Form 8-K PACIFIC GAS & ELECTRIC For: Feb 18 Filed by: PG&E Corp

February 18, 2020 8:40 AM


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

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

•Recorded GAAP losses were $14.50 per share for the year and $6.84 per share for the fourth quarter of 2019, compared to losses of $13.25 and $13.24 per share for the same periods respectively in 2018.

•In anticipation of its emergence from Chapter 11 reorganization, the company is filing a five-year financial forecast that includes capital and rate base growth projections.

•PG&E remains on track to have its Chapter 11 Plan confirmed by June 30, 2020.

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

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

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

Five-year Financial Forecast

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

Chapter 11 Proceeding and Timeline

On January 31, 2020, PG&E submitted regulatory and court filings outlining the key elements of the company’s updated Chapter 11 Plan of Reorganization. Key elements include: refreshing the Boards of Directors of PG&E Corporation and the Utility; regionalizing the company’s operations and its infrastructure to enhance the company’s focus on local communities and customers; paying value in excess of $25 billion to wildfire victims through the settlements reached with individual victims, subrogation claimants, and public entities; and emerging with a financing structure that protects customer rates and positions the company for long-term success.

PG&E believes it remains on track to have its Chapter 11 Plan confirmed by June 30, 2020, the deadline for participating in the state’s new wildfire fund under the terms of Assembly Bill (“AB”) 1054.

“PG&E has made significant progress in our Chapter 11 cases over the past year. We have resolved essentially every consequential issue within the Bankruptcy Court’s jurisdiction, most notably reaching a settlement with wildfire victims. Our focus now is on working with all key stakeholders, including elected officials and state regulators, to position PG&E for emergence as a financially stable company with a renewed and rigorous focus on safe operations and customer service, while meeting California’s energy needs and goals in a changed climate,” said PG&E Corporation Chief Executive Officer and President Bill Johnson.

Progress Report

Over the past several months, the company has made significant headway on operational improvements, wildfire victim compensation, ratemaking, and the Chapter 11 process. As examples, PG&E:

•Met or exceeded core objectives of its 2019 Wildfire Mitigation Plan;

•Announced a $13.5 billion settlement with the Tort Claimants Committee and Representatives of Individual Fire Victims Claimants to resolve claims arising from the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire;

•Announced a settlement with Consenting Noteholders to refinance senior notes and bank debt;

•Announced a settlement in its 2020 General Rate Case that includes cost-recovery mechanisms for wildfire safety spend and insurance costs and will provide clarity into rates over a three year horizon, once approved by the California Public Utilities Commission (“CPUC”);

•Received a Final Decision in its 2020-2022 Cost of Capital Case;

•Announced a settlement with the CPUC in the Wildfire OII, agreeing not to seek recovery for $1.7 billion of wildfire-related expenses; and

•Filed an updated Plan of Reorganization that 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.

Non-GAAP Core Earnings

PG&E Corporation’s non-GAAP core earnings, which exclude non-core items, in 2019 were $2.1 billion, or $3.93 per share, compared with $2.1 billion, or $4.00 per share, in 2018. For the fourth quarter of 2019, non-GAAP core earnings were $360 million, or $0.68 per share, compared with $417 million, or $0.80 per share, during the same period in 2018.

The decrease in quarter-over-quarter non-GAAP core earnings per share was primarily driven by the absence of 2018 short-term incentive compensation, 2019 interest on pre-petition payables and short-term debt, and 2019 vegetation management costs. The decrease was partially offset by the probable recovery of 2019 insurance premiums above amounts included in authorized revenue requirements and by the growth in rate base earnings.

Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as "non-core items" rather than "items impacting comparability." PG&E Corporation uses “non-GAAP core earnings,” which is a non-GAAP financial measure, in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of non-core items. See the accompanying tables for a reconciliation of non-GAAP core earnings to consolidated loss attributable to common shareholders.

2020 Guidance

PG&E Corporation is not providing guidance for 2020 GAAP earnings and non-GAAP core earnings. However, the company is providing factors affecting 2020 non-GAAP core earnings and guidance for non-core earnings items.

These include a range of drivers causing a variance in earnings below authorized, including net below the line and spend above authorized of $150 million to $200 million after tax and unrecovered interest expense of $150 million to $250 million after tax. PG&E Corporation is providing 2020 non-core items guidance of approximately $1.4 billion after-tax for Chapter 11-related costs, wildfire fund-related costs, investigation remedies and delayed cost recoveries, and GT&S capital audit.

Both the drivers and non-core items guidance are based on various assumptions and forecasts related to future expenses and certain other factors.

Supplemental Financial Information

In addition to the financial information accompanying this release, presentation slides have been furnished to the Securities and Exchange Commission (“SEC”) and are available on PG&E Corporation’s website at: http://investor.pgecorp.com/financials/quarterly-earnings-reports/default.aspx.

Public Dissemination of Certain Information

PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings with the CPUC and the Federal Energy Regulatory Commission (“FERC”) at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post, or provide direct links to, presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Chapter 11,” “Wildfire Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information.

About PG&E Corporation

PG&E Corporation (NYSE: PCG) is a holding company headquartered in San Francisco. It is the parent company of Pacific Gas and Electric Company, an energy company that serves 16 million Californians across a 70,000-square-mile service area in Northern and Central California. Each of PG&E Corporation and the Utility is a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules and regulations. For more information, visit http://www.pgecorp.com. In this press release, they are together referred to as “PG&E.”

Forward-Looking Statements

This press release contains forward-looking statements that are not historical facts, including statements about the beliefs, expectations, estimates, future plans and strategies of PG&E Corporation and the Utility, as well as forecasts and estimates regarding timing of PG&E Corporation’s and the Utility’s emergence from Chapter 11, the Utility’s participation in the statewide wildfire fund created by AB 1054, and PG&E Corporation’s 2020 non-core items guidance. These statements are based on current expectations and assumptions, which management believes are reasonable, and on information currently available to management, but are necessarily subject to various risks and uncertainties. In addition to the risk that these assumptions prove to be inaccurate, factors that could cause actual results to differ materially from those contemplated by the forward-looking statements include factors disclosed in PG&E Corporation’s and the Utility’s annual report on Form 10-K for the year ended December 31, 2018, as updated in their subsequent joint quarterly reports on Form 10-Q and their joint annual report on Form 10-K for the year ended December 31, 2019, and other reports filed with the SEC, which are available on PG&E Corporation’s website at www.pgecorp.com and on the SEC website at www.sec.gov. Additional factors include, but are not limited to, those associated with the Chapter 11 cases of PG&E Corporation and the Utility that commenced on January 29, 2019. PG&E Corporation and the Utility undertake no obligation to publicly update or revise any forward-looking statements, whether due to new information, future events or otherwise, except to the extent required by law.

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	Year ended December 31,
	2019		2018		2017
Operating Revenues
Electric	$	12,740	$	12,713	$	13,124
Natural gas	4,389		4,046		4,011
Total operating revenues	17,129		16,759		17,135
Operating Expenses
Cost of electricity	3,095		3,828		4,309
Cost of natural gas	734		671		746
Operating and maintenance	8,725		7,153		6,321
Wildfire-related claims, net of insurance recoveries	11,435		11,771		—
Depreciation, amortization, and decommissioning	3,234		3,036		2,854
Total operating expenses	27,223		26,459		14,230
Operating Income (Loss)	(10,094)		(9,700)		2,905
Interest income	82		76		31
Interest expense	(934)		(929)		(888)
Other income, net	250		424		123
Reorganization items, net	(346)		—		—
Income (Loss) Before Income Taxes	(11,042)		(10,129)		2,171
Income tax provision (benefit)	(3,400)		(3,292)		511
Net Income (Loss)	(7,642)		(6,837)		1,660
Preferred stock dividend requirement of subsidiary	14		14		14
Income (Loss) Available for Common Shareholders	$	(7,656)	$	(6,851)	$	1,646
Weighted Average Common Shares Outstanding, Basic	528		517		512
Weighted Average Common Shares Outstanding, Diluted	528		517		513
Net Earnings (Loss) Per Common Share, Basic	$	(14.50)	$	(13.25)	$	3.21
Net Earnings (Loss) Per Common Share, Diluted	$	(14.50)	$	(13.25)	$	3.21

Reconciliation of PG&E Corporation’s Consolidated Earnings (Loss) Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Core Earnings

Fourth Quarter and Year to Date, 2019 vs. 2018

(in millions, except per share amounts)


	Three Months Ended December 31,														Year Ended December 31,
	Earnings						Earnings per Common Share (Diluted)						Earnings				Earnings per Common Share (Diluted)
(in millions, except per share amounts)	2019		2018		2019		2018		2019		2018		2019		2018
PG&E Corporation’s Loss on a GAAP basis	$	(3,617)	$	(6,873)	$	(6.84)	$	(13.24)	$	(7,656)	$	(6,851)	$	(14.50)	$	(13.25)
Non-core items: ⁽¹⁾
Wildfire-related costs ⁽²⁾	3,847		7,282		7.27		14.03		8,761		8,914		16.59		17.24
Electric asset inspection costs ⁽³⁾	120		—		0.23		—		557		—		1.05		—
Locate and mark penalty ⁽⁴⁾	39		—		0.07		—		39		—		0.07		—
Chapter 11-related costs ⁽⁵⁾	(30)		—		(0.06)		—		180		—		0.34		—
2019 GT&S capital disallowance ⁽⁶⁾	—		—		—		—		193		—		0.37		—
Pipeline-related expenses ⁽⁷⁾	—		8		—		0.02		—		33		—		0.06
Reduction in gas-related capital disallowances ⁽⁸⁾	—		—		—		—		—		(27)		—		(0.05)
PG&E Corporation’s Non-GAAP Core Earnings ⁽⁹⁾	$	360	$	417	$	0.68	$	0.80	$	2,074	$	2,069	$	3.93	$	4.00

(1) “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods, consisting of the items listed in the table above. See Use of Non-GAAP Financial Measures.

