holders of certain 
pre-petition indebtedness of the Utility pursuant to the Proposed Plan and (iv) 
$11.925 billion of new debt securities or bank debt of the Utility to be issued 
to third parties for cash on or prior to the Effective Date. As described 
below, $6.0 billion of such new debt securities or bank debt is expected to be 
repaid with the proceeds of a new securitization transaction after the 
Effective Date.

Insurance Proceeds represents proceeds of PG&E Corporation’s and the Utility’s 
liability insurance policies for wildfire events.

Cash at Emergence represents projected cash on hand at PG&E Corporation and the 
Utility as of the Effective Date.

Expected Uses

Fire Claims (at Emergence) represents compensation to be paid on the Effective 
Date to holders of wildfire-related claims to resolve their claims pursuant to 
the Proposed Plan. The total compensation of $24.15 billion consists of (i) 
$12.15 billion to be paid in cash and stock to the Fire Victim Trust, (ii) 
$11.0 billion to be paid to holders of subrogated insurance claims and (iii) 
$1.0 billion to be paid to the Supporting Public Entities.

Contribution to Wildfire Fund represents required payments under AB 1054 for 
the Utility to participate in the Wildfire Fund. These payments are comprised 
of an initial contribution of approximately $4.8 billion and annual 
contributions of approximately $193 million.

Debtor-In-Possession Financing represents the projected amount that will be 
required in order to repay all amounts outstanding under the DIP Credit 
Agreement on the Effective Date.

Pre-petition Debt represents the aggregate principal amount of pre-petition 
debt of PG&E Corporation or the Utility to be repaid or refinanced on the 
Effective Date, consisting of (i) $650 million of pre-petition debt of PG&E 
Corporation to be repaid in cash pursuant to the Proposed Plan, (ii) $6.2 
billion of pre-petition senior notes of the Utility to exchanged for New 
Utility Long-Term Notes pursuant to the Proposed Plan, (iii) $1.75 billion of 
pre-petition senior notes of the Utility to be exchanged for New Utility 
Short-Term Notes pursuant to the Proposed Plan and (iv) $3.9 billion of 
pre-petition indebtedness of the Utility to be exchanged for Utility Funded 
Debt Exchange Notes pursuant to the Proposed Plan, (v) $9.575 billion of 
pre-petition senior notes of the Utility to be reinstated pursuant to the 
Proposed Plan and (vi) $100 million of Pollution Control Bonds (Series 2008F 
and 2010E) to be repaid in cash pursuant to the Proposed Plan.

Trade Claims and Other Costs represents estimated trade claims and other costs, 
including trade payables and transaction fees, to be paid by PG&E Corporation 
or the Utility on the Effective Date.

Accrued Interest represents the estimated amount of accrued interest that will 
be paid by PG&E Corporation or the Utility on the Effective Date.

Cash represents $750 million of cash remaining on the balance sheet as of the 
Effective Date.

The table above does not include $1.35 billion of payments to be made to the 
Fire Victim Trust after the Effective Date of the Proposed Plan pursuant to a 
tax benefit monetization agreement. Pursuant to this tax benefit monetization 
agreement, PG&E Corporation and the Utility will use the first $1.35 billion of 
wildfire-related tax net operating losses (the “Wildfire NOLs”) in order to 
make payments to the Fire Victim Trust, which payments are expected to be $650 
million on or before January 15, 2021 and $700 million on or before January 15, 
2022. In addition, the table above does not include any expected post-Effective 
Date securitization transaction. As described below under the heading 
“Potential Securitization Transaction,” the economic benefits of the Wildfire 
NOLs in excess of the first $1.35 billion would be used to support the expected 
post-Effective Date securitization transaction.

Potential Securitization Transaction

PG&E Corporation and the Utility expect to file an application with the CPUC 
seeking authorization for a post-emergence $7.0 billion securitization 
transaction that is rate-neutral, on average, to customers, with the proceeds 
used to refinance $6.0 billion of new Utility debt and fund a portion of the 
$1.35 billion payment due to the Fire Victim Trust post-Effective Date. In this 
context, a securitization refers to a financing transaction where the Utility 
or a special purpose financing vehicle issues new debt that is secured by the 
proceeds of a new recovery charge to Utility customers. A rate-neutral 
securitization means that the Utility will propose to offset the new recovery 
charges with customer credits, so that on a net present value basis, customers 
do not experience an increase in utility rates. The Utility would be able to 
support these credits based on the tax savings from the Wildfire NOLs and other 
sources. In other words, the funds retained by the Utility that would have 
otherwise been used to pay taxes can be used for other purposes, reducing the 
amount that the Utility needs to collect from customers (thereby using the 
Wildfire NOLs to “fund” the credit).

The foregoing description of anticipated sources and uses of funding for the 
Proposed Plan includes “forward-looking statements” within the meaning of 
Section 27A of the Securities Act, including statements about the expected 
sources and uses of funding, expected financing transactions (including the 
potential securitization) and projected balances of assets and liabilities 
(including cash on hand, accrued interest, trade payables and other amounts). 
This description reflects PG&E Corporation’s and the Utility’s expectations as 
of the date of this filing and remains subject to change. (See “Forward-Looking 
Statements” at the beginning of this Annual Report on Form 10-K).

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the 
Utility suspended quarterly cash dividends on both PG&E Corporation’s and the 
Utility’s common stock, beginning the fourth quarter of 2017, as well as the 
Utility’s preferred stock, beginning the three-month period ending January 31, 
2018. (See Note 6 of the Notes to the Consolidated Financial Statements in Item 
8.)


Utility Cash Flows

Operating Activities

The Utility’s cash flows from operating activities primarily consist of 
receipts from customers less payments of operating expenses, other than 
expenses such as depreciation that do not require the use of cash. During 2019, 
net cash provided by operating activities increased by $106 million compared to 
2018. This increase was due to a decrease in interest paid from $773 million to 
$7 million as a result of the automatic stay as of the Petition Date. 
Additionally, income taxes paid decreased from $59 million in 2018 to zero in 
2019. These decreases in amounts paid were offset by an increase in amounts 
paid for reorganization items, and enhanced and accelerated inspections and 
repairs of transmission and distribution assets in 2019, with no similar 
payments in 2018, partially offset by additional amounts not paid due to the 
automatic stay as of the Petition Date.

During 2018, net cash provided by operating activities decreased by $1.2 
billion compared to 2017. This decrease was due to an increase in costs for 
clean-up and repair, and legal and other costs related to the 2018 Camp fire 
and 2017 Northern California wildfires, as well as enhanced vegetation 
management work, and due to fluctuations in activities within the normal course 
of business such as the timing and amount of customer billings and collections 
and vendor billings and payments. Additionally, the Utility paid $59 million in 
income taxes in 2018, as compared to receiving a refund of $162 million in 
2017.

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

•the timing and amounts of costs, including fines and penalties, that may be 
incurred in connection with current and future enforcement, litigation, and 
regulatory matters (see Note 14 and “Enforcement and Litigation Matters” in 
Note 15 of the Notes to the Consolidated Financial Statements in Item 8. and 
Item 3. Legal Proceedings for more information);

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

•the timing and amount of premium payments related to wildfire insurance (see 
“Wildfire Insurance” in Note 15 of the Notes to the Consolidated Financial 
Statements in Item 8 for more information);

•the Tax Act, which may accelerate the timing of federal tax payments and 
reduce revenue requirements, resulting in lower operating cash flows depending 
on the timing of wildfire payments; and

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 
NDCTP, 2018 and 2019 CEMA filings, and other ratemaking and regulatory 
proceedings.

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

Investing Activities

Net cash used in investing activities decreased by $186 million during 2019 as 
compared to 2018 primarily due to a decrease in cash paid for capital 
expenditures as a result of the automatic stay as of the Petition Date. Net 
cash used in investing activities increased by $914 million during 2018 as 
compared to 2017 primarily due to an increase of approximately $873 million in 
capital expenditures. The Utility’s investing activities primarily consist of 
the construction of new and replacement facilities necessary to provide safe 
and reliable electricity and natural gas services to its customers. Cash used 
in investing activities also includes the proceeds from sales of nuclear 
decommissioning trust investments which are largely offset by the amount of 
cash used to purchase new nuclear decommissioning trust investments. The funds 
in the decommissioning trusts, along with accumulated earnings, are used 
exclusively for decommissioning and dismantling the Utility’s nuclear 
generation facilities.

Future cash flows used in investing activities are largely dependent on the 
timing and amount of capital expenditures. The Utility estimates that it will 
incur approximately $7.6 billion in capital expenditures in 2020.

Financing Activities

During 2019, net cash provided by financing activities decreased by $1.3 
billion as compared to 2018. This decrease was primarily due to $2.9 billion of 
net borrowings under revolving credit facilities in 2018, partially offset by 
$1.5 billion of net borrowings under the DIP Initial Term Loan Facility in 
2019.

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


CONTRACTUAL COMMITMENTS

Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility 
cannot make reliable estimates of the amounts and periods of future payments to 
major tax jurisdictions related to unrecognized tax benefits.

Subject to certain exceptions, under the Bankruptcy Code, PG&E Corporation and 
the Utility may assume, assign or reject certain executory contracts and 
unexpired leases, subject to the approval of the Bankruptcy Court and 
satisfaction of certain other conditions. Generally, the rejection of an 
executory contract or unexpired lease is treated as a pre-petition breach of 
such executory contract or unexpired lease and, subject to certain exceptions, 
relieves PG&E Corporation and the Utility of performing their respective future 
obligations under such executory contract or unexpired lease but entitles the 
contract counterparty or lessor to a pre-petition general unsecured claim for 
damages caused by such deemed breach. Generally, the assumption of an executory 
contract or unexpired lease will require PG&E Corporation or the Utility, as 
applicable, to cure existing monetary and non-monetary defaults under such 
executory contract or unexpired lease and provide adequate assurance of future 
performance. Accordingly, any description of an executory contract or unexpired 
lease with PG&E Corporation or the Utility in this Annual Report on Form 10-K, 
including where applicable a quantification of the obligations under any such 
executory contract or unexpired lease, is qualified by any overriding 
assumption or rejection rights PG&E Corporation or the Utility, as applicable, 
has under the Bankruptcy Code. Further, nothing herein is or shall be deemed to 
be an admission with respect to any claim amounts or calculations arising from 
the rejection of any executory contract or unexpired lease and PG&E Corporation 
and the Utility expressly reserve all of their rights with respect thereto.


Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have any off-balance sheet arrangements 
that have had, or are reasonably likely to have, a current or future material 
effect on their financial condition, changes in financial condition, revenues 
or expenses, results of operations, liquidity, capital expenditures, or capital 
resources, other than those discussed under “Purchase Commitments” in Note 15 
of the Notes to the Consolidated Financial Statements in Item 8.

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from 
their operations, including contingencies related to the enforcement and 
litigation matters described in Notes 14 and 15 of the Notes to the 
Consolidated Financial Statements in Item 8. and Legal Proceedings in Item 3 
that are incorporated by reference herein. The outcome of these matters, 
individually or in the aggregate, could have a material effect on PG&E 
Corporation’s and the Utility’s financial condition, results of operations, 
liquidity, and cash flows.

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 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.”

On January 30, 2019, the court found that the Utility had violated a condition 
of its probation with respect to reporting requirements related to the 2017 
Honey fire. Also, on January 30, 2019, the court ordered the Utility to submit 
to the court on February 6, 2019 the 2019 Wildfire 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.

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.”

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.”

On May 14, 2019, the court imposed two additional conditions of probation: (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 November 12, 2019, the court held a hearing related to the Utility’s San 
Bruno community service. At the hearing, representatives from San Bruno asked 
the court to approve allowing the Utility to satisfy the remainder of its 
community service requirements by making a $3 million payment that would be 
used for the purpose of hard costs incurred as part of the Crestmoor Canyon 
Wildfire Mitigation Project. The court approved the request and ordered the 
parties to jointly offer language regarding revising the Utility’s conditions 
of probation to effectuate this change. The parties conferred and agreed on 
proposed language, which the Utility submitted to the court as a proposed order 
on November 27, 2019. The court signed the proposed order that same day, and on 
December 10, 2019 confirmed receipt of the $3 million payment from the Utility 
in compliance with the November 27th Order.