(2) The Utility incurred costs of $5.3 billion (before the tax impact of $1.5 billion) and $12.2 billion (before the tax impact of $3.4 billion) during the three and twelve months ended December 31, 2019, respectively, associated with wildfire-related costs related to the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. This includes accrued charges of $5.0 billion (before the tax impact of $1.4 billion) and $11.4 billion (before the tax impact of $3.2 billion) during the three and twelve months ended December 31, 2019, respectively, related to increases in the recorded liability for third-party claims. The Utility incurred costs of $13 million (before the tax impact of $4 million) and $278 million (before the tax impact of $78 million) during the three and twelve months ended December 31, 2019, respectively, for Utility clean-up and repair costs. The Utility also incurred costs of $42 million (before the tax impact of $12 million) and $152 million (before the tax impact of $43 million) during the three and twelve months ended December 31, 2019, respectively, for legal and other costs. In addition, the Utility incurred costs of $398 million (before the tax impact of $108 million) during the three and twelve months ended December 31, 2019 related to the Wildfire Order Instituting Investigation (OII) settlement. The Utility also recorded a charge of $86 million (before the tax impact of $24 million) during the three and twelve months ended December 31, 2019 related to a one-time bill credit for customers impacted by the October 9, 2019 Public Safety Power Shutoff (PSPS) event. These costs were partially offset by $189 million (before the tax impact of $53 million) recorded during the three and twelve months

ended December 31, 2019 for probable cost recoveries of insurance premiums incurred in 2018 above amounts included in authorized revenue requirements.


(in millions, pre-tax)	Three Months Ended December 31, 2019		Year Ended December 31, 2019		Three Months Ended December 31, 2018		Year Ended December 31, 2018
Camp, Northern California, and Butte fire-related costs, net of insurance:
Third-party claims	$	4,988	$	11,435	$	11,500	$	14,000
Utility clean-up and repair costs	13		278		169		209
Legal and other costs	42		152		94		245
Accelerated amortization of prepaid insurance premiums	—		—		185		185
Insurance recoveries	—		—		(1,836)		(2,229)
Subtotal Camp, Northern California, and Butte fire-related costs, net of insurance	5,043		11,865		10,112		12,410
Wildfire OII settlement	398		398		—		—
PSPS customer bill credit	86		86		—		—
2018 Insurance premium cost recovery	(189)		(189)		—		—
2017 Insurance premium cost recovery	—		—		—		(32)
Total Wildfire-related costs	$	5,338	$	12,161	$	10,112	$	12,378

(3) The Utility incurred costs of $167 million (before the tax impact of $47 million) and $773 million (before the tax impact of $216 million) during the three and twelve months ended December 31, 2019, respectively, for incremental operating expenses related to enhanced and accelerated inspections of electric transmission and distribution assets, and resulting repairs that are not probable of recovery.

(4) The Utility recorded costs of $39 million (not tax deductible) during the three and twelve months ended December 31, 2019 associated with an incremental fine payable to the State General Fund resulting from a presiding officer’s decision in the Locate and Mark OII.

(5) PG&E Corporation and the Utility recorded a net benefit of $56 million (before the tax impact of $26 million) and incurred costs of $199 million (before the tax impact of $19 million) during the three and twelve months ended December 31, 2019, respectively, directly associated with their Chapter 11 Cases. This includes legal and other costs of $101 million (before the tax impact of $18 million) and $292 million (before the tax impact of $45 million) during the three and twelve months ended December 31, 2019, respectively ($38 million and $129 million of legal and other costs during the three and nine months ended December 31, 2019, respectively, are not tax deductible.) The Utility also incurred $114 million (before the tax impact of $32 million) during the twelve months ended December 31, 2019 for debtor-in-possession (“DIP”) financing costs. These costs were partially offset by a reduction to interest expense on pre-petition debt of $146 million (before the tax impact of $41 million) during the three and twelve months ended December 31, 2019, and interest income of $11 million (before the tax impact of $3 million) and $60 million (before the tax impact of $17 million) recorded during the three and twelve months ended December 31, 2019, respectively.


(in millions, pre-tax)	Three Months Ended December 31, 2019		Year Ended December 31, 2019
Legal and other costs	$	101	$	292
DIP financing costs	—		114
Reduction of interest expense on pre-petition debt	(146)		(146)
Interest income	(11)		(60)
Chapter 11-related costs	$	(56)	$	199

(6) The Utility recorded costs of $237 million (before the tax impact of $44 million) during the three and twelve months ended December 31, 2019 for pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period. Due to flow-through treatment related to deductible repairs, $80 million of the loss does not generate a net tax benefit.

(7) The Utility incurred costs of $11 million (before the tax impact of $3 million) and $46 million (before the tax impact of $13 million) during the three and twelve months ended December 31, 2018, respectively, for pipeline-related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way

(8) The Utility reduced the estimated disallowance for gas-related capital costs that were expected to exceed authorized amounts by $38 million (before the tax impact of $11 million) during the twelve months ended December 31, 2018. The Utility had previously recorded $85 million (before the tax impact of $35 million) in 2016 for probable capital disallowances in the 2015 GT&S rate case. From 2012 through 2014, the Utility had recorded cumulative charges of $665 million (before the tax impact of $271 million) for disallowed Pipeline Safety Enhancement Plan-related capital expenditures.

(9) “Non-GAAP core earnings” is a non-GAAP financial measure. See Use of Non-GAAP Financial Measures.



Use of Non-GAAP Financial Measures PG&E Corporation and Pacific Gas and Electric Company

PG&E Corporation discloses historical financial results and provides guidance based on “non-GAAP core earnings” and “non-GAAP core EPS” in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of non-core items.

“Non-GAAP core earnings” is a non-GAAP financial measure and is calculated as income available for common shareholders less non-core items. “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods, consisting of the items listed in "Reconciliation of PG&E Corporation’s Consolidated Earnings (Loss) Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations." “Non-GAAP core EPS” also referred to as “non-GAAP core earnings per share” is a non-GAAP financial measure and is calculated as non-GAAP core earnings divided by common shares outstanding (diluted). PG&E Corporation uses non-GAAP core earnings and non-GAAP core EPS to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. PG&E Corporation believes that non-GAAP core earnings and non-GAAP core EPS provide additional insight into the underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance.

Non-GAAP core earnings and non-GAAP core EPS are not substitutes or alternatives for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

2019 FULL YEAR AND FOURTH QUARTER EARNINGS February 18, 2020

® Forward Looking Statements This presentation contains statements regarding management’s expectations and objectives for future periods as well as forecasts and estimates regarding PG&E Corporation’s and Pacific Gas and Electric Company’s (the “Utility”) expected participation in the AB 1054 Wildfire Fund and the Utility’s 2020-2022 Wildfire Mitigation Plan. These statements and other statements that are not purely historical constitute forward-looking statements that are necessarily subject to various risks and uncertainties. Actual results may differ materially from those described in forward-looking statements. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Factors that could cause actual results to differ materially include, but are not limited to: • the risks and uncertainties associated with PG&E Corporation’s and the Utility’s Chapter 11 cases, including, but not limited to, their ability to develop, consummate, and implement a plan of reorganization, the ability to obtain applicable bankruptcy court, creditor or regulatory approvals, the effect of any alternative proposals, views or objections related to the plan of reorganization, potential complexities that may arise in connection with concurrent proceedings involving the bankruptcy court, the CPUC, and the FERC, increased costs related to the Chapter 11 cases, the ability to obtain sufficient financing sources for ongoing and future operations, the ability to satisfy the conditions precedent to financing under the debt and equity commitments to finance the proposed plan of reorganization and the risk that such agreements may be terminated, disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance; • whether PG&E Corporation and the Utility will be able to emerge from Chapter 11 by June 30, 2020 with a plan of reorganization that meets the requirements of AB 1054, and whether PG&E Corporation and the Utility will need to undertake significant changes in ownership, management and governance in connection therewith; • the impact of the 2018 Camp fire and 2017 Northern California wildfires, including whether the Utility will be able to timely recover costs incurred in connection therewith through rates; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liabilities associated with these fires; the timing and amount of insurance recoveries; and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations (which actions could also adversely impact a timely emergence from Chapter 11); • the risks and uncertainties associated with the 2019 Kincade fire; • whether the Utility can obtain wildfire insurance at a reasonable cost in the future, or at all, and whether insurance coverage is adequate for future losses or claims; and whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery; • whether the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses with respect to claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise, which potential financings are not addressed by AB 1054 as it only applies to wildfires occurring after July 12, 2019; • the timing and outcome of future regulatory and legislative developments in connection with the potential financing of the Utility’s wildfire-related liabilities, SB 901, future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility; • the occurrence, timing and extent of damages in connection with future wildfires, the associated financial impact on the Utility and the potential for AB 1054 to mitigate such impact (if at all); • the outcome of the Utility’s CWSP, including the Utility’s ability to comply with the targets and metrics set forth in its 2020-2022 Wildfire Mitigation Plan; the cost of the program; and the timing and outcome of any proceeding to recover such cost through rates; • the impact of the Utility’s implementation of its PSPS program, including the timing and outcome of the PSPS OII and whether any fines or penalties will be imposed on the Utility as a result; and the costs in connection with PSPS events; • the timing and outcomes of the 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 and 2019 CEMA applications, WEMA application, future applications for FHPMA, FRMMA, and WMPMA, future cost of capital proceedings, and other ratemaking and regulatory proceedings; • the timing and outcomes of CPUC OIIs that remain open; • the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within the authorized levels of spending and timely recover its costs through rates, and the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; • the outcome of the probation and the monitorship, and the costs that the Utility may incur as a result, including the costs of complying with any additional conditions of probation, including expenses associated with any material expansion of the Utility’s vegetation management program; • the ability of PG&E Corporation and the Utility to continue as going concerns; and • the other factors disclosed in PG&E Corporation and the Utility’s joint annual report on Form 10-K for the year ended December 31, 2018, as updated in their subsequent joint quarterly reports on Form 10-Q and their joint annual report on Form 10-K for the year ended December 31, 2019, and other reports filed with the SEC, which are available on PG&E Corporation’s website at www.pgecorp.com and on the SEC website at www.sec.gov. Unless otherwise indicated, the statements in this presentation are made as of February 18, 2020. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation was attached to PG&E Corporation and the Utility’s joint current report on Form 8-K that was furnished to the SEC on February 18, 2020 and is also available on PG&E Corporation’s website at www.pgecorp.com. 2

® Resolution of Key Issues Path to timely Chapter 11 exit through the fair settlement of wildfire claims and pending regulatory proceedings, progress with legislative initiatives, and establishment of a multi-year investment and rate roadmap. Q1 Q2 POR OII Testimony and Evidentiary Hearings, and POR OII Proposed Decision Expected Briefing Upcoming Plan of Reorganization Confirmation Hearing Milestones Wildfire OII and Locate & Mark OII Decisions Expected Confirmable Plan to Exit Chapter 11 GRC Decision Expected Progress to Date Third-Party Claims Ratemaking Regulatory & Legislative • Settlements reached with key • 2020 General Rate Case (GRC) • Wildfire OII Settlement (1) constituents Settlement Agreed not to seek recovery for $1.6B of wildfire related expenses Settlements totaling $25.5B with Tort Proposes revenue requirements through 2022 Claimants Committee, Subrogation Claimants, and Public Entities • 2019 Gas Transmission and • Locate & Mark OII Settlement Proposed fines and remedies of $110M • Settlement agreements resolve Storage (GT&S) Final Decision Adopted revenue requirements through 2022 claims estimation and Tubbs Fire • Ex Parte OII Settlement – Final trial • 2020 Cost of Capital Final Decision Resulting in fines and remedies of $107.5M Provides for an expeditious path towards Adopted capital structure through 2022 confirmation and exit from Chapter 11 within • AB 1054 Wildfire Fund the AB1054 deadline Creation of ~$21B fund 3 ( 1 ) Subject to CPUC and Bankruptcy Court approvals.