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 a request for amended responses and 
further questions to be answered by the Utility relating to certain of the 
court’s requests for wildfire and PSPS related information. The Utility has 
until February 18, 2020 to submit its responses to these questions.


REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the 
NRC, and other federal and state regulatory agencies. The resolutions of the 
proceedings described below and other proceedings may materially affect PG&E 
Corporation’s and the Utility’s financial condition, results of operations, 
liquidity, and cash flows.

Rate Cases

Application for Wildfire Mitigation and Catastrophic Events Interim Rates

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

After removing the amounts agreed to be not subject for recovery pursuant to 
the 2017 Northern California Wildfires and the 2018 Camp Fire OII settlement 
agreement (submitted to the CPUC on December 17, 2019), the total electric 
distribution costs related to the above activities are approximately $1.7 
billion in expense and capital expenditures. This amount translates to an 
electric distribution revenue requirement of approximately $1 billion. The 
interim rate relief sought in this application is 85% of that revenue 
requirement. The Utility’s application calls for a CPUC decision by July of 
2020. In its interim rate relief application, the Utility also proposes to file 
one or more detailed application(s) with the CPUC to determine the 
reasonableness of the above-described costs later in 2020.

If approved, by the CPUC, the interim relief request would increase electric 
distribution rates over a 17-month period beginning in August 2020. If the CPUC 
determines in those later application(s) that the interim rates were too high, 
the Utility will refund any overcollections to customers with interest based on 
the applicable commercial paper rate.

The Utility’s application also requests a CPUC ruling that would allow for 
interim rate relief when the recorded balance in certain memorandum accounts 
exceeds a threshold of $100 million. The Utility is unable to predict the 
timing and outcome of this application.

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

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

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

Application for a Waiver of the Capital Structure Condition

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

On April 30, 2019, the CPUC held a prehearing conference, and on May 29, 2019, 
the CPUC issued a scoping memo and ruling on issues for briefing. Subsequently, 
among other things, the Utility filed a motion with the CPUC to notify the CPUC 
of a decline in its equity ratio to approximately 34% at June 30, 2019. On 
November 12, 2019, the Utility submitted a second motion to the CPUC to notify 
the CPUC of an additional decline in its equity ratio to approximately 30.4%, 
based on information reported in its Quarterly Report on Form 10-Q for the 
quarter ended September 30, 2019, primarily related to non-cash charges related 
to the 2018 Camp fire and the 2017 Northern California wildfires. The Utility 
submitted additional pleadings in December 2019, notifying the CPUC of 
additional charges due to the 2017 Northern California wildfires and the 2018 
Camp fire, and describing the impacts on its equity percentage if the charges 
were added to the Utility’s financial information reported in its Form 10-Q for 
the quarterly period ending September 30, 2019. However, the Utility indicated 
that its equity percentage at December 31, 2019 would not be known until the 
financial information for the period ending December 31, 2019 is reported in 
the 2019 Form 10-K.

On November 20, 2019, the assigned ALJ issued a ruling with questions for the 
Utility to answer. On January 21, 2020, the Utility filed responses to the 
questions presented in the ALJ’s November 20, 2019 ruling. In its responses, 
among other things, the Utility recommended that the CPUC grant the Utility a 
waiver of the capital structure condition, and transfer the issue of the 
Utility’s capital structure waiver to the OII to consider and resolve the 
continuance or end of the waiver in that proceeding in connection with the 
Utility’s Proposed Plan of Reorganization.

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

2020 Cost of Capital Proceeding

On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of 
Capital proceeding, maintaining the Utility’s return on common equity for the 
three-year period beginning January 1, 2020 at 10.25%, as compared to 12% 
requested by the Utility. The Utility’s annual cost of capital adjustment 
mechanism also remains unchanged. The decision maintains the common equity 
component of the Utility’s capital structure at 52%, as requested by the 
Utility, and reduces its preferred stock component from 1% to 0.5%, also as 
requested by the Utility. The decision also approves the cost of debt requested 
by the Utility.

The Utility estimates that the Utility’s 2020 revenue requirement associated 
with the authorized cost of capital is approximately $30 million more than the 
authorized revenue requirement at the 2019 authorized cost of capital.

The decision does not take a position or establish any orders pertaining to 
whether the Utility should be required to submit a new cost of capital 
application following its emergence from Chapter 11 bankruptcy. The decision 
defers that issue to the CPUC’s separate order instituting investigation into 
issues relating to the Utility’s bankruptcy.

2017 General Rate Case

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

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

Also, as a result of the Tax Act, on March 30, 2018, the Utility submitted to 
the CPUC a PFM of the CPUC’s final decision in the 2017 GRC proposing to reduce 
revenue requirements by $267 million and $296 million for 2018 and 2019, 
respectively, and increase rate base by $199 million and $425 million for 2018 
and 2019, respectively. On August 15, 2019, a final decision on the PFM was 
issued directing the Utility to consult with the CPUC’s Energy Division to 
ensure that its calculations include the cost of removal component of book 
depreciation when calculating the amortization of protected excess deferred 
income taxes using the ARAM and to quantify the amount of unprotected excess 
deferred taxes, which can be returned to ratepayers without following the ARAM. 
In compliance with the decision, on September 13, 2019, the Utility filed an 
advice letter with the revised calculations and the length of time the revenue 
requirement reductions would be amortized in rates. On October 17, 2019, the 
CPUC approved the Utility’s advice letter approving a revised computation of 
the effects of the Tax Act on the revenue requirements, resulting in a $282 
million reduction to the 2018 revenue requirement and a $291 million reduction 
to the 2019 revenue requirement. The Utility will incorporate these revenue 
requirement reductions into rates beginning on January 1, 2020 and later in 
2020, along with other anticipated changes, such as the 2020 GRC phase one. The 
IRS is expected to provide additional guidance on ARAM. This IRS guidance may 
impact the Utility’s calculation of the related revenue requirement. It is 
uncertain when the IRS guidance may be issued.

The Utility provided an update of the cost effectiveness study for the 
SmartMeterTM Upgrade project to the CPUC on July 10, 2017. On October 24, 2019, 
the CPUC adopted a final decision that finds (i) the July 10, 2017 study is a 
thorough and complete update of the cost-effectiveness of the project and (ii) 
the Utility should submit an updated version of the cost effectiveness study as 
a stand-alone exhibit in each GRC Phase I application that the Utility files in 
the future.

2020 General Rate Case

On December 20, 2019, the Utility together with the PAO, TURN, CUE, the CPUC’s 
Office of the Safety Advocate, the National Diversity Coalition, the Center for 
Accessible Technology, the Small Business Utility Advocates, and California 
City County Street Light Association filed a motion with the CPUC seeking 
approval of a settlement agreement that resolves all of the issues raised by 
these parties in the Utility’s 2020 GRC.

Revenue Requirements and Attrition Year Revenues

For the Utility’s largest requests in the GRC application (i.e., the CWSP and 
excess liability insurance costs), the settlement agreement includes the 
following terms:

•Funding of the Utility’s CWSP forecast through a new two-way Wildfire 
Mitigation Balancing Account. This would include the costs associated with 
overhead system hardening and other incremental costs of wildfire mitigations 
that are approved by the CPUC. A reasonableness review threshold would apply if 
the Utility wishes to recover costs beyond 115% of the adopted forecast or 
average unit cost.

•Combination of routine and enhanced vegetation management costs in a new 
two-way Vegetation Management Balancing Account to track and record actual 
vegetation management costs (routine and enhanced) beyond the adopted level. A 
reasonableness review threshold would apply if the Utility wishes to recover 
beyond 120% of the adopted forecast. This new account would replace the 
currently established one-way Vegetation Management Balancing Account that 
covered costs for the routine program.

•A new two-way electric and gas Risk Transfer Balancing Account to record the 
difference between the amounts adopted for liability insurance premiums and the 
Utility’s actual costs. This two-way account would allow the Utility to pass 
through actual insurance premium costs for up to $1.4 billion in coverage. The 
Utility could also request additional coverage through an advice letter and/or 
pursue self-insurance.

Capital Additions and Rate Base

The settlement agreement assumes a 2020 weighted average rate base of 
approximately $29.4 billion for the portions of the Utility’s business reviewed 
in the GRC, compared with the Utility’s original request of approximately $29.9 
billion. The $0.5 billion difference is primarily due to the lower level of 
working capital, depreciation and other reductions in the settlement agreement. 
This rate base amount includes $601 million of forecast capital spend in 2020 
that will not earn an equity return, pursuant to AB 1054. For the purpose of 
the settlement agreement, the Utility calculated a weighted average rate base 
of $31.0 billion and $33.0 billion for 2021 and 2022, respectively. The Utility 
submitted its five-year financial forecast, including projected capital 
expenditure assumptions, in connection with its chapter 11 proceedings. While 
the Utility currently is evaluating capital expenditure assumptions, capital 
additions and rate base amounts may materially increase from the current 
forecast.

Over the 2020-2022 GRC period, the settlement agreement provides average annual 
capital investments of approximately $4.6 billion in electric distribution, 
natural gas distribution and electric generation infrastructure. While the 
settlement agreement proposes overall revenue requirement increases for 2021 
and 2022, it does not specify capital expenditures for those years.

Consistent with the Utility’s GRC application, the settlement agreement does 
not propose funding for claims resulting from the 2017 Northern California 
wildfires or the 2018 Camp fire. Also, the Utility is not seeking recovery of 
compensation of PG&E Corporation’s and the Utility’s officers.

On December 2, 2019, the CPUC revised the procedural schedule for this 
proceeding.

Opening and reply briefs on disputed issues outside of the settlement agreement 
were submitted to the CPUC by several parties on January 6, 2020 and January 
27, 2020, respectively. Opening and reply comments on the settlement agreement 
were submitted to the CPUC by several parties on January 21, 2020 and February 
5, 2020, respectively.

As a result of the settlement and based on other facts and circumstances known 
to PG&E Corporation and the Utility as of the date of this filing, PG&E 
Corporation and the Utility expect to remain on track to satisfy the rate base 
conditions included in their exit financing documents.

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

In accordance with a January 16, 2020 CPUC decision in its OIR to Develop a 
Risk-Based Decision-Making Framework to Evaluate Safety and Reliability 
Improvements and Revise the GRC Plan the decision, the Utility is required to 
file with the CPUC on June 30, 2021 a single “general rate case” application 
requesting integrated GRC and GT&S related revenue requirements for test year 
2023 and three attrition years.

2015 Gas Transmission and Storage Rate Case

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

As a result of the Tax Act, on March 30, 2018, the Utility submitted to the 
CPUC a PFM of the CPUC’s final decision in the 2015 GT&S rate case proposing to 
reduce revenue requirements by $58 million and increase rate base by $12 
million for 2018 (excluding the impacts of an approximately $7 million increase 
in revenue requirement and a $60 million increase in rate base associated with 
the Utility’s private letter ruling advice letter approved by the CPUC on July 
18, 2018). On August 15, 2019, a final decision on the PFM was issued directing 
the Utility to consult with the CPUC’s Energy Division to ensure that its 
calculations include the cost of removal component of book depreciation when 
calculating the amortization of protected excess deferred income taxes using 
the ARAM and to quantify the amount of unprotected excess deferred taxes, which 
can be returned to ratepayers without following the ARAM. In compliance with 
the decision, on September 13, 2019, the Utility filed an advice letter with 
the revised calculations and the length of time the revenue requirement 
reductions would be amortized in rates. On October 17, 2019, the CPUC approved 
the Utility’s advice letter approving a revised computation of the effects of 
the Tax Act on the revenue requirements, resulting in a $61 million reduction 
to the 2018 revenue requirement. The Utility incorporated the revenue 
requirement reduction into rates beginning January 1, 2020. The IRS is expected 
to provide additional guidance on ARAM. This IRS guidance may impact the 
Utility’s calculation of the related revenue requirement. It is uncertain when 
the IRS guidance may be issued.

2019 Gas Transmission and Storage Rate Case

On September 12, 2019, the CPUC voted the final decision in the 2019 GT&S rate 
case of the Utility. By approving the decision, the CPUC adopted a 2019 revenue 
requirement of $1.332 billion compared to the Utility’s (revised) request of 
$1.485 billion. This corresponds to an increase of $31 million over the 
Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to 
the $184 million increase requested by the Utility. The CPUC also adopted 
revenue requirements of $1.432 billion for 2020, $1.516 billion for 2021, and 
$1.580 billion for 2022, compared to the Utility’s request of $1.595 billion 
for 2020, $1.693 billion for 2021, and $1.679 billion for 2022.

The decision removed from rate base approximately $304 million on a forecasted 
basis of pipeline replacement capital expenditures for the 2015-2018 period due 
to cost overruns; the Utility submitted updated recorded numbers to the CPUC 
that calculate the disallowance as $237 million. Incorporating the forecast 
reduction, the decision adopted a rate base for 2019 of $4.46 billion, which 
corresponds to an increase of $0.75 billion over the 2018 adopted rate base of 
$3.71 billion. This is compared to the Utility’s rate base request of $4.75 
billion for 2019. The decision adopted a rate base of $4.98 billion for 2020, 
$5.37 billion for 2021, and $5.71 billion for 2022.

The rate base amounts also exclude approximately $576 million of capital 
spending subject to audit by the CPUC (related to 2011 through 2014 
expenditures in excess of amounts adopted in the 2011 GT&S rate case), pursuant 
to the 2015 GT&S rate case decision. The Utility is unable to predict whether 
the $576 million, or a portion thereof, will ultimately be approved by the CPUC 
and included in the Utility’s future rate base.

The decision adopted capital expenditures of $726 million for 2019, which 
corresponds to a decrease of $104 million over the Utility’s request of $830 
million. The decision adopted a post-test year ratemaking joint stipulation 
proposed by the Utility and PAO. The joint stipulation results in adopted 
capital expenditures of $697 million in 2020, $597 million in 2021, and $570 
million in 2022.

The decision adopted the Utility’s proposed Natural Gas Storage Strategy, with 
minor modifications related to the decommissioning or sale of the Utility’s Los 
Medanos and Pleasant Creek storage fields, and the decision adopted a two-way 
balancing account for storage costs, which will be subject to a reasonableness 
review in the next GT&S rate case. The decision retained a number of existing 
memorandum accounts and one-way balancing accounts, including a one-way expense 
balancing account for transmission integrity management, and adopted 19 new 
expense and capital one-way balancing and memorandum accounts.

The decision also resolved the second phase of this proceeding, addressing the 
removal of officer compensation costs from the revenue requirement, which is 
required by California Senate Bill 901. On this matter, the decision adopted 
the joint stipulation offered by the Utility, PAO and TURN that reduces the 
Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital 
expenditures by $0.455 million.

On October 23, 2019, the Utility filed an application with the CPUC requesting 
the rehearing of the final decision. Specifically, issues identified by the 
Utility include the adopted disallowance associated with vintage pipe 
replacement, reduction in the Utility’s expense forecast for in-line 
inspections, and establishment of a memo account for Internal Corrosion Direct 
Assessment. The Utility cannot predict the timing and outcome of this matter.

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 be 
required to combine the GRC and GT&S rate cases starting with the 2023 GRC and 
2023 GT&S rate case. In accordance with the decision, on June 30, 2021, the 
Utility is required to file with the CPUC a single “general rate case” 
application requesting integrated GRC and GT&S related revenue requirements for 
test year 2023 and three attrition years.

Transmission Owner Rate Cases

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

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

On February 28, 2018, the Utility filed a motion to establish procedures on 
remand requesting additional briefing on the issues identified in the Ninth 
Circuit Court’s opinion. On August 20, 2018, FERC issued an order granting the 
Utility’s motion to allow for additional briefing. The order also consolidated 
the TO18 rate case with TO16 and TO17 for this issue. The Utility filed initial 
briefs on September 19, 2018 and reply briefs on October 10, 2018. On July 18, 
2019, FERC issued its order on remand reaffirming its prior grant of the 
Utility’s request for the 50 basis point ROE adder. On August 16, 2019, a 
number of parties filed for rehearing of that order. As a result, on September 
16, 2019, FERC extended the amount of time it has to consider the request for 
rehearing by issuing a tolling order for the limited purpose of further 
consideration of the matters raised in the request.

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

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

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

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

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

Once the FERC issues its decision, the Utility expects one or more parties to 
seek rehearing of that decision and then appeal it to the courts. The Utility 
is unable to predict the timing and outcome of this proceeding.

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

On July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 
2018 retail electric transmission revenue requirement of $1.79 billion, a $74 
million increase over the proposed 2017 revenue requirement of $1.72 billion. 
The forecasted network transmission rate base for 2018 was $6.9 billion. The 
Utility sought an ROE of 10.75%, which includes an incentive component of 50 
basis points for the Utility’s continuing participation in the CAISO. In the 
filing, the Utility forecasted capital expenditures of approximately $1.4 
billion. On September 28, 2017, the FERC issued an order accepting the 
Utility’s July 2017 filing, subject to hearing and refund, and established 
March 1, 2018 as the effective date for rate changes. The FERC also ordered 
that the hearings be held in abeyance pending settlement discussion among the 
parties. On May 14, 2018, the Utility filed a proposal to reflect the impact of 
the Tax Act on its TO tariff rates effective March 1, 2018, in the resolution 
of the TO19 rate case. The tax impact reduces the TO19 requested revenue 
requirement from $1.79 billion to $1.66 billion.

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

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

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

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

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

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

On May 9, 2019, the Utility filed an application with the FERC requesting 
revisions to its TO20 rate case formula rate model to remove the impact of the 
non-cash wildfire-related charges on the ratio of common equity to total 
capital. The Utility indicates in its application that, because of the 
recording of the non-cash wildfire-related charges in connection with the 2017 
Northern California wildfires and the 2018 Camp fire, the Utility’s financial 
statements reflected a ratio of common equity to total capital of approximately 
41% as of December 31, 2018. The Utility indicates that the proposed revisions 
adjust the equity ratio to accurately reflect how the Utility financed the 
capital projects that are included in rate base. The Utility’s current rate 
base was financed with an equity ratio of approximately 52%, rather than the 
41% equity ratio. In addition, on May 9, 2019, the Utility submitted a request 
to the FERC to exclude the wildfire charge from the Utility’s capital structure 
for the purpose of calculating its allowance for funds used during construction 
effective January 1, 2019.

On July 10, 2019, the FERC accepted the Utility’s revisions to the formula rate 
to become effective December 9, 2019, subject to refund, established hearing 
and settlement judge procedures, and reflected it with the Utility’s TO20 case.

On November 27, 2019, the Utility filed its annual update filing under the TO20 
Formula Rate for the rate year 2020 for the rates that will be effective 
January 1 through December 31, 2020, subject to refund and true-up.

The parties conducted several settlement conferences throughout 2019 and 
currently expect to file a partial settlement with the FERC no later than March 
31, 2020.

Nuclear Decommissioning Cost Triennial Proceeding

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

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

On February 14, 2019, the CPUC issued a scoping memo addressing the scope of 
the Utility’s 2018 NDCTP application to include the reasonableness of the 
Diablo Canyon decommissioning cost estimate, ratemaking proposals, proposed 
Diablo Canyon milestone framework, plans to address host community needs, 
reasonableness of Humboldt Bay Power Plant decommissioning costs, and 
reasonableness of performing Diablo Canyon planning activities pre-shutdown, 
including the proposed rate of recovery of these pre-planning activities 
addressed in the Utility’s application for authorization to establish the 
Diablo Canyon decommissioning planning memorandum account

On March 7, 2019, the CPUC amended the scoping memo to combine the Diablo 
Canyon DPM account application, which seeks authorization for the Utility to 
establish the Diablo Canyon Decommissioning Memorandum Account to track funding 
for Diablo Canyon pre-shutdown decommissioning planning activities, with the 
2018 NDCTP. The CPUC approved the Utility to establish an interim mechanism to 
track decommissioning planning activity expenses in the Diablo Canyon 
Decommissioning Memorandum Account. Any Memorandum Account recovery of such 
expenses is subject to the authorization and approval of the CPUC, which will 
be discussed in this year’s NDCTP. The assigned ALJ deferred the decision of 
cost recovery until after the NRC addresses the Utility’s December 13, 2018 
exemption request, in which the Utility requested an exemption to allow the 
Utility to withdraw from the NDT to fund decommissioning planning activities. 
The CPUC held public participation hearings on August 7 and 8, 2019 for 
residents and organizations in and near San Luis Obispo in connection with the 
Utility’s request.

On September 10, 2019, the NRC issued a letter granting the Utility’s request 
for an exemption and authorizing the Utility to access the NDT for up to $187.8 
million on decommissioning planning activities. On October 4, 2019, the Utility 
submitted supplemental testimony to the NRC addressing how it proposes to 
modify its request in light of the NRC exemption and the Utility’s proposed 
disposition of and ratemaking treatment of the planned Baywood Feed, a 
12-kilovolt transmission line.

On October 24, 2019, the Utility and TURN requested a suspension of the 
procedural schedule in order to allow parties to continue settlement 
discussions. On January 10, 2020, the settlement agreement that the parties had 
reached was filed with the CPUC, along with a joint motion for adoption of 
settlement agreement.

Under the proposed settlement agreement, the Utility would collect annual 
revenue requirements of $112.5 million and $3.9 million over for the funding of 
the Diablo Canyon tax qualified trust and Humboldt Bay tax qualified trust, 
respectively, commencing January 1, 2020. Additionally, under the proposed 
settlement agreement, the $398.4 million spent for Humboldt Bay Power Plant 
decommissioning project costs completed to date would be deemed reasonable.

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

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

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

On October 1, 2019, the Alliance for Nuclear Responsibility filed a PFM of the 
CPUC’s January 11, 2018 decision approving the planned retirement of Diablo 
Canyon. The PFM argues that above-market costs attributable to Diablo Canyon 
under the Power Charge Indifference Adjustment methodology, when combined with 
decreasing bundled load by the Utility, create material changed circumstances 
that undermine the reasonableness of incurring costs to operate Diablo Canyon 
until its retirement. On October 31, 2019, the Utility filed a joint response 
with Friends of the Earth, Natural Resources Defense Council, CUE, and IBEW 
Local 1245, which argued that modification of the CPUC’s initial decision is 
not warranted and is not in the public interest. On February 7, 2020, the ALJ 
issued a PD denying the Alliance for Nuclear Responsibility’s PFM. The CPUC 
decision on the PD is anticipated no later than March 2020.

Wildfire Expense Memorandum Account

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to 
establish a WEMA to track specific incremental wildfire liability costs 
effective as of July 26, 2017. In the WEMA, the Utility can record costs 
related to wildfires, including: (1) payments to satisfy wildfire claims, 
including any deductibles, co-insurance and other insurance expenses paid by 
the Utility but excluding costs that have already been forecasted and adopted 
in the Utility’s GRC; (2) outside legal costs incurred in the defense of 
wildfire claims; (3) insurance premium costs not in rates; and (4) the cost of 
financing these amounts. Insurance proceeds, as well as any payments received 
from third parties, or through FERC authorized rates, will be credited to the 
WEMA as they are received. The WEMA will not include the Utility’s costs for 
fire response and infrastructure costs, which are tracked in the CEMA. The 
decision does not grant the Utility rate recovery of any wildfire-related 
costs. Any such rate recovery would require CPUC authorization in a separate 
proceeding.

As of December 31, 2019, the Consolidated Financial Statements include 
long-term regulatory assets, consisting of insurance premium costs that are 
probable of recovery (see “Long-Term Regulatory Assets” in Note 4 of the Notes 
to the Consolidated Financial Statements in Item 1). Should PG&E Corporation 
and the Utility conclude in future periods that recovery of insurance premiums 
in excess of amounts included in authorized revenue requirements is no longer 
probable, PG&E Corporation and the Utility will record a charge in the period 
such conclusion is reached.