® AB 1054 Wildfire Fund (1) Wildfire Fund Contribution Treatment $21B Wildfire Fund • Contribution amounts expected to be amortized based on an assumed ~10-year life (2) • Tax treatment pending private letter ruling from the IRS PG&E Pre-Emergence Wildfire Liabilities $4.8B • For fires occurring after July 12, 2019 and prior to exiting Chapter 11 $10.5B Claims in excess of $1B are eligible for recovery and the fund will pay no more than $2.7B • 40% of allowed claims • May seek payment for claims after funding initial contribution $193M/ year $107M/ PG&E Investments and Liability Cap year • $3.2B of wildfire investments excluded from earning a ROE Initial Contribution: PG&E $2.4B liability cap (20% of Equity T&D Rate base for 2019) Initial Contribution: Other IOUs • Annual Contribution: PG&E (3) Annual Contribution: Other IOUs (3) Non-bypassable Charge 1. Participation in the AB 1054 Wildfire Fund is subject to numerous terms and conditions. 2. The useful life of the Wildfire Fund is estimated based on various assumptions, including the number and severity of catastrophic fires within the participating electric utilities’ service territories during the term of the Wildfire Fund, historical fire-loss data, 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. Forecast amortization expense for 2020 is $670 million. 3. Assumes annual IOU contributions will be made for a 10-year period. 4 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.

CONFIDENTIAL – FOR INTERNAL DISCUSSION ® Wildfire Mitigation Overview In 2019, PG&E succeeded in meeting or exceeding its goals for core elements of its Wildfire Mitigation Plan, resulting in a ~25% reduction in ignitions(1) Vegetation Enhanced Situational Public Safety System Hardening Management Inspections Awareness Power Shutoff 114% of circuit mi 102% of circuit mi 100% of visual and 107% of weather Implemented PSPS (171 / 150 mi) (2,498 / 2,450 mi) of aerial inspections on stations (426 / 400 events where we conducted hardened by replacing overhang and radial ~50,000 transmission, units) and 139% of proactive customer outreach overhead circuits, installing clearing and hazard tree ~700,000 distribution, and HD cameras (133 / 96 and deployed back up stronger poles, or mitigation in HFTD areas ~200 substation assets in generation, temporary undergrounding in High HFTD areas units) installed and microgrids, and Community Fire Threat District (HFTD) operationalized to provide Resource Centers areas highly localized and real- 2019 Progress time conditions in HFTD areas The 2020 Wildfire Mitigation Plan is an evolution and continuation of programs that further mitigate wildfire risk and enable implementation of smarter, smaller, and shorter PSPS events 241 miles of system 1,800 circuit miles of Annual inspections 400 weather stations 50% faster restoration hardening, a 40% enhanced vegetation for Tier 3 HFTD facilities and 200 HD cameras and 33% fewer increase in miles as management (EVM) to improve accuracy of impacted customers compared to the 2019 and expanded rights-of-way Three-year cycles for meteorology models and through night patrols with system hardening targets on lower voltage Tier 2 HFTD facilities capabilities of the Wildfire infrared technology, distributed transmission lines to Safety Operations Center generation-enabled complement PSPS reduction microgrids, and additional 2020 Target efforts sectionalization (1) Ignitions associated with PG&E assets in high fire-threat districts (HFTD) as compared to the 3-year historical average. 6 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.

® Q4 2019 Earnings Results Q4 2019 (in millions, except per share amounts) Earnings EPS Earnings EPS PG&E Corporation’s Loss on a GAAP basis $ (3,617) $ (6.84) $ (7,656) $ (14.50) Non-core items: Wildfire-related costs 3,847 7.27 8,761 16.59 Electric asset inspection costs 120 0.23 557 1.05 Locate and mark penalty 39 0.07 39 0.07 Chapter 11-related costs (30) (0.06) 180 0.34 PG&E Corporation’s Non-GAAP Core Earnings $ 360 $ 0.68 $ 2,074 $ 3.93 Non-Core Items (in millions, pre-tax) Q4 2019 Wildfire-related costs $ 5,338 $ 12,161 Electric asset inspection costs 167 773 Locate and mark penalty (56) 199 Chapter 11-related costs — 237 Note: Amounts may not sum due to rounding. Non-GAAP core earnings is not calculated in accordance with GAAP and excludes non-core items. See Appendix 1, Exhibit A for a reconciliation of earnings per share ("EPS") on a GAAP basis to non-GAAP core earnings per share and Exhibit E for the use of non-GAAP financial measures. Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to 6 adjustments as "non-core items" rather than "items impacting comparability."

® Q4 2019 Quarter over Quarter Comparison Non-GAAP Core Earnings per Share $1.00 ($0.18) $0.80 $0.10 ($0.13) $0.60 $0.17 ($0.06) ($0.01) ($0.01) $0.40 $0.80 $0.68 $0.20 $0.00 Q4 2018 Non- Short-term Interest Vegetation Timing of Increase in Liability Growth in rate Q4 2019 Non- GAAP Core incentive accrued on management taxes shares insurance base earnings GAAP Core EPS compensation pre-petition costs outstanding premiums EPS payables and short-term debt Non-GAAP core earnings is not calculated in accordance with GAAP and excludes non-core items. See Appendix 1, Exhibit A for a reconciliation of earnings per share ("EPS") on a GAAP basis to non-GAAP core earnings per share and Exhibit E for the use of non-GAAP financial measures. Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to 7 adjustments as "non-core items" rather than "items impacting comparability."

Appendix

® Table of Contents Appendix 1 - Supplemental Earnings Materials Slides 10-25 Appendix 2 - Overview of Regulatory Cases Slides 26-28 9

® Appendix 1 – Supplemental Earnings Materials Reconciliation of PG&E Corporation's Consolidated Earnings (Loss) Attributable to Exhibit A: Common Shareholders in Accordance with Generally Accepted Accounting Principles Slides 11-14 ("GAAP") to Non-GAAP Core Earnings Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Exhibit B: Share ("EPS") Slide 15 Exhibit C: Operational Performance Metrics Slides 16-17 Exhibit D: Sales and Sources Summary Slide 18 Exhibit E: Use of Non-GAAP Financial Measures Slide 19 Exhibit F: GAAP Net Income (Loss) to Non-GAAP Adjusted EBITDA Reconciliation Slide 20 Exhibit G: 2019 Financial Results Summary Slide 21 Exhibit H: Expected Timelines of Selected Regulatory Cases Slides 22-25 10

® Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings (Loss) Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings Fourth Quarter and Year to Date, 2019 vs. 2018 (in millions, except per share amounts) (2) The Utility incurred costs of $5.3 billion (before the tax impact of $1.5 billion) and $12.2 billion (before the tax impact of $3.4 billion) during the three and twelve months ended December 31, 2019, respectively, associated with wildfire-related costs. This includes accrued charges of $5.0 billion (before the tax impact of $1.4 billion) and $11.4 billion (before the tax impact of $3.2 billion) during the three and twelve months ended December 31, 2019, respectively, related to increases in the recorded liability for third-party claims related to the 2018 Camp Fire, the 2017 Northern California wildfires, and the 2015 Butte fire. The Utility incurred costs of $13 million (before the tax impact of $4 million) and $278 million (before the tax impact of $78 million) during the three and twelve months ended December 31, 2019, respectively, for clean-up and repair costs. The Utility also incurred costs of $42 million (before the tax impact of $12 million) and $152 million (before the tax impact of $43 million) during the three and twelve months ended December 31, 2019, respectively, for legal and other costs. In addition, the Utility incurred costs of $398 million (before the tax impact of $108 million) during the three and twelve months ended December 31, 2019 related to the Wildfire Order Instituting Investigation ("OII") settlement. The Utility also recorded a charge of $86 million (before the tax impact of $24 million) during the three and twelve months ended December 31, 2019 related to a one-time bill credit for customers impacted by the October 9, 2019 Public Safety Power Shutoff (PSPS) event. These costs were partially offset by $189 million (before the tax impact of $53 million) recorded during the three and twelve months ended December 31, 2019 for probable cost recoveries of insurance premiums incurred in 2018 above amounts included in authorized revenue requirements. Three Months Three Months Ended Year Ended Ended Year Ended December 31, December 31, December 31, December 31, (in millions, pre-tax) 2019 2019 2018 2018 Camp, Northern California, and Butte fire-related costs, net of insurance: Third-party claims $ 4,988 $ 11,435 $ 11,500 $ 14,000 Utility clean-up and repair costs 13 278 169 209 Legal and other costs 42 152 94 245 Accelerated amortization of prepaid insurance premiums — — 185 185 Insurance recoveries — — (1,836) (2,229) Subtotal Camp, Northern California, and Butte fire-related costs, net of insurance 5,043 11,865 10,112 12,410 Wildfire OII settlement 398 398 — — PSPS customer bill credit 86 86 — — 2018 Insurance premium cost recovery (189) (189) — — 2017 Insurance premium cost recovery — — — (32) Total Wildfire-related costs $ 5,338 $ 12,161 $ 10,112 $ 12,378 12

® Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings (Loss) Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings Fourth Quarter and Year to Date, 2019 vs. 2018 (in millions, except per share amounts) (3) The Utility incurred costs of $167 million (before the tax impact of $47 million) and $773 million (before the tax impact of $216 million) during the three and twelve months ended December 31, 2019, respectively, for incremental operating expenses related to enhanced and accelerated inspections of electric transmission and distribution assets, and resulting repairs that are not probable of recovery. (4) The Utility recorded costs of $39 million (not tax deductible) during the three and twelve months ended December 31, 2019 associated with an incremental fine payable to the State General Fund resulting from a presiding officer's decision in the Locate and Mark OII. (5) PG&E Corporation and the Utility recorded a net benefit of $56 million (before the tax impact of $26 million) and incurred costs of $199 million (before the tax impact of $19 million) during the three and twelve months ended December 31, 2019, respectively, directly associated with their Chapter 11 Cases. This includes legal and other costs of $101 million (before the tax impact of $18 million) and $292 million (before the tax impact of $45 million) during the three and twelve months ended December 31, 2019, respectively ($38 million and $129 million of legal and other costs during the three and nine months ended December 31, 2019, respectively, are not tax deductible). The Utility also incurred $114 million (before the tax impact of $32 million) during the twelve months ended December 31, 2019 for debtor-in-possession (“DIP”) financing costs. These costs were partially offset by a reduction to interest expense on pre-petition debt of $146 million (before the tax impact of $41 million) during the three and twelve months ended December 31, 2019, and interest income of $11 million (before the tax impact of $3 million) and $60 million (before the tax impact of $17 million) recorded during the three and twelve months ended December 31, 2019, respectively. Three Months Ended Year Ended (in millions, pre-tax) December 31, 2019 December 31, 2019 Legal and other costs $ 101 $ 292 DIP financing costs — 114 Reduction of interest expense on pre-petition debt (146) (146) Interest income (11) (60) Chapter 11-related costs $ (56) $ 199 (6) The Utility recorded costs of $237 million (before the tax impact of $44 million) during the three and twelve months ended December 31, 2019 for pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period. Due to flow-through treatment related to deductible repairs, $80 million of the loss does not generate a net tax benefit. (7) The Utility incurred costs of $11 million (before the tax impact of $3 million) and $46 million (before the tax impact of $13 million) during the three and twelve months ended December 31, 2018, respectively, for pipeline-related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way. 13

® Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share ("EPS") Fourth Quarter and Year to Date, 2019 vs. 2018 (in millions, except per share amounts) Fourth Quarter 2019 vs. 2018 Year Ended 2019 vs. 2018 Earnings per Earnings per Earnings Common Share Earnings Common Share (Diluted) (Diluted) 2018 Non-GAAP Core Earnings (1) $ 417 $ 0.80 $ 2,069 $ 4.00 Short-term incentive compensation (2) (95) (0.18) (95) (0.18) Interest accrued on pre-petition payables and short-term debt (3) (67) (0.13) (67) (0.13) Vegetation management costs (4) (32) (0.06) (110) (0.21) Timing of taxes (5) (7) (0.01) — — Resolution of 2018 regulatory items (6) — — (44) (0.08) Increase in shares outstanding — (0.01) — (0.08) Miscellaneous 1 — (6) (0.01) Liability insurance premiums (7) 92 0.17 137 0.26 Growth in rate base earnings 51 0.10 190 0.36 2019 Non-GAAP Core Earnings (1) $ 360 $ 0.68 $ 2,074 $ 3.93 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2018 and 2019. Amounts may not sum due to rounding. (1) See Exhibit A for reconciliations of (i) earnings on a GAAP basis to non-GAAP core earnings and (ii) EPS on a GAAP basis to non-GAAP core EPS. (2) Represents the impact of Short-Term Incentive Plan ("STIP") compensation expense recorded during the three and twelve months ended December 31, 2019, as compared to the same periods in 2018, where no payment was made. (3) Represents the impact of interest accrued on pre-petition payables and short-term debt during the three and twelve months ended December 31, 2019, pursuant to the Bankruptcy Court's December 30, 2019 decision regarding pre-petition interest and the January 22, 2020 Noteholder Restructuring Support Agreement. (4) Represents the increase in routine vegetation management costs incurred during the three and twelve months ended December 31, 2019, which are not recoverable through authorized revenue requirements. (5) Represents the timing of taxes reportable in quarterly statements in accordance with Accounting Standards Codification 740, Income Taxes, and results from variances in the percentage of quarterly earnings to annual earnings. (6) Represents the impact of various regulatory matters resolved during the twelve months ended December 31, 2018, with no similar impact in 2019. (7) Includes the impact of additional regulatory cost deferrals recorded in the three and twelve months ended December 31, 2019 related to insurance premium costs above amounts included in authorized revenue requirements, which became probable of recovery in the fourth quarter of 2019, and lower insurance premium costs due to lower coverage renewed for excess liability. Additionally, the reduction in insurance premium costs during the twelve months ended December 31, 2019 reflects the accelerated amortization of a portion of the Utility’s liability insurance premiums recorded during the fourth quarter of 2018 as a result of the 2018 Camp fire, with no similar activity in 2019. 15

® Exhibit C: Operational Performance Metrics 2019 Performance Results 2019 Actual 2019 Target Meets Target Safety Nuclear Operations Safety 97.5 93.7 Diablo Canyon Power Plant (DCPP) Reliability and Safety P Electric Operations Safety 1.3 1.0 Public Safety Index P Gas and Electric Operations Safety 1.2 1.0 Asset Records Duration Index P Gas Operations Safety 266.4 183.0 Gas First-Time In-Line Inspection P Employee Safety 1.5 1.0 Serious Injuries and Fatalities Corrective Actions Index P Customer Escalated Customer Complaints 10.1 12.2 P Financial Non-GAAP Core Earnings (1)(3) 2,074 See note (2) See note (2) See following page for definitions of the operational performance metrics. The operational performance goals set under the PG&E Corporation 2019 Short-Term Incentive Plan (“STIP”) are based on the same operational metrics and targets, except as noted in Footnote 1 below. (1) For STIP purposes, non-GAAP core earnings may be further adjusted in a manner consistent with the methodology used to establish the applicable STIP target. (2) The 2019 target for non-GAAP core earnings is not publicly reported. (3) Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as 16 "non-core items" rather than "items impacting comparability".

® Definitions of 2019 Operational Performance Metrics from Exhibit C Safety Public and employee safety are measured in four areas: Nuclear Operations Safety, Electric Operations Safety, Gas Operations Safety, and Employee Safety. The safety of the Utility’s nuclear power operations, DCPP Unit 1 and Unit 2, is based on 11 performance indicators for nuclear power generation, including unit capability, on-line reliability, safety system unavailability, radiation exposure, and safety accident rate, as reported to the Institute of Nuclear Power Operations. The safety of the Utility’s electric and gas operations is represented by: • Public Safety Index - Measure consisting of a weighted index of two electric programs that evaluate the effectiveness of compliance activities in the Fire Index Areas: (1) Enhanced Vegetation Management (50%) and (2) System Hardening (50%). • Gas and Electric Asset Records Duration Index (equally weighed) - Measure consisting of two indices tracking the average number of days to complete the as-built process in the system of record for electric and gas capital and expense jobs from the time construction is completed in the field or released to operations. The Gas Operations Index consists of three weighted sub-metrics: (1) Transmission (60%), (2) Station (10%), and (3) Distribution (30%). The Electric Operations Index consists of three weighted sub-metrics: (1) Transmission Line (25%), (2) Substation (25%), and (3) Distribution (50%). • Gas First-Time In-Line Inspections - Measures the Utility’s successful completion of first-time in-line inspections of newly-constructed natural gas transmission lines. The safety of the Utility’s employees is represented by: • Serious Injuries and Fatalities (SIF) Corrective Action Index - Index measuring (1) percentage of SIF corrective actions completed on time, and (2) quality of corrective actions as measured against an externally derived framework. Customer Customer satisfaction is measured by: • Escalated Customer Complaints Score - Measures the number of customer complaints escalated to the California Public Utilities Commission, per 100,000 adjusted customers. Financial “Non-GAAP core earnings” (shown in millions of dollars) is a non-GAAP financial measure and is calculated as income available for common shareholders less non- core items. “Non-core items” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods, consisting of items listed in Exhibit A. Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as "non-core items" rather than "items 17 impacting comparability".

® Exhibit D: Pacific Gas & Electric Company Sales and Sources Summary Fourth Quarter and Year to Date, 2019 vs. 2018 Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 Sales from Energy Deliveries (in millions kWh) 18,870 19,198 78,070 79,777 Total Electric Customers at December 31 — — 5,457,101 5,428,318 Total Gas Sales (in Bcf) 223 217 823 836 Total Gas Customers at December 31 — — 4,518,209 4,495,279 Sources of Electric Energy Deliveries (in millions kWh): Total Utility Generation 7,132 8,241 33,485 32,297 Total Utility Net Purchases/(Sales) (2,215) 2,923 (3,537) 21,024 Direct Access and Community Choice Aggregator Purchases 10,585 9,065 41,609 30,550 Total Electric Energy Delivered (1) 18,870 19,198 78,070 79,777 Diablo Canyon Performance: Overall Capacity Factor (including refuelings) 56 % 95 % 82 % 93 % 2/10/19/ - 3/18/19 Refueling Outage Period 9/22/19 -12/18/2019 None 9/22/19 -12/19/2019 2/11/18 - 3/22/18 Refueling Outage Duration during the Period (days) 78.3 None 123.7 39 (1) Includes other sources/(uses) of electric energy totaling 3,368 million kWh and (1,031) million kWh for the three months ended December 31, 2019 and 2018, respectively, and 6,513 million kWh and (4,094) million kWh for the year ended December 31, 2019 and 2018, respectively. Please see the 2019 Annual Report on Form 10-K for additional information about operating statistics. 18

® Exhibit E: Use of Non-GAAP Financial Measures PG&E Corporation and Pacific Gas and Electric Company: Use of Non-GAAP Financial Measures PG&E Corporation discloses historical financial results and provides guidance based on “non-GAAP core earnings” and “non-GAAP core EPS” in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of items impacting comparability. Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as "non-core items" rather than "items impacting comparability". “Non-GAAP core earnings” is a non-GAAP financial measure and is calculated as income available for common shareholders less items non- core items. “Non-core Items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods, consisting of the items listed in Exhibit A. “Non-GAAP core EPS”, also referred to as “non-GAAP core earnings per share”, is a non-GAAP financial measure and is calculated as non-GAAP core earnings divided by common shares outstanding (diluted). PG&E Corporation and the Utility use non-GAAP core earnings and non-GAAP core EPS to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. PG&E Corporation and the Utility believe that non-GAAP core earnings and non-GAAP core EPS provide additional insight into the underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance. Non-GAAP core earnings and non-GAAP core EPS are not substitutes or alternatives for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies. 19