Catastrophic Event Memorandum Account Applications

The CPUC allows utilities to recover the reasonable, incremental costs of 
responding to catastrophic events that have been declared a disaster or state 
of emergency by competent federal or state authorities through a CEMA. In 2014, 
the CPUC directed the Utility to perform additional fire prevention and 
vegetation management work in response to the severe drought in California. The 
costs associated with this work are tracked in the CEMA. The Utility’s CEMA 
applications are subject to CPUC review and approval.

2019 CEMA Application

On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA 
application requesting cost recovery of $159.3 million in connection with 
thirteen catastrophic events that included twelve wildfires and one storm for 
declared emergencies from mid-2017 through 2018. The 2019 CEMA application does 
not include costs related to the 2015 Butte fire, the 2017 Northern California 
wildfires, or the 2018 Camp fire. A prehearing conference was held on November 
4, 2019 and a scoping memo was issued on December 6, 2019.

95

PG&E Corporation and the Utility are unable to predict the timing and outcome 
of this overall proceeding.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application 
requesting cost recovery of $183 million in connection with seven catastrophic 
events that included fire and storm declared emergencies from mid-2016 through 
early 2017, as well as $405 million related to work performed in 2016 and 2017 
to cut back or remove dead or dying trees that were exposed to years of drought 
conditions and bark beetle infestation. The 2018 CEMA application originally 
sought cost recovery of $555 million on a forecast basis, for additional tree 
mortality and fire risk mitigation work anticipated in 2018 and 2019, subject 
to true-up if actual costs were greater or less than the forecast. However, on 
April 25, 2019, the CPUC adopted a decision denying cost recovery on a forecast 
basis for the 2018 and 2019 costs requested.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate 
relief, allowing for recovery of $373 million of costs (63% of the total costs 
incurred in 2016 and 2017), compared to $588 million requested by the Utility. 
The interim rate relief was implemented on October 1, 2019. Costs included in 
the interim rate relief are subject to audit and refund. On August 7, 2019, the 
Utility filed a Revised Application, Revised Testimony and Revised Workpapers, 
reflecting a new revenue requirement request of $669 million, pursuant to CPUC 
ruling allowing these changes. The $669 million incorporates (i) the removal of 
forecast tree mortality costs (reduction of approximately $555 million); (ii) 
inclusion of the 2018 Tree Mortality and Fire Risk Reduction activities 
(increase of approximately $90 million); and (iii) other corrections and 
updates found since the filing (reduction of approximately $9 million), as 
compared to the Utility’s original request of $1.14 billion.

The 2018 CEMA application does not include costs related to the 2015 Butte 
fire, the 2017 Northern California wildfires, or the 2018 Camp fire.

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

Fire Hazard Prevention Memorandum Account

The CPUC allows utilities to track and record costs associated with 
implementing regulations and requirements adopted to protect the public from 
potential fire hazards associated with overhead power line facilities and 
nearby aerial communication facilities that have not been previously authorized 
in another proceeding. The Utility tracked such costs in the FHPMA through the 
end of 2019.

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of 
the Safety Advocate, and CUE jointly submitted to the CPUC a proposed 
settlement agreement in connection with the OII into the 2017 Northern 
California Wildfires and the 2018 Camp Fire. Pursuant to the settlement 
agreement, the Utility agrees, among other things, to not seek recovery of $36 
million of wildfire-related expenses recorded in the FHPMA. For more 
information on the settlement agreement, see Note 15 of the Notes to the 
Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement in connection with 
the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire, the 
Utility believes such costs are recoverable but rate recovery requires CPUC 
reasonableness review and authorization in a separate proceeding or through a 
GRC.

Fire Risk Mitigation Memorandum Account

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs 
incurred beginning January 1, 2019, for fire risk mitigation activities that 
are not otherwise covered in revenue requirements. The FRMMA was authorized by 
SB 901 and AB 1054 to capture mitigation costs of activities not included in a 
CPUC approved Wildfire Mitigation Plan. The Utility has proposed that the FRMMA 
continue after the approval of its 2019 Wildfire Mitigation Plan to record 
costs of wildfire mitigation activities that were beyond the initial identified 
scope of work.

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of 
the Safety Advocate, and CUE jointly submitted to the CPUC a proposed 
settlement agreement in connection with the OII into the 2017 Northern 
California Wildfires and the 2018 Camp Fire. Pursuant to the settlement 
agreement, the Utility agrees, among other things, to not seek recovery of $236 
million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For 
more information on the settlement agreement, see Note 15 of the Notes to the 
Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement in connection with 
the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire, the 
Utility intends to seek recovery of the FRMMA balance in a future application, 
which rate recovery requires CPUC reasonableness review and authorization in a 
separate proceeding or through a GRC. PG&E Corporation’s and the Utility’s 
financial condition, results of operations, liquidity and cash flows could be 
materially affected if the Utility is unable to timely recover costs in 
connection with the 2019 Wildfire Mitigation Plan recorded in the FRMMA, which 
the Utility expects will be substantial.

For the amount recorded to this memorandum account as of December 31, 2019, see 
Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

Wildfire Mitigation Plan Memorandum Account

On June 5, 2019, the Utility submitted an advice letter to establish the WMPMA 
(also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The 
purpose of the WMPMA is to track costs incurred to implement the Utility’s 
Wildfire Mitigation Plan, as required by Public Utilities Code Sections 8386 et 
seq, as modified by SB 901 and subsequent bills including AB 1054, AB 111, SB 
70, SB 167, SB 247, and SB 560. The WMPMA is required to be established upon 
approval of a utility’s wildfire mitigation plan to track costs incurred to 
implement the plan. The CPUC approved the memorandum account on August 5, 2019, 
so the Utility will record any costs incurred in implementing an approved 
Wildfire Mitigation Plan as of the effective date, June 5, 2019.

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of 
the Safety Advocate, and CUE jointly submitted to the CPUC a proposed 
settlement agreement in connection with the OII into the 2017 Northern 
California Wildfires and the 2018 Camp Fire. Pursuant to the settlement 
agreement, the Utility agrees, among other things, to not seek recovery of $236 
million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For 
more information on the settlement agreement, see Note 15 of the Notes to the 
Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement in connection with 
the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire, the 
Utility anticipates that the recovery of the costs recorded to the WMPMA would 
occur through a general rate case or future application at which time the CPUC 
would review the costs for reasonableness as required by SB 901. PG&E 
Corporation’s and the Utility’s financial condition, results of operations, 
liquidity and cash flows could be materially affected if the Utility is unable 
to timely recover costs in connection with the 2019 Wildfire Mitigation Plan 
recorded in the WMPMA, which the Utility expects will be substantial.

For the amount recorded to this memorandum account as of December 31, 2019, see 
Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

Other Regulatory Proceedings

2019 Wildfire Mitigation Plan

On October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 
901 related to electric utility wildfire mitigation plans. This OIR provided 
guidance on the form and content of the initial wildfire mitigation plans, 
provided a venue for review of the initial plans, and developed and refined the 
content of and process for review and implementation of wildfire mitigation 
plans to be filed in future years. In this proceeding the CPUC determined, 
among other things, how to interpret and apply SB 901’s list of required plan 
elements, as well as what additional elements beyond those required in SB 901 
should be included in the wildfire mitigation plans. SB 901 also requires, 
among other things, that such plans include a description of the preventive 
strategies and programs to be adopted by an electrical corporation to minimize 
the risk of its electrical lines and equipment causing catastrophic wildfires, 
including the consideration of dynamic climate change risks, plans for 
vegetation management, and plans for inspections of the electrical 
corporation’s electrical infrastructure. The scope of this proceeding does not 
include utility recovery of costs related to wildfire mitigation plans, which 
SB 901 requires to be addressed in separate rate recovery applications.

On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 
Wildfire Mitigation Plan”) with the CPUC. The 2019 Wildfire Mitigation Plan 
describes forecasted work and investments in 2019 that are designed to help 
further reduce the potential for wildfire ignitions associated with the 
Utility’s electrical equipment in high fire-threat areas. The 2019 Wildfire 
Mitigation Plan includes measures the Utility proposed to take in 2019 and 
longer-term plans, subject to further modifications, as follows:

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

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

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

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

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

•expanding the PSPS to include all transmission and distribution lines in Tier 
2 and Tier 3 High Fire-Threat District areas;

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

•partnering with additional communities in high fire-threat areas to create new 
resilience zones that can power central community resources during a PSPS.

On February 12, February 14, and April 25, 2019, the Utility filed amendments 
to the 2019 Wildfire Mitigation Plan with the CPUC to correct inadvertent 
errors in the cost table attached to the 2019 Wildfire Mitigation Plan; refine 
language in the 2019 Wildfire Mitigation Plan; and modify certain 2019 Wildfire 
Mitigation Plan targets.

On May 30, 2019, the CPUC adopted a decision that generally approved the 
Utility’s 2019 Wildfire Mitigation plan as amended February 14, 2019, subject 
to certain reporting, data gathering, and other requirements set forth in the 
decision. Also, on May 30, 3019, the Utility adopted another decision regarding 
California IOUs wildfire mitigation plans, that among other things, includes 
additional reporting, data gathering, and other requirements.

On June 14, 2019, the assigned commissioner and ALJ issued a decision 
implementing Phase 2 of the OIR, announcing Phase 2 workshops. The decision 
also announced that the CPUC would evaluate the Utility’s April 25th amendment 
in Phase 2, as well as the process for independent evaluation of the Utility’s 
compliance with its 2019 plan.

On August 23, 2019, the CPUC approved the Utility’s Initial Safety 
Certification, which under AB 1054 entitles the Utility to certain benefits, 
including eligibility for a cap on wildfire fund reimbursement and for a 
reformed prudent manager standard. The Utility satisfied the required elements 
for its Initial Safety Certificate, as follows: (i) the electrical corporation 
has an approved wildfire mitigation plan, (ii) the electrical corporation is in 
good standing, which can be satisfied by the electrical corporation having 
agreed to implement the findings of its most recent safety culture assessment, 
if applicable, (iii) the electrical corporation has established a safety 
committee of its board of directors composed of members with relevant safety 
experience, and (iv) the electrical corporation has established 
board-of-director-level reporting to the CPUC on safety issues. The Initial 
Safety Certification is valid for twelve months.

On September 18, 2019, the CPUC issued a scoping memo and ruling for Phase 2 
setting the scope and procedural schedule. On December 16, 2019, the CPUC 
issued a ruling proposing WMP templates and evaluative materials on which the 
CPUC would rely for 2020 wildfire mitigation plans. These included WMP 
Guidelines, a maturity model, a utility survey, WMP metrics, and a supplemental 
data request. The utilities are required to complete the WMP Guidelines and the 
utility survey when submitting the 2020 WMP. Since December 16, 2019, the CPUC 
has held a number of workshops and issued clarifications of the December 16, 
2019 materials.

On February 5, 2020, the assigned ALJ issued a PD in Phase 2 of this proceeding 
on electrical corporations’ wildfire mitigation plans. It resolves one Phase 2 
issue by requiring all electrical corporations to conduct outreach to 
communities and the public before, during, and after a wildfire. If adopted, 
the PD would clarify among other things where the additional Phase 2 issues 
will be resolved: the CPUC’s newly created Wildfire Safety Division would 
review 2020 wildfire mitigation plans, present resolutions for CPUC 
consideration on the 2020 Plans, and oversee independent evaluation and other 
compliance activity with regard to both 2019 and 2020 Plans. Opening and reply 
comments are due on February 25, 2020 and March 2, 2020, respectively. The CPUC 
decision on the PD is expected no later than March 2020.

2020-2022 Wildfire Mitigation Plan

On February 7, 2020, the Utility publicly posted its 2020 Wildfire Mitigation 
Plan and utility survey. The Utility’s 2020 Wildfire Mitigation Plan describes 
the Utility’s wildfire safety programs, which are focused on three key areas: 
reducing the potential for fires to be started by electrical equipment, 
reducing the potential for fires to spread, and minimizing the frequency, scope 
and duration of Public Safety Power Shut-off events, as well as providing 
historical data requested by the guidelines. The primary programs include 
continuing enhanced vegetation management, system hardening, system automation, 
the wildfire safety operations center, installing additional situational 
awareness tools, and public safety power shutoffs, as well as working to reduce 
the frequency, scope, and duration of public safety power shutoffs. The Utility 
plans to conduct enhanced vegetation management on approximately 1,800 miles of 
lines for 2020 and beyond based on insights gained from the 2019 effort. The 
Utility is also incorporating the enhanced inspection process and tools from 
the 2019 wildfire safety inspection program into the routine inspection and 
maintenance program. For 2020, the Utility plans the following improvements: 
hardening 241 line-miles for a total of 7,100 line miles over 12 to 14 years; 
sectionalizing 592 devices; making PSPS events fewer, smaller and shorter; 
installing 400 weather stations and 200 cameras; and operating additional 
microgrids during PSPS events. The utility survey will be used to collect 
information relevant to track the utility’s capabilities in reducing wildfire 
risk and corresponding maturity levels over time. Along with other inputs, 
responses to the survey will establish a baseline maturity in 2020 and a target 
maturity for 2023.

PG&E Corporation and the Utility expect the CPUC to issue a decision on its 
2020-2022 WMP by June 2020. PG&E Corporation’s and the Utility’s financial 
condition, results of operations, liquidity and cash flows could be materially 
affected if the Utility is unable to timely recover costs in connection with 
the 2019 Wildfire Mitigation Plan, and the 2020-2022 Wildfire Mitigation Plan 
recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

OIR Regarding Microgrids

On September 19, 2019, the CPUC initiated a rulemaking proceeding to examine 
microgrid implementation issues and resiliency strategies pursuant to SB 1339. 
In the first track of that proceeding, the CPUC is seeking to deploy resiliency 
planning in areas that are prone to outage events and wildfires, with the 
stated goal of putting some microgrid and other resiliency strategies in place 
by Spring or Summer 2020, if not sooner. A decision giving direction for 
mitigation measures ready for implementation by September 1, 2020 is expected 
in Spring 2020. At the CPUC’s direction, the Utility submitted a proposal for 
immediate implementation of resiliency strategies on January 21, 2020. The 
Utility’s proposal contains three components for which it is seeking scope and 
cost recovery authorization of up to approximately $379 million in both expense 
and capital. These include:

•a make-ready program to invest in the infrastructure needed to allow 
high-priority substations and associated downstream infrastructure to operate 
as microgrids through the use of distributed generation (“DG”). The Utility is 
also conducting a Request for Offers for permanent DG to serve these 
substations and plans to file for cost recovery and approval of any executed 
contracts for permanent generation through a separate CPUC proceeding;

•a temporary generation program to provide mobile, temporarily-sited DG at 
substations, mid-feeder line segments serving commercial corridors and critical 
facilities, and single-customer critical facilities during PSPS events; and

•a community microgrid enablement program to provide incremental technical and 
financial support on a prioritized basis for community-requested microgrids for 
PSPS shutoff mitigation purposes.

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

OIR Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to 
Senate Bill 901

SB 901, signed into law on September 21, 2018, requires 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 authorizes the CPUC to issue a financing order that 
permits recovery, through the issuance of recovery bonds (also referred to as 
“securitization”), of wildfire-related costs found to be just and reasonable by 
the CPUC and, only for the 2017 Northern California wildfires, any amounts in 
excess of the CHT. SB 901 does not authorize securitization with respect to 
possible 2018 Camp fire costs.

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

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

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

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

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

OII to Consider PG&E Corporation’s and the Utility’s Proposed Plan of 
Reorganization

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 Chapter 11 Proceedings OII 
indicates that the proceeding will “afford parties the opportunity to be heard 
and comment on” any CPUC “regulatory review resulting from a proposed plan of 
reorganization (including any amendments) filed with the Commission, any 
proposed settlement agreement resolving [the Chapter 11 Cases] between PG&E and 
Commission staff filed in connection with a plan, any regulatory approvals 
required pursuant to Public Utilities Code Section 3292 in order for PG&E to 
become eligible to participate in the wildfire fund established pursuant to 
Assembly Bill 1054 (AB) 1054, any other regulatory approvals required by AB 
1054, and any other matters that may need to be decided by [the CPUC] in 
connection with a plan.” The OII anticipates that the proceeding “will serve as 
a venue for review of a proposed plan and all attendant issues identified as 
within the scope of this proceeding.” The CPUC “expects to render its decision 
sufficiently in advance of the June 30, 2020 statutory deadline contained in AB 
1054 to allow the Bankruptcy Court to address and approve any modifications 
made to the plan pursuant to Commission orders.”

On November 14, 2019, the assigned commissioner issued a scoping memo which 
divided the proceeding into two phases, first addressing non-financial issues 
(which include safety governance, climate goals, procurement, and other 
non-financial issues) and then financial issues (which include ratemaking, 
fines and penalties, financial governance, and other financial issues). After 
holding a status conference on December 20, 2019, the ALJ issued a ruling on 
December 27, 2019 modifying the schedule. That ruling re-combined the two 
phases of the proceeding such that financial and non-financial issues will be 
considered together. On January 16, 2020, the Utility filed a motion to further 
modify the schedule, which the ALJ granted in part. Pursuant to that modified 
schedule, on January 31, 2020, the Utility submitted testimony to the CPUC. The 
Utility’s testimony outlined key elements of the company’s updated Chapter 11 
plan of reorganization, including, but not limited to, key aspects of the 
Utility’s governance structure; implementing a plan to regionalize the 
company’s operations; appointing an independent safety advisor; strengthening 
the roles of the Chief Risk Officer and the Chief Safety Officer; utilizing an 
Independent Safety Oversight Committee with non-PG&E Corporation and 
non-Utility employees to provide independent review of the company’s 
operations; paying value in excess of $25.5 billion to wildfire victims through 
the settlements reached; and emerging with a financing structure that seeks to 
protect customer rates and position the company for long term success. Reply 
testimony was due February 14, 2020, evidentiary hearings are scheduled for 
February 19-28, 2020, and post-hearing briefing is scheduled for March 2020.

On January 22, 2020, the Utility entered into a RSA with members of the Ad Hoc 
Committee of Senior Unsecured Noteholders of the Utility and, consistent with 
that agreement, on January 23, 2020, the Ad Hoc Committee of Senior Unsecured 
Noteholders of the Utility filed a motion to withdraw from the proceeding. On 
January 30, 2020, the ALJ issued a ruling allowing the Ad Hoc Committee of 
Senior Unsecured Noteholders to withdraw as a party.

Wildfire Fund Non-Bypassable Charge

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new 
rulemaking to consider the authorization of a non-bypassable charge to support 
the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision 
finding that the imposition of the non-bypassable charge is just and 
reasonable. In addition, the decision affirmed that the Utility and its 
customers will not pay an allocated share of the adopted wildfire charge 
revenue requirement unless and until the Utility participates in the Wildfire 
Fund. The decision also continues the same allocation of the wildfire charge 
revenue requirement among the investor-owned utilities as previously adopted 
for the Department of Water Resources power and bond charge revenue 
requirements. The decision proposes revenue requirements for the Utility of 
$404.6 million, which is based on average annual collections and shall expire 
at the end of the year 2035.

On November 25, 2019, an individual intervenor filed an application for 
rehearing of the decision arguing that the decision constitutes a 
constitutional violation of procedural due process and an unjust and 
unreasonable rate increase. On December 10, 2019, the Utility, along with San 
Diego Gas and Electric Company and Southern California Edison Company argued 
that due process rights were not violated and the CPUC appropriately determined 
the non-bypassable charge is just and reasonable.

Transportation Electrification

SB 350 requires the CPUC, in consultation with the California Air Resources 
Board and the CEC, to direct electrical corporations to file applications for 
programs and investments to accelerate widespread TE. In September 2016, the 
CPUC directed the Utility and the other large IOUs to file TE applications that 
include both short-term projects (of up to $20 million in total) and 
two-to-five year programs with a requested revenue requirement determined by 
the Utility.

On May 31, 2018, the CPUC issued a final decision approving the Utility’s 
two-to-five year program proposals for actual expenditures up to approximately 
$269 million (including $198 million of capital expenditures), to support 
utility-owned make-ready infrastructure supporting public fast charging and 
medium to heavy-duty fleets. In the EV Fleet program, the Utility has a goal of 
providing make-ready infrastructure at 700 sites supporting 6,500 vehicles, 
conducting operation and maintenance of installed infrastructure, and educating 
customers on the benefits of electric vehicles. The final decision gives 
customers the option of self-funding, installing, owning, and maintaining the 
make-ready infrastructure installed beyond the customer meter in lieu of 
utility ownership, after which they would receive a utility rebate for a 
portion of those costs. The EV Fast Charge program has a goal to install 
utility-owned make-ready infrastructure at approximately 52 public charging 
sites amounting to roughly 234 DC fast chargers.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle 
electrification matters (R.18-12-006). This new proceeding will include issues 
related to utility rate designs supporting transportation electrification and 
hydrogen fueling stations, a framework for IOUs’ transportation electrification 
investments, and vehicle-grid integration. A prehearing conference for this 
rulemaking was held on March 1, 2019. On May 2, 2019, the assigned commissioner 
issued a scoping memo and ruling for the proceeding, which sets forth the 
category, issues to be addressed, and schedule of the proceeding.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed 
electric DRP for approval by the CPUC. The Utility’s DRP identifies its 
approach for identifying optimal locations on its electric distribution system 
for deployment of DERs. The Utility’s DRP approach is designed to allow 
distributed energy technologies to be integrated into the larger grid, while 
continuing to provide customers with safe, reliable, and affordable electric 
service.

On June 1, 2018 and on September 4, 2018, the Utility filed with the CPUC its 
first annual distribution grid needs assessment report and its first 
distribution deferral opportunity report, respectively. On February 5, 2019, 
the CPUC approved the Utility’s proposal to competitively procure distribution 
services from third-party owned DERs to defer selected distribution projects as 
identified in the Utility's first annual distribution deferral report. On 
December 2, 2019, the Utility filed for approval of three executed DER 
contracts related to two deferral opportunities. The Utility's second annual 
distribution grid assessment, and distribution deferral opportunity report, 
were filed on August 15, 2019. On December 16, 2019, the CPUC approved the 
Utility’s proposal to competitively procure distribution services from 
third-party owned DERs to defer selected distribution projects as identified in 
the Utility's second annual distribution deferral opportunity report.

On March 26, 2018, the CPUC issued a final decision requiring the Utility to 
include a grid modernization plan for integrating DERs in the Utility’s GRC. On 
December 13, 2018, the Utility filed its 2020 GRC Application, which includes 
the Utility’s grid modernization plan.

OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas 
Systems in California and Perform Long-Term Gas Planning

On January 16, 2020, the CPUC opened an OIR to address reliability and 
compliance standards for gas public utilities and impacts due to legislative 
mandates to address the greenhouse gas reduction emissions which will result in 
the replacement of gas-fuel technologies and reduced demand for natural gas. 
This proceeding will examine whether recent industry related events will 
require the CPUC to change the rules, processes and regulations governing gas 
utilities, including but not limited to, gas reliability standards, long-term 
contracting, regulatory accounting, reporting and tariff changes for 
operational flow orders.

This proceeding is expected to have three phases: Track 1A - System Reliability 
Standards, Track 1B - Market Structure and Regulations and Track 2 - Long Term 
Natural Gas Policy and Planning. Additionally, in Track 2, the CPUC will 
examine to what extent the projected gas demand reduction will require 
regulatory changes, such as shortening the useful life of gas assets, to ensure 
gas transmission costs are fairly allocated and that stranded costs are 
mitigated. The CPUC expects to issue a preliminary scoping memo and decision 
for each track.

Tracks 1A and 1B are expected to be completed within 18 months. Track 2 is 
expected to be resolved within 31 months in order to resolve issues to be 
considered in Track 1A and 1B and coordinate with other regulatory proceedings. 
This proceeding has been preliminarily designated as quasi-legislative. 
Evidentiary hearings may be necessary for Track 1A and Track 2. The Utility may 
file and serve opening comments on the preliminary scope no later than February 
26, 2020 and reply comments on March 12, 2020.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for 
integrating climate change adaptation matters into relevant CPUC proceedings. 
On October 10, 2018, the CPUC issued a scoping memo, establishing two phases 
for this proceeding, and determined a procedural schedule. Scope of phase one 
covers five topics regarding how to integrate climate change adaptation into 
the IOUs’ existing planning and operations to avoid or mitigate projected 
utility safety and reliability vulnerability to forecasted climate change 
impacts. Phase 2 will be scoped at a later time, but it is not expected to 
apply to the Utility. On October 24, 2019, the CPUC adopted a final decision 
extending the statutory deadline of this proceeding to September 30, 2020.