® Exhibit F: GAAP Net Income (Loss) to Non-GAAP Adjusted EBITDA Reconciliation PG&E Corporation Fourth Quarter and Year to Date, 2019 vs. 2018 Three Months Ended Year Ended December 31, December 31, (in millions) 2019 2018 2019 2018 PG&E Corporation’s Net Loss on a GAAP basis $ (3,613) $ (6,869) $ (7,642) $ (6,837) Income tax provision (benefit) (1,468) (2,765) (3,400) (3,292) Other income, net (52) (106) (250) (424) Interest expense 605 251 934 929 Interest income (20) (41) (82) (76) Reorganization items, net 90 — 346 — Operating Income $ (4,458) $ (9,530) $ (10,094) $ (9,700) Depreciation, amortization, and decommissioning 801 779 3,234 3,036 Wildfire-related costs (1) 5,338 9,927 12,161 12,225 Electric asset inspection costs 167 — 773 — PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 1,848 $ 1,176 $ 6,074 $ 5,561 Note: Amounts may not sum due to rounding. PG&E Corporation discloses “Adjusted EBITDA,” which is a non-GAAP financial measure, in order to provide a measure that investors may find useful for evaluating PG&E Corporation’s performance during the pendency of the Chapter 11 Cases. PG&E Corporation’s management generally does not use Adjusted EBITDA in managing its business. Adjusted EBITDA is calculated as PG&E Corporation’s net income plus income tax provision (or less income tax benefit); less other income, net; plus interest expense; less interest income; plus reorganization items, net; plus depreciation, amortization, and decommissioning; plus wildfire- related costs and electric asset inspection costs. Adjusted EBITDA is not a substitute or alternative for GAAP measures, such as net income, and may not be comparable to similarly titled measures used by other companies. See above for a reconciliation of GAAP net loss to non-GAAP Adjusted EBITDA. (1) Wildfire-related costs exclude recorded costs of $185 million during the three and twelve months ended December 31, 2018 for accelerated insurance amortizations included in the line above, as well as $32 million of 2017 insurance premium cost recovery recorded during the twelve months ended December 31, 2018. 20

® Exhibit G: 2019 Financial Results Summary Financial Results ($ billions) 2019 Actuals Earnings Loss on a GAAP basis $ (7.7) Non-core items $ 9.8 Non-GAAP core earnings $ 2.1 Capital Expenditures General Rate Case $ 4.6 Gas Transmission and Storage $ 0.8 Transmission Owner $ 1.5 Total $ 7.0 Rate Base General Rate Case $ 27.5 Gas Transmission and Storage $ 4.5 Transmission Owner $ 8.1 Total $ 40.2 Return Equity ratio 52% (1) Authorized return on equity 10.25% Note 1: 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. 21 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.

® Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates 2020 General Rate Case (Phase I) A.18-11-009 Dec 13, 2018 – Application filed Mar 8, 2019 – Scoping Memo Mar 25, 2019 – PG&E's Revised Testimony on Real Estate served Jun 28, 2019 – PAO testimony Jul 26, 2019 – Intervenor testimony Jul-Aug 2019 – Public participation hearings Sept 4, 2019 – PG&E rebuttal testimony due Sep 23-Oct 18, 2019 – Evidentiary hearings Nov 1, 2019 – Joint Comparison Exhibit filed and AB 1054 Equity Return Exclusion Proposal Dec 13, 2019 – Report to ALJs and parties on Settlement progress, including identification of any unresolved issues Dec 20, 2019 – Filed Motion for Approval of Settlement Agreement Jan 6, 2020 – Deadline for filing Opening Briefs on disputed issues outside of the Settlement Agreement Jan 21, 2020 – Deadline for filing Comments on Settlement Agreement Jan 27, 2020 – Deadline for filing Reply Briefs on disputed issued outside of the Settlement Agreement Feb 5, 2020 – Deadline for filing Reply to Comments on Settlement Agreement TBD – Proposed Decision Locate and Mark Order Instituting Investigation I.18-12-007 Dec 13, 2018 – OII issued Jan 14, 2019 – PG&E submitted its 30 Day Report Mar 14, 2019 – PG&E submitted its 90 Day Report Mar 22, 2019 – SED filed motion to expand scope Apr 2, 2019 – PG&E filed response to SED's motion Apr 4, 2019 – Prehearing Conference Jul 24, 2019 – SED opening testimony Jul 30, 2019 – Status conference Aug 16, 2019 – Intervenor opening testimony Sept 13, 2019 – SED and PG&E reach Settlement in principle Sept 18, 2019 – PG&E reply testimony Sept 27, 2019 – CUE joins PG&E/SED in Settlement Agreement Oct 3, 2019 – PG&E, SED, and CUE file Motion to Adopt Settlement Agreement Oct 21-22, 2019 – Evidentiary hearings Nov 4, 2019 – Parties to respond to Motion to Adopt Settlement Agreement Nov 19, 2019 – PG&E, SED, and CUE to reply to responses Jan 17, 2020 – Presiding Officer’s Decision amending the proposed Settlement Agreement Feb 6, 2020 – Settling Parties file a motion accepting the Amended Settlement and requesting other modifications Feb 14, 2020 – ALJ's Ruling granting motion accepting Presiding Officer's Decision and denying motion proposing alternate relief 22

® Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates Safety Culture and Governance Order I.15-08-019 Dec 21, 2018 – President Picker issued ruling on next phase of the Safety Culture OII Instituting Investigation (Phase 3) Jan 16, 2019 – PG&E submitted its initial response Feb 13, 2019 – Opening comments submitted Feb 28, 2019 – Reply Comments due Apr 15 and 26, 2019 – Workshops on Corporate Governance and Corporate Structure May 7, 2019 – Proposed decision issued May 27, 2019 – PG&E opening comments filed Jun 13, 2019 – Final decision issued Jun 18, 2019 – President Picker issued ruling requesting comment on safety culture proposals Jul 19, 2019 – Opening comments filed Aug 2, 2019 – Reply comments due Plan of Reorganization Order Instituting I.19-09-016 Sept 26, 2019 – OII issued Investigation Oct 11, 2019 – PG&E to file and serve a response to the OII Oct 18, 2019 – Other responses to the OII filed and served Oct 23, 2019 – Prehearing Conference Jan 31, 2020 – Testimony of Plan proponents Feb 21, 2020 – Reply testimony Feb 25-Mar 4, 2020 – Evidentiary Hearings Mar 13, 2020 – Post-hearing opening briefs Mar 20, 2020 – Post-hearing reply briefs Apr 2020 – Proposed Decision Transmission Owner Rate Case (TO18) ER16-2320 Jul 29, 2016 – PG&E filed TO18 rate case seeking an annual revenue requirement for 2017 Sep 30, 2016 – FERC accepted TO18 making rates effective Mar 1, 2017 and establishing settlement process Oct 19, 2016 – FERC settlement conference Oct 30, 2016 – CPUC seeks rehearing of FERC's grant of 50 bp ROE adder for CAISO participation Feb 7-8, 2017 – FERC settlement conference Mar 16, 2017 – Parties reached impasse in settlement discussions Jan 2018 – Hearings Oct 1, 2018 – Initial decision issued Oct 31, 2018 – Brief on Exceptions (BOE) filed Nov 20, 2018 – Reply to BOE filed TBD – Final decision Transmission Owner Rate Case (TO19) ER17-2154 Jul 26, 2017 – PG&E filed TO19 rate case seeking an annual revenue requirement for 2018 Sept 28, 2017 – FERC accepted TO19 making rates effective Mar 1, 2018, subject to refund, and establishing settlement process Oct 2017 and May/July 2018 – FERC settlement conferences Sept 21, 2018 – Offer of Settlement filed with FERC with motion for interim rates Oct 9, 2018 – Chief ALJ granted motion for interim rates and authorized the implementation of the interim rates (Jul 1, 2018 for Wholesale and Jan 1, 2019 for retail) pending Commission action on settlement 23 Dec 20, 2018 – FERC approved the all-party settlement

® Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates Transmission Owner Rate Case (TO20) ER19-13 Oct 1, 2018 – Application filed Nov 30, 2018 – FERC accepted TO20 filing and set interim rates effective May 1, 2019 Dec 14, 2018 – FERC settlement conference Mar 14, 2019 – FERC settlement conference Jun 13-14, 2019 – FERC settlement conference Aug 13-14, 2019 – FERC settlement conference Oct 9, 2019 – First comprehensive settlement offer from Intervenors and Trial Staff Oct 28-29, 2019 – FERC settlement conference Nov 7, 2019 – FERC settlement phone conference - status update Dec 12, 2019 – FERC settlement conference Mar 31, 2020 – Partial settlement offer target filing date Mid-Apr 2020 – Prehearing conference on litigation issues Wildfire Mitigation Plan Order Instituting R.18-10-007 Feb 6, 2019 – 2019 Wildfire Mitigation Plan filed Rulemaking Feb 13, 2019 – Wildfire Mitigation Plans presentation workshop Week of Feb 25, 2019 – Technical workshops Feb 26, 2019 – Prehearing Conference Mar 13, 2019 – Intervenor comments Mar 22, 2019 – Utility reply comments Apr 29, 2019 – Proposed decisions issued on Phase 1 Jun 4, 2019 – Final decisions issued on Phase 1 Jun 14, 2019 – Phase 2 initiated Jul 30, 2019 – Utilities file reports detailing data and metrics for evaluating plan effectiveness Aug 21, 2019 – Comments due Aug 28, 2019 – Prehearing Conference Sept 10, 2019 – IOUs submit presentations on status of 2019 WMPs Sept 17-19, 2019 – SED Workshops Oct 30, 2019 – Opening Comments and motions for evidentiary hearings Nov 13, 2019 – Reply Comments and responses to motions for evidentiary hearings Feb 5, 2020 – Proposed decision issued on Phase 2 Feb 7, 2020 – 2020 Wildfire Mitigation Plan filed Feb 18-19, 2020 – Informational Workshops Feb 24-25, 2020 – Technical Workshops Feb 25, 2020 – Opening comments due on Phase 2 proposed decision Mar 2, 2020 – Reply comments due on Phase 2 proposed decision 24

® Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates Wildfire Mitigation Plan Order Instituting Apr 7, 2020 – Deadline for members of the public to submit comments on utility plans Rulemaking (continued) Apr 16, 2020 – Deadline for electric corporations to submit reply comments May 7, 2020 – CPUC's Wildfire Safety Division to issue Draft Resolution recommending approval or denial of utility plans May 27, 2020 – Parties to submit comments on Draft Resolution Jun 11, 2020 – Earliest CPUC voting meeting on the Wildfire Safety Division's Draft Resolution 2017 Northern California Wildfires Order I.19-06-015 Jun 27, 2019 – OII issued Instituting Investigation ("Wildfire OII") Jul 29, 2019 – PG&E to submit its initial response Jul 29, 2019 – Immediate corrective actions response due Aug 13, 2019 – Prehearing Conference Dec 17, 2019 – PG&E, SED, OSA, and CUE filed proposed settlement agreement with the CPUC Jan 16, 2020 – Non-settling parties to file a response Jan 31, 2020 – Reply comments Public Safety Power Shutoff Order Instituting I.19-11-013 Nov 13, 2019 – OII issued Investigation Dec 4, 2019 – Prehearing Conference Dec 13, 2019 – Respondents to file and serve a response to the OII Jan 10, 2020 – Other responses to the OII filed and served Public Safety Power Shutoff Order to Show R.18-12-005 Nov 12, 2019 – OSC issued Cause Feb 5, 2020 – PG&E serves testimony in response to the OSC Feb 28, 2020 – Other parties serve testimony in response to PG&E's testimony Mar 16, 2020 – Concurrent rebuttal testimony served Mar 26, 2020 – Cross-examination estimates Apr 1-3, 2020 – Hearings (if necessary) Most of these regulatory cases are discussed in PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2018. 25

® APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES 2020 CPUC General Rate Case • On December 20, 2019, PG&E filed a 2020 GRC settlement agreement together with the Public Advocates Office of the CPUC, The Utility Reform Network, Coalition of California Utility Employees, the Office of the Safety Advocate of the CPUC, and four other parties that resolves all of the contested issues among those parties in the 2020 GRC. ($ billions) 2020 2021 2022 Requested Revenue Requirement ~$9.52 ~$9.88 ~$10.36 Settlement Agreement Revenue ~$9.09 ~$9.84 ~$10.25 Requirement • The settlement agreement proposes a 2020 weighted average rate base of ~$29.4B for the portions of the Utility’s business reviewed in the GRC, compared with the Utility’s request of ~$29.9B. This rate base amount includes ~$600M of forecast capital spend in 2020 that will not earn an equity return, pursuant to AB 1054. • The settlement provides for new two-way balancing accounts for the three largest components of the GRC application increase, the Community Wildfire Safety Program, vegetation management, and liability insurance premiums. • PG&E cannot predict when a proposed decision will be issued. • Assigned Commissioner: Randolph • Administrative Law Judges: Lirag, Lau Changes from prior quarter noted in blue 26

® APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES FERC Transmission Owner Rate Cases TO18 (2017 Revenues) • On July 29, 2016, PG&E filed TO18 with FERC requesting a ~$1.7B revenue requirement with an ROE of 10.90% (inclusive of 50 basis point adder) • PG&E cannot predict when a final decision will be issued TO19 (2018 Revenues) • On December 20, 2018, FERC approved an uncontested settlement of TO19 that relies on the outcome of TO18 • The TO19 revenue requirement will be determined by applying a settlement factor of 98.85% to the final TO18 authorized revenue requirement • Revenues collected during the TO19 rate period will be subject to refund once the final revenue requirement is determined TO20 (2019 Revenues) • On October 1, 2018, PG&E filed its TO20 rate case requesting a conversion to formula rates, a revenue requirement of ~$1.96B, and an ROE of 12.5% (inclusive of 50 basis point incentive adder) • On November 30, 2018, FERC accepted the filing and established interim rates effective May 1, 2019, and directed the parties to settlement procedures, while holding hearings in abeyance 27

® APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES 2020 Cost of Capital Filing • On December 19, 2019, the CPUC issued a Final Decision retaining the existing ROEs for all three California investor-owned utilities. The Final Decision maintained PG&E’s common equity percentage at 52% and reduced the preferred stock percentage from 1.0% to 0.5%. • For an average residential customer, the electric and gas bill will increase by 0.2%, or ~$0.30, for a total bill of $168.85 per month in 2020. 2019 Authorized 2020 Requested 2020 Adopted Capital Weighted Capital Weighted Capital Weighted Cost Structure Cost Cost Structure Cost Cost Structure Cost Return on 10.25% 52.0% 5.33% 12.0% 52.0% 6.24% 10.25% 52.0% 5.33% Common Equity Preferred Stock 5.60% 1.0% 0.06% 5.52% 0.5% 0.03% 5.52% 0.5% 0.04% Long-Term Debt 4.89% 47.0% 2.30% 5.16% 47.5% 2.45% 5.16% 47.5% 2.45% Weighted Average 7.69% 8.72% 7.81% Cost of Capital • Assigned Commissioner: Batjer • Administrative Law Judge: Stevens 28

PG&E Business Outlook February 2020

Forward-Looking Statements This presentation contains statements regarding and governance in connection therewith; • the impact of the Utility’s implementation of its PSPS management’s expectations and objectives for future periods program, including the timing and outcome of the PSPS OII • the impact of the 2018 Camp fire and 2017 Northern as well as forecasts and estimates regarding PG&E and whether any fines or penalties will be imposed on the California wildfires, including whether the Utility will be able Corporation’s and Pacific Gas and Electric Company’s (the Utility as a result; and the costs in connection with PSPS to timely recover costs incurred in connection therewith “Utility”) Chapter 11 emergence, improvements and events; through rates; the timing and outcome of the remaining investments, and growth outlook; their planned operational, wildfire investigations and the extent to which the Utility will • the timing and outcomes of the 2020 GRC, FERC TO18, TO19, safety and structural improvements, including but not limited have liabilities associated with these fires; the timing and and TO20 rate cases, 2018 and 2019 CEMA applications, WEMA to the expected participation in the AB 1054 Wildfire Fund and amount of insurance recoveries; and potential liabilities in application, future applications for FHPMA, FRMMA, and the Utility’s 2020-2022 Wildfire Mitigation Plan; clean energy connection with fines or penalties that could be imposed on WMPMA, future cost of capital proceedings, and other opportunities; and five-year financial outlook, including but the Utility if the CPUC or any other law enforcement agency ratemaking and regulatory proceedings; not limited to ratebase growth through 2024, capital were to bring an enforcement action, including a criminal expenditure through 2024, 2020 and 2021-2024 earnings • the timing and outcomes of CPUC OIIs that remain open; proceeding, and determined that the Utility failed to comply overview and assumptions, planned cost savings and rates with applicable laws and regulations (which actions could • the Utility’s ability to efficiently manage capital expenditures and bills trajectory and potential capital raise. These also adversely impact a timely emergence from Chapter 11); and its operating and maintenance expenses within the statements and other statements that are not purely authorized levels of spending and timely recover its costs historical constitute forward-looking statements that are • the risks and uncertainties associated with the 2019 Kincade through rates, and the extent to which the Utility incurs necessarily subject to various risks and uncertainties. Actual fire; unrecoverable costs that are higher than the forecasts of results may differ materially from those described in • whether the Utility can obtain wildfire insurance at a such costs; forward-looking statements. PG&E Corporation and the reasonable cost in the future, or at all, and whether • the outcome of the probation and the monitorship, and the Utility are not able to predict all the factors that may affect insurance coverage is adequate for future losses or claims; costs that the Utility may incur as a result, including the costs future results. Factors that could cause actual results to and whether the Utility will be able to obtain full recovery of of complying with any additional conditions of probation, differ materially include, but are not limited to: its significantly increased insurance premiums, and the including expenses associated with any material expansion timing of any such recovery; • the risks and uncertainties associated with PG&E of the Utility’s vegetation management program; Corporation’s and the Utility’s Chapter 11 cases, including, but • whether the ability of PG&E Corporation and the Utility to not limited to, their ability to develop, consummate, and • the ability of PG&E Corporation and the Utility to continue as finance costs, expenses and other possible losses with going concerns; and implement a plan of reorganization, the ability to obtain respect to claims related to the 2018 Camp fire and the 2017 applicable bankruptcy court, creditor or regulatory Northern California wildfires, through securitization • the other factors disclosed in PG&E Corporation and the approvals, the effect of any alternative proposals, views or mechanisms or otherwise, which potential financings are not Utility’s joint annual report on Form 10-K for the year ended objections related to the plan of reorganization, potential addressed by AB 1054 as it only applies to wildfires occurring December 31, 2018, as updated in their subsequent joint complexities that may arise in connection with concurrent after July 12, 2019; quarterly reports on Form 10-Q and their joint annual report proceedings involving the bankruptcy court, the CPUC, and on Form 10-K for the year ended December 31, 2019, and other the FERC, increased costs related to the Chapter 11 cases, the • the timing and outcome of future regulatory and legislative reports filed with the SEC, which are available on PG&E ability to obtain sufficient financing sources for ongoing and developments in connection with the potential financing of Corporation’s website at www.pgecorp.com and on the SEC future operations, the ability to satisfy the conditions the Utility’s wildfire-related liabilities, SB 901, future wildfire website at www.sec.gov. precedent to financing under the debt and equity reforms, inverse condemnation reform, and other wildfire commitments to finance the proposed plan of reorganization mitigation measures or other reforms targeted at the Utility; and the risk that such agreements may be terminated, • the occurrence, timing and extent of damages in connection Unless otherwise indicated, the statements in this disruptions to PG&E Corporation’s and the Utility’s business with future wildfires, the associated financial impact on the presentation are made as of February 18, 2020. PG&E and operations and the potential impact on regulatory Utility and the potential for AB 1054 to mitigate such impact (if Corporation and the Utility undertake no obligation to update compliance; at all); information contained herein. This presentation was attached to PG&E Corporation and the Utility’s joint current • whether PG&E Corporation and the Utility will be able to • the outcome of the Utility’s CWSP, including the Utility’s report on Form 8-K that was furnished to the SEC on emerge from Chapter 11 by June 30, 2020 with a plan of ability to comply with the targets and metrics set forth in its February 18, 2020 and is also available on PG&E Corporation’s reorganization that meets the requirements of AB 1054, and 2020-2022 Wildfire Mitigation Plan; the cost of the program; website at www.pgecorp.com. whether PG&E Corporation and the Utility will need to and the timing and outcome of any proceeding to recover undertake significant changes in ownership, management such cost through rates; 1

PG&E Corporation and Pacific Gas and Electric Company: Use of Non- GAAP Financial Measures and No Securities Offering PG&E Corporation and Pacific Gas and Electric Company: Use of Non-GAAP Financial Measures PG&E Corporation discloses historical financial results and provides guidance based on “non-GAAP core earnings” and “non- GAAP core EPS” in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of items impacting comparability. Beginning with the quarter and full year periods ended December 31, 2020, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from “non-GAAP earnings from operations” to “non-GAAP core earnings” in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as “non-core items” rather than “items impacting comparability.” “Non-GAAP core earnings” is a non-GAAP financial measure and is calculated as income available for common shareholders less non-core items. “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods. “Non-GAAP core EPS”, also referred to as “non-GAAP core earnings per share”, is a non-GAAP financial measure and is calculated as non-GAAP core earnings divided by common shares outstanding (diluted). PG&E Corporation and the Utility use non-GAAP core earnings and non-GAAP core EPS to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. PG&E Corporation and the Utility believe that non- GAAP core earnings and non-GAAP core EPS provide additional insight into the underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance. Non-GAAP core earnings and non-GAAP core EPS are not substitutes or alternatives for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies. No Securities Offering This is not an offering of securities and securities may not be offered or sold absent registration or an applicable exemption from the registration requirements. 2