On October 24, 2019, the CPUC adopted a final decision on a portion of phase 
one (Topic 1 and 2), defining climate change adaptation for California’s energy 
utilities as “adjustment in natural and human systems to a new or changing 
environment. Adaptation to climate change for energy utilities regulated by the 
CPUC refers to adjustment in utility systems using strategic and data-driven 
consideration of actual or expected climatic impacts and stimuli or their 
effects on utility planning, facilities maintenance and construction, and 
communications, to maintain safe, reliable, affordable and resilient 
operations.” In addition, this decision provides guidance on what data should 
be used by the investor-owned utilities to perform all climate impact, climate 
risk, and climate vulnerability analyses undertaken with respect to their 
infrastructure assets, operations, and customer impacts. Finally, this decision 
requires the energy utilities to adhere to the same climate scenarios and 
projections used in the most recent California Statewide Climate Change 
Assessment when analyzing climate impacts, climate risk, and climate 
vulnerability of utility systems, operations, and customers.

The remaining topics in phase one of this proceeding are still under 
consideration and will be subject to a separate decision. Those issues include: 
guidance on how climate adaptation should be incorporated into the 
investor-owned utilities’ investment plans, program design, and operations; how 
climate change might affect vulnerable and disadvantaged communities; and into 
which specific CPUC proceedings and activities climate adaptation should be 
incorporated, including development of specific procedures. The CPUC decision 
on such issues is anticipated no earlier than mid-2020.

OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions

On December 13, 2018, the CPUC opened an OIR to examine the notification, 
mitigation, and reporting requirements on electric utilities when de-energizing 
power lines in case of dangerous conditions that threaten life or property in 
California. This proceeding has focused on the following issues:

•examining conditions in which proactive and planned de-energization is 
practiced;

•developing best practices and ensuring an orderly and effective set of 
criteria for evaluating de-energization programs;

•ensuring electric utilities coordinate with state and local level first 
responders, and align their systems with the Standardized Emergency Management 
System framework;

•mitigating the impact of de-energization on vulnerable populations;

•examining whether there are ways to reduce the need for de-energization;

•ensuring effective notice to affected stakeholders of possible de-energization 
and follow-up notice of actual de-energization; and

•ensuring consistency in notice and reporting of de-energization events.

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, 
which adopted de-energization communication and notification guidelines for the 
electric IOUs along with updates to requirements established in Resolution 
ESRB-8. The CPUC also provided clarity on phase two issues; however, a final 
determination of phase two issues will be conveyed in the phase two scoping 
memo. Phase two will take a more comprehensive look at de-energization 
practices, including mitigation, additional coordination across agencies, 
further refinements to findings in phase one, re-energization practices, and 
other matters.

On August 14, 2019, the former CPUC president issued a phase two scoping memo. 
However, subsequent to the October PSPS events, on November 1, 2019, the ALJ 
issued a ruling suspending the schedule and scope of the proceeding and 
indicating that the current CPUC president will issue an amended phase two 
scoping memo in the near future in order to refocus the direction of the 
proceeding.

On December 19, 2019, CPUC president and newly assigned commissioner issued an 
amended Phase 2 scoping memo and ruling. Pursuant to the ruling, the issues to 
be considered in the amended Phase 2 include:

•updates or changes to existing PSPS guidelines to promote public safety in 
advance of the 2020 wildfire season;

•proposed guidelines related to a variety of topics including (1) server and 
website capacity; (2) identification of transit corridors and critical 
transportation infrastructure dependent on back-up generation during a PSPS 
event; (3) operations and locations of Community Resource Centers; (4) possible 
creation of a wildfire safety community advisory board for each utility; (5) 
PSPS planning exercises in advance of wildfire season; (6) communication and 
notification during PSPS events when communication services may be disrupted; 
(7) assistance to medical baseline customers in the near term; (8) plans to 
better execute identification, communication, and contact with vulnerable 
populations that may not be considered medical baseline.

On January 30, 2020, the CPUC proposed new guidelines. Parties are given the 
opportunity to submit opening and reply comments on the guidelines on February 
19, 2020 and February 26, 2020, respectively. A proposed decision is 
anticipated in May 2020.

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

Order to Show Cause Against the Utility Related to Implementation of the 
October 2019 PSPS Events

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine 
Utility De-energization of Power Lines in Dangerous Conditions issued an order 
to show cause directing the Utility to show cause why it should not be 
sanctioned for violations of law or CPUC decisions related to the PSPS events 
of October 9-12, 2019 and October 23-November 1, 2019.

A prehearing conference was held on December 4, 2019, and the assigned 
commissioner and ALJ issued a ruling on December 23, 2019 and set forth issues 
to be determined in the order to show cause, including related to failures 
associated with the Utility’s website, online maps, data transfer portal, 
advanced notice to customers, and staffing at its call centers in connection 
with its October 9-12, PSPS event, as well as advance notice to customers in 
connection with the October 23-25, 2019 and the October 26-November 1, 2019 
PSPS event.

The Utility filed its testimony with the CPUC on February 5, 2020. Parties’ 
testimony is due February 28, 2020; concurrent rebuttal is due March 16, 2020; 
and hearings, if necessary, will be held April 1-3, 2020.

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

OII to Examine the Late 2019 Public Safety Power Shutoff Events

On November 13, 2019, the CPUC issued an OII to determine “whether California’s 
investor-owned utilities prioritized safety and complied with the Commission’s 
regulations and requirements with respect to their Public Safety Power Shutoff 
(PSPS) events in late 2019.” The first phase of this proceeding will assess for 
each utility, among other things, (1) the effectiveness of the utility’s 
procedures to notify the public of the PSPS events, (2) the utility’s 
communication and coordination with first responders, local jurisdictions and 
state agencies, and (3) the utility’s management of its resources to ensure 
public safety. In later phases of this proceeding, the CPUC may consider taking 
action if it finds violations of statutes or its decisions or general orders 
have been committed and to enforce compliance, if necessary.

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

Power Charge Indifference Adjustment OIR

In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the 
PCIA, a cost recovery mechanism to ensure that customers that leave the 
Utility’s bundled service for a non-Utility provider pay their fair share of 
the above market costs associated with long-term power purchase commitments and 
Utility-owned generation made on their behalf. The above market costs of the 
Utility’s generation portfolio are calculated using benchmarks for energy, 
resource adequacy (RA) and RPS attributes. On October 11, 2018, the CPUC 
approved a phase one decision to modify the PCIA methodology establishing:

•calculation of the PCIA rate using benchmark values that more closely resemble 
actual market prices for RA and RPS;

•continued recovery of legacy Utility-owned generation costs from departed load 
customers;

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

•an annual true-up of the PCIA rate based on actual market revenues.

The Utility implemented a revised PCIA reflecting this decision in rates as of 
July 1, 2019.

On December 19, 2018, the CPUC initiated Phase 2 of the PCIA proceeding to 
address unresolved issues from phase one, separated into three Working Groups. 
In Working Group 1, the CPUC directed parties to (1) establish the method to 
annually update the RA and RPS price benchmarks, (2) determine the process for 
the annual true-up of PCIA rates to reflect actual market outcomes, and (3) 
determine the proper billing factors for setting the PCIA rate. A PD was issued 
on September 6, 2019. On October 10, 2019, the CPUC approved a final decision 
that:

•approves a methodology for annually setting the price benchmark for RA and RPS 
based on market transactions of all load-serving entities occurring within the 
past 12 months;

•values any unsold RA and RPS attributes at zero for calculating the PCIA 
true-up at year end, meaning that bundled customers are not responsible for 
paying for RA and RPS attributes that are not needed for compliance; and

•establishes that the PCIA rates shall be calculated using the forecasted sales 
of customers in a particular billing group, rather than using system-level 
sales, to prevent a persistent under-collection of PCIA rates.

In Working Group 2, the CPUC directed parties to develop a framework evaluating 
and approving a PCIA prepayment framework, whereby departed load customers 
could eliminate their PCIA obligation through an up-front payment. The working 
group issued a final report on December 9, 2019 containing proposed guiding 
principles that the CPUC should apply when reviewing prepayment applications. A 
PD is expected in the first quarter of 2020.

Lastly, in Working Group 3 the CPUC directed parties to develop structures and 
rules governing how the Utility addresses excess resources in its portfolio due 
to load loss to CCA and DA, including standards for active management of the 
Utility’s portfolios. A PD is expected in the third quarter of 2020.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a 
CHT, directing the CPUC to limit certain disallowances in the aggregate, so 
that they do not exceed the CHT. SB 901 also authorizes the CPUC to issue a 
financing order that permits recovery, through the issuance of recovery bonds 
(also referred to as “securitization”), of wildfire-related costs found to be 
just and reasonable by the CPUC and, only for the 2017 Northern California 
wildfires, any amounts in excess of the CHT. SB 901 does not authorize 
securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to 
develop criteria and a methodology to inform determinations of the CHT in 
future applications under Section 451.2(a) of the Public Utilities Code for 
recovery of costs related to the 2017 Northern California wildfires. On March 
29, 2019, the assigned commissioner issued a scoping memo, which confirmed that 
the CPUC in this proceeding would establish a CHT methodology applicable only 
to 2017 fires, to be invoked in connection with a future application for cost 
recovery, and would not determine a specific financial outcome in this 
proceeding. On July 8, 2019, the CPUC issued a decision in the OIR, which 
establishes a methodology to establish the CHT in future applications under 
Section 451.2(a), but determines 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 the decision. The Utility indicated in 
its application, among other things, that the CPUC’s decision “is contrary to 
law because it bars a utility that has filed for Chapter 11 from accessing the 
CHT, requires a utility to file a cost recovery application before the CHT will 
be determined, and erects ratepayer protection mechanisms as an extra-statutory 
hurdle for accessing the CHT.” The Utility also argued that the CPUC should 
apply the CHT methodology to costs related to the 2018 Camp fire.

In addition, SB 901 requires utilities to submit annual wildfire mitigation 
plans for approval by the CPUC on a schedule to be established by the CPUC. The 
wildfire mitigation plan must include the components specified in SB 901, such 
as identification and prioritization of wildfire risks, and drivers for those 
risks; plans for vegetation management; actions to harden the system, prepare 
for, and respond to events; and protocols for disabling reclosers and 
deenergizing the system. The CPUC has three months to approve a utility’s plan, 
with the ability to extend the deadline. The CPUC will conduct an annual 
compliance review, which will be supported by an independent evaluator’s 
report. The CPUC will complete the compliance review within 18 months. SB 901 
establishes factors to be considered by the CPUC when setting penalties for 
failure to substantially comply with the plan. Costs associated with the 
wildfire mitigation plan are tracked in a memorandum account, and the costs of 
implementing the plan will be assessed in each utility’s GRC proceeding, or 
other application proceedings. The Utility is unable to predict the timing or 
outcome of the CPUC’s review of the wildfire mitigation plan, the results of 
the CPUC compliance review of wildfire mitigation plan implementation, or the 
timing or extent of cost recovery for wildfire mitigation plan activities. 
Subsequent bills including AB 1054, AB 111, SB 70, SB 167, SB 247, and SB 560, 
modified the wildfire mitigation plan requirements, including expanding the 
plan coverage to three years, adding additional components and requirements and 
transferring review of the plans to a new Wildfire Safety Division of the CPUC 
beginning January 1, 2020, and later to an office in the Natural Resources 
Agency beginning July 1, 2021.

Assembly Bill 1054

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

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

The Wildfire Fund to be established under AB 1054 will be available for 
eligible electric utility companies to pay eligible claims for liabilities 
arising from wildfires occurring after July 12, 2019 that are caused by the 
applicable electric utility company’s equipment. Electric utility companies 
that draw from the Wildfire Fund will only be required to repay amounts that 
are determined by the CPUC in an application for cost recovery not to be just 
and reasonable, subject to a rolling three-year disallowance cap equal to 20% 
of the electric utility company’s transmission and distribution equity rate 
base. For the Utility, this disallowance cap is expected to be approximately 
$2.3 billion for the three-year period starting in 2019, subject to adjustment 
based on changes in the Utility’s total transmission and distribution equity 
rate base. The disallowance cap is inapplicable in certain circumstances, 
including if the Wildfire Fund administrator determines that the electric 
utility company’s actions or inactions that resulted in the applicable wildfire 
constituted “conscious or willful disregard of the rights and safety of 
others,” or the electric utility company fails to maintain a valid safety 
certification. Costs that the CPUC determines to be just and reasonable will 
not need to be repaid to the Wildfire Fund, resulting in a draw-down of the 
Wildfire Fund. The Wildfire Fund and disallowance cap will be terminated when 
the amounts therein are exhausted. The Wildfire Fund is expected to be 
capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year 
extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 
billion in initial contributions from California’s three investor-owned 
electric utility companies, and (iii) $300 million in annual contributions paid 
by California’s three investor-owned electric utility companies. The 
contributions from the investor-owned electric utility companies will be 
effectively borne by their respective shareholders, as they will not be 
permitted to recover these costs from ratepayers. The costs of the initial and 
annual contributions are allocated among the three investor-owned electric 
utility companies pursuant to a “Wildfire Fund allocation metric” set forth in 
AB 1054 based on land area in the applicable utility’s service territory 
classified as high fire threat districts and adjusted to account for risk 
mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is 
expected to be 64.2% (representing an initial contribution of approximately 
$4.8 billion and annual contributions of approximately $193 million). In 
addition, all initial and annual contributions will be excluded from the 
measurement of the Utility’s authorized capital structure. The Wildfire Fund 
will only be available for payment of eligible claims so long as there are 
sufficient funds remaining in the Wildfire Fund. Such funds could be depleted 
more quickly than expected, including as a result of claims made by 
California’s other participating electric utility companies.

AB 1054 provides that the Wildfire Fund will be established when Southern 
California Edison and San Diego Gas & Electric Company provide their initial 
contributions. On September 11, 2019, Southern California Edison and San Diego 
Gas & Electric Company notified the CPUC that each had provided its respective 
initial contribution to the Wildfire Fund.

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

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

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

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

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

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

On August 23, 2019, the CPUC granted the Utility its Initial Safety 
Certification, which is valid for 12 months. While not a requirement for 
participation in the Wildfire Fund, a valid safety certification allows the 
Utility to benefit from AB 1054’s disallowance cap. (See “Regulatory Matters - 
2019 Wildfire Mitigation Plan” above.)

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the 
Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the 
Utility to participate in the Wildfire Fund and to make any initial and annual 
contributions to the Wildfire Fund upon emergence from Chapter 11. On August 
26, 2019, the Bankruptcy Court entered an order granting such authorizations.

If the Utility satisfies the requirements to participate in the Wildfire Fund, 
the Utility will be required to fund its initial contribution upon its 
emergence from Chapter 11. The Utility’s required contributions to the Wildfire 
Fund will be substantial. Participation in the Wildfire Fund is expected to 
have a material impact on PG&E Corporation’s and the Utility’s financial 
condition, results of operations, liquidity and cash flows. The Utility is 
currently evaluating the tax treatment of the required initial and annual 
contributions. The timing and amount of any potential charges associated with 
shareholder contributions would also depend on various factors, including the 
timing of resolution of the Chapter 11 Cases, the expected life of the Wildfire 
Fund, and the impact of future wildfires on the Wildfire Fund's claims passing 
capacity. The Proposed Plan filed with the Bankruptcy Court on January 31, 2020 
would provide for the financing of such required contributions, but there can 
be no assurance that PG&E Corporation and the Utility will successfully 
consummate or implement any such plan, which will ultimately require Bankruptcy 
Court, creditor and regulatory approval. Further, there can be no assurance 
that the expected benefits of participating in the Wildfire Fund ultimately 
outweigh its substantial costs.

The Utility expects to record its required contributions as an asset and 
amortize the asset over the estimated life of the Wildfire Fund. The Wildfire 
Fund asset will be further adjusted for impairment as the assets are used to 
pay eligible claims, which will result in decreases to the assets available for 
coverage of future events. AB 1054 does not establish a definite term of the 
Wildfire Fund; therefore, this accounting treatment is subject to significant 
judgments and estimates. The assumptions create a high degree of uncertainty 
related to the estimated useful life of the Wildfire Fund. The most significant 
estimate is the number and severity of catastrophic fires that could occur in 
California within the participating electric utilities’ service territories 
during the term of the Wildfire Fund. The Utility intends to utilize 
historical, publicly available fire-loss data as a starting point; however, 
future fire-loss can be difficult to estimate due to uncertainties around the 
impacts of climate change, land use changes, and mitigation efforts by the 
California electric utility companies. Other assumptions include the estimated 
cost of wildfires caused by other electric utilities, the amount at which 
wildfire claims will be settled, the likely adjudication of the CPUC in cases 
of electric utility-caused wildfires, the level of future insurance coverage 
held by the electric utilities, and the future transmission and distribution 
equity rate base growth of other electric utilities. Significant changes in any 
of these estimates could materially impact the amortization period. There could 
also be a significant delay between the occurrence of a wildfire and the timing 
of which the Utility recognizes impairment for the reduction in future 
coverage, due to the lack of data available to the Utility following a 
catastrophic event, especially if the wildfire occurs in the service territory 
of another electric utility. As of December 31, 2019, the Utility has not 
reflected the required contributions in its Consolidated Financial Statements 
as it has not yet satisfied all of the Wildfire Fund eligibility criteria 
pursuant to AB 1054.

AB 1054 includes certain modifications to the “just and reasonable” standard to 
be utilized by the CPUC in determining applications for recovery of 
wildfire-related costs. These modifications will apply to wildfires occurring 
following the effective date of AB 1054. AB 1054 provides that costs and 
expenses arising from any such wildfires “are just and reasonable if the 
conduct of the electrical corporation related to the ignition was consistent 
with actions that a reasonable utility would have undertaken in good faith 
under similar circumstances, at the relevant point in time, and based on the 
information available to the electrical corporation at the relevant point of 
time.” Further, in applying such standard, the CPUC is directed to take into 
account factors “both within and beyond the utility’s control that may have 
exacerbated the costs and expenses, including humidity, temperature, and 
winds.” Finally, AB 1054 modifies the circumstances under which an electric 
utility company bears the burden of demonstrating that its conduct was 
reasonable in accordance with the above standard.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by 
California’s three investor-owned electric utility companies on fire risk 
mitigation capital expenditures included in their respective approved wildfire 
mitigation plans will be excluded from their respective equity rate bases. The 
$5.0 billion of capital expenditures will be allocated among the investor-owned 
electric utility companies in accordance with their Wildfire Fund allocation 
metrics (described above). AB 1054 contemplates that such capital expenditures 
may be securitized through a customer charge.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local 
laws and permits relating to the protection of the environment and the safety 
and health of the Utility’s personnel and the public. These laws and 
requirements relate to a broad range of the Utility’s activities, including the 
remediation of hazardous wastes; the reporting and reduction of carbon dioxide 
and other GHG emissions; the discharge of pollutants into the air, water, and 
soil; the reporting of safety and reliability measures for natural gas storage 
facilities; and the transportation, handling, storage, and disposal of spent 
nuclear fuel.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility 
are exposed to risks associated with adverse changes in commodity prices, 
interest rates, and counterparty credit. The Utility actively manages market 
risk through risk management programs designed to support business objectives, 
discourage unauthorized risk-taking, reduce commodity cost volatility, and 
manage cash flows. The Utility uses derivative instruments only for non-trading 
purposes (i.e., risk mitigation) and not for speculative purposes.

Commodity Price Risk

The Utility is exposed to commodity price risk as a result of its electricity 
and natural gas procurement activities, including the procurement of natural 
gas and nuclear fuel necessary for electricity generation and natural gas 
procurement for core customers. The Utility’s risk management activities 
include the use of physical and financial instruments such as forward 
contracts, futures, swaps, options, and other instruments and agreements. As 
long as the Utility can conclude that it is probable that its reasonably 
incurred wholesale electricity procurement costs and natural gas costs are 
recoverable, fluctuations in electricity and natural gas prices will not affect 
earnings. Such fluctuations, however, may impact cash flows. The Utility’s 
natural gas transportation and storage costs for core customers are also fully 
recoverable through a ratemaking mechanism.

The Utility’s current authorized revenue requirement for natural gas 
transportation and storage service to non-core customers is not balancing 
account protected. The Utility recovers these costs in its gas transmission and 
storage rate cases through fixed reservation charges and volumetric charges 
from long-term contracts, resulting in price and volumetric risk. The Utility 
uses value-at-risk to measure its shareholders’ exposure to these risks. The 
Utility’s value-at-risk was approximately $9 million and $11 million at 
December 31, 2019 and 2018, respectively.

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk 
by computing estimated changes in cash flows as a result of assumed changes in 
market interest rates. At December 31, 2019 and 2018, if interest rates changed 
by 1% for all PG&E Corporation and Utility variable rate long-term debt, 
short-term debt, and cash investments, the impact on net income over the next 
12 months would be $45 million and $24 million, respectively, based on net 
variable rate debt and other interest rate-sensitive instruments outstanding.

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry 
to purchase electricity or gas, including the CAISO market, other California 
investor-owned electric utilities, municipal utilities, energy trading 
companies, financial institutions, electricity generation companies, and oil 
and natural gas production companies located in the United States and Canada. 
If a counterparty fails to perform on its contractual obligation to deliver 
electricity or gas, then the Utility may find it necessary to procure 
electricity or gas at current market prices, which may be higher than the 
contract prices.

The Utility manages credit risk associated with its counterparties by assigning 
credit limits based on evaluations of their financial conditions, net worth, 
credit ratings, and other credit criteria as deemed appropriate. Credit limits 
and credit quality are monitored periodically. The Utility executes many energy 
contracts under master commodity enabling agreements that may require security 
(referred to as “Credit Collateral” in the table below). Credit collateral may 
be in the form of cash or letters of credit. The Utility may accept other forms 
of performance assurance in the form of corporate guarantees of acceptable 
credit quality or other eligible securities (as deemed appropriate by the 
Utility). Credit collateral or performance assurance may be required from 
counterparties when current net receivables and replacement cost exposure 
exceed contractually specified limits.


CRITICAL ACCOUNTING POLICIES

The preparation of the Consolidated Financial Statements in accordance with 
GAAP involves the use of estimates and assumptions that affect the recorded 
amounts of assets and liabilities as of the date of the financial statements 
and the reported amounts of revenues and expenses during the reporting period. 
The accounting policies described below are considered to be critical 
accounting policies due, in part, to their complexity and because their 
application is relevant and material to the financial position and results of 
operations of PG&E Corporation and the Utility, and because these policies 
require the use of material judgments and estimates. Actual results may differ 
materially from these estimates and assumptions. These accounting policies and 
their key characteristics are outlined below.

Liabilities Subject to Compromise

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

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material 
accruals for various wildfire-related, enforcement and legal matters, and 
environmental remediation liabilities. PG&E Corporation and the Utility have 
also recorded insurance receivables for third-party claims.

Wildfire-Related Liabilities

PG&E Corporation and the Utility are subject to potential liabilities related 
to wildfires. PG&E Corporation and the Utility record a wildfire-related 
liability when it determines that a loss is probable and it can reasonably 
estimate the loss or a range of losses. The provision is based on the lower end 
of the range, unless an amount within the range is a better estimate than any 
other amount.

Potential liabilities related to wildfires depend on various factors, including 
but not limited to negotiations and settlements or 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, other damages the Utility may be responsible 
for if found negligent, and the amount of any penalties or fines that may be 
imposed by governmental entities. There are a number of unknown facts and legal 
considerations that may impact the amount of any potential liability, including 
the total scope and nature of claims that may be asserted against PG&E 
Corporation or the Utility, the number of current and future claims that will 
be included in a plan of reorganization, and how claims for punitive damages 
and claims by variously situated persons will be treated and whether such 
claims will be allowed.