PG&E System at a Glance PG&E Overview Key Highlights PG&E Corporation is a holding company Roughly two-thirds of PG&E’s revenues are associated whose primary operating subsidiary is Pacific with owning and operating gas, electric, and generation Gas and Electric Company, an investor- infrastructure. The remaining third are pass-through owned energy company that operates in costs associated with commodity procurement. Northern and Central California and delivers some of the nation’s cleanest energy. Californians served ~16M Miles of electric lines ~125,000 Miles of natural gas pipelines ~50,000 MW utility-owned generation ~7,700 PG&E’s Carbon-free and renewable Service energy delivered (2018) >85% Area 2019 WEIGHTED AVERAGE RATEBASE = $40.2B Gas ~25% Electric ~60% Generation ~15% 3

Executive Summary Emergence Positioned for timely Chapter 11 exit ∎ Settlements reached with major wildfire victim groups and regulatory resolution ∎ Clarity in ratemaking clarity through progress in major rate cases Improvement Changes in leadership, governance, structure, operations, and oversight to better manage risks and localize operations ∎ Improved enterprise risk reduction through data-driven enhanced safety measures, enterprise-wide safety system, and long-term system upgrades ∎ Regional restructuring and reducing administrative burdens for our frontline supervisors to enable a greater focus on customers and safety ∎ Appointed new Chief Safety Officer and independent safety advisor, and established independent oversight committee Sustainable Growth Investing to enhance wildfire mitigation, increase customer focus, and advance clean energy goals ∎ Forecasting ~$37B - ~$41B in infrastructure investments over the next 5 years, resulting in ~8% ratebase growth ∎ Advancing our track record of supporting California’s climate leadership and investing in building and transportation electrification See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 4

Agenda 1 Recent Progress Enables Timely Emergence 2 Operational, Safety & Structural Improvements 3 Clean Energy Opportunities 4 Sustainable Financials 5

RECENT PROGRESS ENABLES TIMELY EMERGENCE Resolution of Key Issues Wildfire settlements, regulatory resolutions, the enactment of AB 1054, and establishment of a multi-year investment and rate roadmap resolve uncertainty and provide stability. Third-Party Claims Ratemaking Regulatory & Legislative ✓ Settlements reached with key ✓ 2020 General Rate Case (GRC) ✓ Wildfire OII Settlement (1) constituents Settlement Agreed not to seek recovery for $1.6B of wildfire Settlements totaling $25.5B with: Proposes revenue requirements through 2022: related expenses, including: • Tort Claimants Committee and • Includes two-way balancing account recovery • ~$700M of inspections and repairs expense Representatives of ~70% of Individual Fire for wildfire mitigation, vegetation • ~$500M of Catastrophic Expense Victim Claimants: $13.5B management, and insurance costs Memorandum Account (CEMA) expense • Subrogation Claimants: $11B • ~$400M in CEMA capital • County and Local Public Entities: $1B 2019 Gas Transmission and Storage ✓ ✓ Locate & Mark OII Settlement (1) (GT&S) Final Decision ✓ Settlement agreements avoid need Modified settlement of $110M: • Adopted revenue requirements through 2022 • $66M of system enhancements for claims estimation and Tubbs Fire • $44M fine to the California General Fund trial ✓ 2020 Cost of Capital Final Decision Provide for an expedient confirmation and exit Adopted capital structure through 2022: ✓ Ex Parte OII Settlement – Final from Chapter 11 within the AB1054 deadline • Maintains 10.25% return on equity (ROE) Final Decisions in both Phases 1 and 2: • Maintains 52% equity structure, as requested • Phase 1 remedies of $97.5M ✓ Settlement agreement with • Reduces preferred stock from 1.0% to 0.5%, as • Phase 2 remedies of $10.0M Consenting Noteholders requested • Approves cost of long-term debt of 5.16% • Refinance or reinstate ~$21.5B of senior notes ✓ AB 1054 Wildfire Fund and bank debt Creation of ~$21B fund subject to: • Expected ~$1B cost savings to customers • $4.8B initial contribution and $193M annual contribution • ~$2.4B liability cap (2) • $3.2B of capital excluded from equity return • Full participation upon Chapter11 emergence(3) (1) Subject to CPUC and Bankruptcy Court approvals. (2) The liability cap is calculated as 20% of equity transmission and distribution ratebase and applies over a three-year measurement period. (3) Assuming Plan of Reorganization (POR) is confirmed on or before June 30, 2020. 6

RECENT PROGRESS ENABLES TIMELY EMERGENCE Path to June 2020 Confirmed Plan Upcoming Bankruptcy Court and CPUC milestones will allow for timely confirmation of PG&E’s Plan. Chapter 11 1.31 2.5 2.7 2.28 3.10 5.15 5.27 Amended RSA with Proposed Key parties’ Disclosure Deadline to First Day of POR Filed Consenting Disclosure Disclosure Statement Submit Confirmation Noteholders Statement Statement Hearing Ballots to Hearings Approved Filed Views Filed Vote on Plan CPUC 2.25 – 3.4 3.13 3.20 April May Hearings Opening Reply Expected Expected Final Briefs Briefs Proposed Decision, incl. Decision AB1054 Compliance Approval by CPUC 7

RECENT PROGRESS ENABLES TIMELY EMERGENCE Plan of Reorganization Summary Key Elements of the Plan of Reorganization $59 Billion in Plan Funding Sources ($B) PG&E’s Plan of Reorganization prioritizes wildfire victims, Cash Immediately Prior to Emergence puts customers ahead of investors, and enables continued 1.6 2.2 Insurance Proceeds support of California’s clean energy goals. Key elements of the Plan include: 6.0 Temporary Utility Debt • Satisfaction of pre-petition wildfire claims ($25.5B) and funding for participation in the statewide Wildfire Fund ($5.0B) • Creditors made whole ($27.75B) 9.6 Reinstated Utility Debt • Collective bargaining agreements are assumed • Corporate and Utility governance satisfies AB1054 • Puts PG&E on path to help the state meet its clean energy goals and become the company that customers and 17.8 New Utility Debt communities expect and deserve Plan Has Stakeholder Support 4.8 New Holding Company Debt Official Committee of Tort Claimants 1.4 Deferred TCC Settlement Attorneys representing fire victims who hold over 70% of the more than 70,000 claims that have been filed Subrogation Claimants and Key County and Local Public Entities 15.8 New Equity in PG&E Corp Ad Hoc Noteholder Committee Labor (IBEW) Sources of Funds See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 8

RECENT PROGRESS ENABLES TIMELY EMERGENCE Potential Capital Raise $59B funding for entirety of plan of reorganization has been secured. ~$27B may be raised via future public offerings. Sources of Funds: $59.0B Potential Capital Raise: $26.925B 4.8 New HoldCo Debt 5.8 New Utility Debt Backstop, Bridge, and Potential Capital Raise 26.9 6.0 New Temp. Utility Debt ($26.925B) 1.4 Deferred Common Equity (1) 9.0 New Common Equity (3) 1.6 2.2 Cash at Emergence Potential Insurance Proceeds Capital Raise 12.0 Noteholder RSA Capital Debt Committed Capital: $22.825B Secured ($32.075B) 9.6 Reinstated Utility Equity backstop commitment Up to $12B Debt Utility debt bridge financing $5.825B Equity Issuance to 6.8 (2) Wildfire Claimants HoldCo debt bridge financing $5B Sources of Funds (1) Deferred Wildfire Claims payments to be made on January 15, 2021 ($650M) and January 15, 2022 ($700M). (2) Common Equity to the Fire Victims to be issued to the Trust at a P/E multiple of 14.9x subject to Trust having a minimum ownership of 20.9%. (3) Capital to be raised within the parameters of the Backstop Agreement. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 9

RECENT PROGRESS ENABLES TIMELY EMERGENCE Structural and Governance Commitments PG&E is moving forward with a number of structural, management and governance changes to improve operations and ensure long-term accountability for sustained performance. Operational & ▪ Regional restructuring placing leadership and operations closer to Structural customers ▪ Metrics developed in consultation with the CPUC enable regular oversight of PG&E’s safety and operational performance Management ▪ Enhanced Chief Risk Officer and Chief Safety Officer roles, in addition to Chief Ethics and Compliance Officer, reporting directly to PG&E’s CEO ▪ Majority of executive compensation will be at risk and based on safety and customer-focused metrics Corporate ▪ Refreshed Board with a goal of 50% California residents Governance ▪ Refined skills matrix for Board member selection that includes extensive safety requirements ▪ Refreshed Board has expanded PSPS, risk management, and wildfire mitigation responsibilities 10

Agenda 1 Recent Progress Enables Timely Emergence 2 Operational, Safety & Structural Improvements 3 Clean Energy Opportunities 4 Sustainable Financials 11

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Regionalization Model Over time, we will reorganize our operations into smaller regions designed to get us closer to our customers and be more responsive to specific regional and community needs. Proposed New Regional Operating Model PG&E’s Diverse Customer Base ▪ One key goal of this new structure is to improve A regionalized model will help to more effectively PG&E’s performance in critical customer- serve our diverse customer base: centric areas such as: ▪ More quickly addressing localized safety Agriculture Commercial issues ▪ Reducing outage response times ▪ Faster interconnections for customers ▪ Building a stronger and more personal connection between customers and the new regional leadership ▪ Core operations—including work execution and service delivery—will be brought closer to customers through regionalization, while key enterprise functions will continue to be centralized High Tech and Bio Tech See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 12

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Evolution of Risk Management at PG&E Risk management at PG&E has significantly evolved. In collaboration with the commission and external stakeholders, PG&E has developed models to identify, rank, measure, and mitigate all top safety risks. Data-Driven, Risk-Based Decision Making Regulatory Alignment Our improved risk management processes are Our risk assessment methodology was developed in ensuring that our efforts and investments have consultation with regulators and intervenors and is the greatest impact on reducing our top risks: delivering transparency and accountability for risk management results. Enterprise-wide All quantitative risk Risk Assessment Safety Model Event-based Risk assessments based Mitigation Phase Assessment Proceeding Register on bowtie analysis ▪ Includes a quantitative ▪ Describes agreed-upon (from LOB Siloed Risk Identify Evaluate and Monte Carlo deep dive into top safety risk assessment Register) simulations risks and an analytical methodology for all IOUs (from qualitative and initial basis for risk mitigations ▪ Establishes accountability quantitative risk to be included in the assessments) reporting to track spend ERM* company’s GRC request and risk reduction results Effort and Monitor Respond Data-driven outcome-based mitigation decisions metrics to monitor based on alternative completion and analysis, risk GRC effectiveness reduction value, and (from effort-based metrics risk-spend efficiency General Rate Case to monitor completion) (from subject matter expertise driven) ▪ Provides assessment of safety risks, proposed mitigations, and forecasted cost to implement mitigations * ERM – Enterprise Risk Management 13