The process for estimating wildfire-related liabilities requires management to 
exercise significant judgment based on a number of assumptions and subjective 
factors, including but not limited to factors identified above and estimates 
based on currently available information and prior experience with wildfires.

Enforcement and Litigation Matters

PG&E Corporation and the Utility are subject to various laws and regulations 
and, in the normal course of business, are named as parties in a number of 
claims and lawsuits. In addition, penalties may be incurred for failure to 
comply with federal, state, or local laws and regulations. PG&E Corporation and 
the Utility record a provision for a loss contingency when it is both probable 
that a loss has been incurred and the amount of the loss can be reasonably 
estimated. PG&E Corporation and the Utility evaluate the range of reasonably 
estimated losses and record a provision based on the lower end of the range, 
unless an amount within the range is a better estimate than any other amount. 
The assessment of whether a loss is probable or reasonably possible, and 
whether the loss or a range of loss is estimable, often involves a series of 
complex judgments about future events. Loss contingencies are reviewed 
quarterly and estimates are adjusted to reflect the impact of all known 
information, such as negotiations, discovery, settlements and payments, 
rulings, advice of legal counsel, and other information and events pertaining 
to a particular matter. PG&E Corporation’s and the Utility’s provision for loss 
and expense excludes anticipated legal costs, which are expensed as incurred. 
Actual results may differ materially from these estimates and assumptions.

Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California 
environmental laws and regulations that in the future may require the Utility 
to pay for environmental remediation at sites where it has been, or may be, a 
potentially responsible party. Such contingencies may exist for the remediation 
of hazardous substances at various potential sites, including former 
manufactured gas plant sites, power plant sites, gas compressor stations, and 
sites used by the Utility for the storage, recycling, or disposal of 
potentially hazardous materials, even if the Utility did not deposit those 
substances on the site.

The Utility generally commences the environmental remediation assessment 
process upon notification from federal or state agencies, or other parties, of 
a potential site requiring remedial action. (In some instances, the Utility may 
initiate action to determine its remediation liability for sites that it no 
longer owns in cooperation with regulatory agencies. For example, the Utility 
has a program related to certain former manufactured gas plant sites.) Based on 
such notification, the Utility completes an assessment of the potential site 
and evaluates whether it is probable that a remediation liability has been 
incurred. The Utility records an environmental remediation liability when site 
assessments indicate remediation is probable and it can reasonably estimate the 
loss or a range of possible losses. Given the complexities of the legal and 
regulatory environment and the inherent uncertainties involved in the early 
stages of a remediation project, the process for estimating remediation 
liabilities is subjective and requires significant judgment. Key factors 
evaluated in developing cost estimates include the extent and types of 
hazardous substances at a potential site, the range of technologies that can be 
used for remediation, the determination of the Utility’s liability in 
proportion to other responsible parties, and the extent to which such costs are 
recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but 
also considers historical experience for costs incurred at similar sites 
depending on the level of information available. Estimated costs are composed 
of the direct costs of the remediation effort and the costs of compensation for 
employees who are expected to devote a significant amount of time directly to 
the remediation effort. These estimated costs include remedial site 
investigations, remediation actions, operations and maintenance activities, 
post remediation monitoring, and the costs of technologies that are expected to 
be approved to remediate the site. Remediation efforts for a particular site 
generally extend over a period of several years. During this period, the laws 
governing the remediation process may change, as well as site conditions, 
thereby possibly affecting the cost of the remediation effort.

At December 31, 2019 and 2018, the Utility’s accruals for undiscounted gross 
environmental liabilities were $1.3 billion. The Utility’s undiscounted future 
costs could increase to as much as $2.4 billion if the extent of contamination 
or necessary remediation is greater than anticipated or if the other 
potentially responsible parties are not financially able to contribute to these 
costs, and could increase further if the Utility chooses to remediate beyond 
regulatory requirements. Although the Utility has provided for known 
environmental obligations that are probable and reasonably estimable, estimated 
costs may vary significantly from actual costs, and the amount of additional 
future costs may be material to results of operations in the period in which 
they are recognized.

Insurance Receivable

The Utility has liability insurance from various insurers, which provides 
coverage for third-party claims. The Utility records insurance recoveries only 
when a third-party claim is recorded and it is deemed probable that a recovery 
of that claim will occur and the Utility can reasonably estimate the amount or 
its range. The assessment of whether recovery is probable or reasonably 
possible, and whether the recovery or a range of recoveries is estimable, often 
involves a series of complex judgments about future events. Insurance 
recoveries are reviewed quarterly and estimates are adjusted to reflect the 
impact of all known information, including contractual liability insurance 
policy coverage, advice of legal counsel, past experience with similar events, 
discussions with insurers and other information and events pertaining to a 
particular matter. (See “Loss Recoveries” in Note 14 and “Insurance” in Note 15 
of the Notes to the Consolidated Financial Statements in Item 8.)

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets and liabilities 
for amounts that are deemed probable of recovery from, or refund to, customers. 
Despite the ongoing losses related to wildfires (See Note 14 of the Notes to 
the Consolidated Financial Statements), there is no actual or anticipated 
change in the cost of service regulation of the Utility’s operations. 
Therefore, the Utility continues to apply the accounting ASC 980, Regulated 
Operations. These amounts would otherwise be recorded to expense or income 
under GAAP. Refer to “Regulation and Regulated Operations” in Note 3 as well as 
Note 4 of the Notes to the Consolidated Financial Statements in Item 8. At 
December 31, 2019, PG&E Corporation and the Utility reported regulatory assets 
(including current regulatory balancing accounts receivable) of $8.5 billion 
and regulatory liabilities (including current regulatory balancing accounts 
payable) of $11.2 billion.

Determining probability requires significant judgment by management and 
includes, but is not limited to, consideration of testimony presented in 
regulatory hearings, proposed regulatory decisions, final regulatory orders, 
and the strength or status of applications for rehearing or state court 
appeals. For some of the Utility’s regulatory assets, including utility 
retained generation, the Utility has determined that the costs are recoverable 
based on specific approval from the CPUC. The Utility also records a regulatory 
asset when a mechanism is in place to recover current expenditures and 
historical experience indicates that recovery of incurred costs is probable, 
such as the regulatory assets for pension benefits; deferred income tax; price 
risk management; and unamortized loss, net of gain, on reacquired debt. The 
CPUC has not denied the recovery of any material costs previously recognized by 
the Utility as regulatory assets for the periods presented. If the Utility 
determined that it is no longer probable that regulatory assets would be 
recovered or reflected in future rates, or if the Utility ceased to be subject 
to rate regulation, the regulatory assets would be charged against income in 
the period in which that determination was made. If regulatory accounting did 
not apply, the Utility’s future financial results could become more volatile as 
compared to historical financial results due to the differences in the timing 
of expense or revenue recognition.

A portion of the Utility's regulatory asset balances relate to items which 
could not be anticipated by the Utility during CPUC GRC rate requests resulting 
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, which include the CEMA, WEMA, and FHPMA, among others, 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.)

Additionally, SB 901 provides a mechanism for the CPUC to potentially allow 
recovery in future rates, through a securitization mechanism, 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. 
The Utility has made an assessment as of December 31, 2019 and has concluded 
that the net wildfire-related claims incurred for the 2017 Northern California 
wildfires do not meet the criteria for recognition as a regulatory asset. The 
Utility must evaluate the likelihood of recovery in future rates each period. 
If the criteria are met at a later date, the Utility would recognize a 
regulatory asset and a related gain in the consolidated income statement in the 
period in which it is determined that the likelihood of recovery is probable. 
In addition, regulatory accounting standards require recognition of a loss if 
it becomes probable that capital expenditures will be disallowed for ratemaking 
purposes and if a reasonable estimate of the amount of the disallowance can be 
made. Such assessments require significant judgment by management regarding 
probability of recovery, as described above, and the ultimate cost of 
construction of capital assets. The Utility records a loss to the extent 
capital costs are expected to exceed the amount to be recovered. The Utility’s 
capital forecasts involve a series of complex judgments regarding detailed 
project plans, estimates included in third-party contracts, historical cost 
experience for similar projects, permitting requirements, environmental 
compliance standards, and a variety of other factors.

Asset Retirement Obligations

PG&E Corporation and the Utility account for an ARO at fair value in the period 
during which the legal obligation is incurred if a reasonable estimate of fair 
value and its settlement date can be made. At the time of recording an ARO, the 
associated asset retirement costs are capitalized as part of the carrying 
amount of the related long-lived asset. The Utility recognizes a regulatory 
asset or liability for the timing differences between the recognition of 
expenses and costs recovered through the ratemaking process. (See Notes 3 and 4 
of the Notes to the Consolidated Financial Statements in Item 8.)

To estimate its liability, the Utility uses a discounted cash flow model based 
upon significant estimates and assumptions about future decommissioning costs, 
inflation rates, and the estimated date of decommissioning. The estimated 
future cash flows are discounted using a credit-adjusted risk-free rate that 
reflects the risk associated with the decommissioning obligation.

At December 31, 2019, the Utility’s recorded ARO for the estimated cost of 
retiring these long-lived assets was approximately $6 billion. Changes in these 
estimates and assumptions could materially affect the amount of the recorded 
ARO for these assets.

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a non-contributory defined benefit 
pension plan for eligible employees as well as contributory postretirement 
health care and medical plans for eligible retirees and their eligible 
dependents, and non-contributory postretirement life insurance plans for 
eligible employees and retirees. Adjustments to the pension and other benefit 
obligation are based on the differences between actuarial assumptions and 
actual plan results. These amounts are deferred in accumulated other 
comprehensive income (loss) and amortized into income on a gradual basis. The 
differences between pension benefit expense recognized in accordance with GAAP 
and amounts recognized for ratemaking purposes are recorded as regulatory 
assets or liabilities as amounts are probable of recovery from customers. To 
the extent the other benefits are in an overfunded position, the Utility 
records a regulatory liability. (See Note 4 of the Notes to the Consolidated 
Financial Statements in Item 8.)

The pension and other postretirement benefit obligations are calculated using 
actuarial models as of the December 31 measurement date. The significant 
actuarial assumptions used in determining pension and other benefit obligations 
include the discount rate, the average rate of future compensation increases, 
the health care cost trend rate and the expected return on plan assets. PG&E 
Corporation and the Utility review these assumptions on an annual basis and 
adjust them as necessary. While PG&E Corporation and the Utility believe that 
the assumptions used are appropriate, significant differences in actual 
experience, plan changes or amendments, or significant changes in assumptions 
may materially affect the recorded pension and other postretirement benefit 
obligations and future plan expenses. (See Note 12 of the Notes to the 
Consolidated Financial Statements in Item 8.)

In establishing health care cost assumptions, PG&E Corporation and the Utility 
consider recent cost trends and projections from industry experts. This 
evaluation suggests that current rates of inflation are expected to continue in 
the near term. In recognition of continued high inflation in health care costs 
and given the design of PG&E Corporation’s plans, the assumed health care cost 
trend rate for 2019 is 6.3%, gradually decreasing to the ultimate trend rate of 
4.5% in 2027 and beyond.

Expected rates of return on plan assets were developed by estimating future 
stock and bond returns and then applying these returns to the target asset 
allocations of the employee benefit trusts, resulting in a weighted average 
rate of return on plan assets. Fixed-income returns were projected based on 
real maturity and credit spreads added to a long-term inflation rate. Equity 
returns were projected based on estimates of dividend yield and real earnings 
growth added to a long-term rate of inflation. For the Utility’s defined 
benefit pension plan, the assumed return of 5.7% compares to a ten-year actual 
return of 9.3%%.

The rate used to discount pension benefits and other benefits was based on a 
yield curve developed from market data of approximately 936 Aa-grade 
non-callable bonds at December 31, 2019. This yield curve has discount rates 
that vary based on the duration of the obligations. The estimated future cash 
flows for the pension and other postretirement benefit obligations were matched 
to the corresponding rates on the yield curve to derive a weighted average 
discount rate.