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Wildfire Mitigation Overview We developed our expanded wildfire safety programs based on analysis of the accelerated wildfire risks stemming from climate change. We met or exceeded goals for core elements of our 2019 Wildfire Mitigation Plan, resulting in a ~25% reduction in ignitions. (1) PG&E Specific Risk Drivers Wildfire Threat in PG&E’s 2019 Wildfire Mitigation Plan Service Area Progress Vegetation and equipment failure ~95% of the wildfire risk can be Met or exceeded goals on key account for >70% of ignitions in HFTDs addressed in ~20% of the total elements: overhead circuit miles in HFTDs (2) 171 out of 150 circuit 2015-2017 Fire Incident Drivers System 114% miles hardened and for PG&E’s Tiers 2 and 3 Hardening hardened passed quality validation 49% Vegetation Equipment Failure 2,498 out of 2,455 circuit Vegetation 102% miles worked and 3rd Party Management cleared validated Animal 28% Other/Unknown ~ 50k transmission, Enhanced 100% ~700k distribution, and Inspections inspected ~200 substation assets 13% inspected 8% 3% 426 out of 400 weather Situational stations and 133 out of 96 100%+ HD cameras installed Awareness completed Fire Incident Drivers and operationalized (1) Ignitions associated with PG&E assets in high fire-threat districts (HFTD) as compared to the 3-year historical average. (2) Based on PG&E’s relative risk assessment where each circuit was scored on various factors to determine the locations of the greatest wildfire risk areas. Aggregating the relative risk score showed that approximately 95% of the wildfire risk is in 22% of the distribution line miles, or approximately 5,500 circuit miles. 14

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS 2020 Wildfire Mitigation Plan Detail PG&E is committed to sustaining and building upon 2019 progress with our 2020-22 Wildfire Mitigation Plan. The 2020-22 Plan will focus on reducing ignitions through core programs, reducing wildfire spread by leveraging situational awareness tools, and reducing PSPS customer impacts. Core Program Projections Program Goal Context 462 System 171 241 378 ▪ Risk-prioritized approach can substantially Hardening 7,100 address ~95% of the wildfire risk by hardening (miles) line-miles over 10+ years ~20% of HFTD overhead line-miles (1) 2019 2020 2021 2022 Enhanced 2,498 1,800 1,800 1,800 ▪ Leveraging 2019 insights and balancing EVM Vegetation 25,500 resources to continue D-line work and expand Management T-line rights-of-way to reduce PSPS impacts (miles) 2019 2020 2021 2022 line-miles over 10+ years Enhanced Tier 2 ~370,000 ▪ Using risk-informed maintenance cycles Inspections Tier 3 ▪ Annual inspections of facilities in Tier 3 areas structures on (frequency) 2019 2020 2021 2022 ▪ Three-year cycles for facilities in Tier 2 areas avg per year (2) 426 400 ▪ Real-time monitoring of weather conditions and Weather 274 1,300 improved accuracy of meteorology models Stations weather stations (units) ▪ 1 weather station roughly every 20 circuit miles 2019 2020 2021 2022 installed by 2021 (3) across HFTDs ▪ Live feeds and time-lapse data allow PG&E and High Definition 200 200 133 58 external agencies to identify, confirm, and track Cameras 600 wildfires (units) 2019 2020 2021 2022 HD, pan tilt zoom cameras by 2022 (3) ▪ Targeting ~90% visual coverage across HFTDs (1) Based on PG&E’s relative risk assessment where each circuit was scored on various factors to determine the locations of the greatest wildfire risk areas. Aggregating the relative risk score showed that approximately 95% of the wildfire risk is in 22% of the distribution line miles, or approximately 5,500 circuit miles. (2) Starting in 2020, Tier 2 assets will be inspected on a three-year cycle and Tier 3 assets will continue to be inspected annually. (3) In 2018, PG&E installed approximately 200 weather stations and 9 HD cameras. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 15

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS – WILDFIRE MITIGATION System Hardening In 2019, PG&E exceeded our system hardening goal by completing and quality validating 171 miles of system hardening, all of which were in Tiers 2 and 3 High Fire Threat Districts. System Hardening Approach 2019 Progress and Program Evolution 1. Replacing overhead circuits with 171 miles of system hardening completed insulated conductors, stronger poles, 2019 and covered secondary lines and quality validated in HFTDs, or 114% of Progress our 2019 goal 2. Converting overhead circuits to underground lines 241 miles out of a total 7,100 line miles that 3. Retiring or removing overhead assets 2020 Target will be targeted over 10+ years when customers can be served by other means (e.g. Distributed Generation, microgrids) System hardening can address ~95% of Program the wildfire risk through targeting of Impact ~20% of the total overhead line-miles within HFTDs(1) (1) Based on PG&E’s relative risk assessment where each circuit was scored on various factors to determine the locations of the greatest wildfire risk areas. Aggregating the relative risk score showed that approximately 95% of the wildfire risk is in 22% of the distribution line miles, or approximately 5,500 circuit miles. Wildfire Mitigation Plan Element | SYSTEM HARDENING | VEGETATION MANAGEMENT | ENHANCED INSPECTIONS | SITUATIONAL AWARENESS | PSPS IMPROVEMENTS See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 16

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS – WILDFIRE MITIGATION Enhanced Vegetation Management (EVM) PG&E’s enhanced vegetation management program goes beyond compliance. The program is evolving to balance our overall goals, including shifting resources for rights-of-way (ROW) expansion that will have the dual benefit of reducing wildfire risk and reducing PSPS footprints. EVM Program Approach 2019 Progress and Program Evolution 1. Overhang Clearing: Removing overhanging branches and limbs directly above but outside the 2019 2,498 miles in HFTD areas worked radial clearance zone around electric power lines Progress and validated, or 102% of our 2019 goal 2. Hazard Tree Mitigation: Removing or trimming trees that are determined to be hazard trees based on their species, health, and proximity to power lines ▪ 1,800 miles worked 2020 ▪ Comprehensive EVM program that 3. ROW Expansion: Additional vegetation clearance Target and enables broader hazard tree work on lower voltage transmission lines (e.g. Approach 60/70kV or 115kV) to raise wind thresholds on lines evaluation and ROW expansion on for PSPS events lower voltage transmission lines Enhanced Vegetation Management Figure 1: Illustrative example of enhanced vegetation work, which exceeds mandated Figure 2: Advanced vegetation management analytical model using remote sensing clearances and includes overhang trimming, ground-to-conductor fuel reduction, and data to identify which trees pose the greatest risk mitigation of hazard trees in HFTDs, in addition to ROW expansion (not pictured) Wildfire Mitigation Plan Element | SYSTEM HARDENING | VEGETATION MANAGEMENT | ENHANCED INSPECTIONS | SITUATIONAL AWARENESS | PSPS IMPROVEMENTS See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 17

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS – WILDFIRE MITIGATION Enhanced Inspections In 2019, PG&E conducted an unprecedented number of enhanced fire ignition-based inspections and high- priority corrective actions of all transmission, distribution, and substation assets in HFTD areas. Wildfire Safety Inspection Program 2019 Progress and Program Evolution Incorporating enhanced inspections, which include ground and aerial inspections, and 2019 ▪ 100% accelerated safety inspections of Progress climbing inspections of every transmission electric infrastructure in HFTD areas, tower, into routine inspections including: • ~50,000 transmission towers, Standardized Structure Model Template for Camera • ~700,000 distribution poles, and Angles • ~200 substations ▪ Comprehensive ground, climbing or helicopter inspections, and in some cases High Resolution UAV Image using drones 2020 ▪ PG&E has rolled its WSIP program into its Target modified routine inspections and ▪ Enhanced inspections will be implemented Approach for Tier 3 facilities every year and Tier 2 Note: Icons above do not reflect all images/angles that Cracked Insulator visible in facilities on a three-year cycle to facilitate will be captured as part of zoomed image a thorough understanding of asset drone inspections conditions in HFTDs Figure 1: Drone inspections complement and further enhance the ground and climbing visual inspections Wildfire Mitigation Plan Element | SYSTEM HARDENING | VEGETATION MANAGEMENT | ENHANCED INSPECTIONS | SITUATIONAL AWARENESS | PSPS IMPROVEMENTS See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 18

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS – WILDFIRE MITIGATION Improved Situational Awareness PG&E has established fire detection and fire spread modeling capabilities based on an industry-leading satellite system that offers 24/7 advance warning of potential new fire incidents. These data-driven investments will improve our risk-informed decision-making processes in 2020 and beyond. New Data and Analytics Improved Situational Awareness ▪ Real time monitoring of HFTD areas with: ▪ Custom and interactive web application for near-time fire detections where users can track multiple properties, including the general intensity and spread 5 100+ 600+ of fires Satellites HD, pan-tilt- Weather ▪ By 2022, PG&E aims to have ~90% coverage across zoom cameras stations HFTD areas with the installation of ~600 high- definition cameras ▪ Custom and proprietary 1-min GOES-R fire detection data pipeline established with the Space ▪ Increasing weather forecast granularity to a 2km x Center and Engineering Center 2km spatial resolution (vs. 3km x 3km in 2019) Figure 1: Example Camera Output and Web Interface Figure 2: Internal Web Application Showing Real-Time Figure 3: Example Output from the Fire Spread Model Weather Station Data from Multiple Networks Application Wildfire Mitigation Plan Element | SYSTEM HARDENING | VEGETATION MANAGEMENT | ENHANCED INSPECTIONS | SITUATIONAL AWARENESS | PSPS IMPROVEMENTS See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 19

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS – WILDFIRE MITIGATION Public Safety Power Shutoff (PSPS) Improvements Leveraging learnings from 2019, PG&E is committed to reducing customer impact by minimizing the frequency, scope, and duration of future PSPS events. 2020 PSPS Goals and Mitigation Approach Reduced Customer Impacts in 2020 and Beyond Goals by September 1, 2020: By utilizing Distributed Generation Enabled Microgrids (DGEM), PG&E is targeting a ~20% (1) 50% 33% reduction in number of customers impacted. faster restoration times reduction in affected customers CURRENT STATE FUTURE STATE Mitigation Approach: Customers Customers affected: 200K affected: 160K ▪ Distributed Generation Enabled Microgrids (DGEM) at 20 priority substations to power safe-to- Outage Outage energize areas by June 1, 2020 (2) DGEM ▪ Additional Sectionalization with enhanced segmentation strategies on distribution and transmission lines Tier 3 Tier 3 ▪ Increased Restoration Capabilities with up to 65 helicopters and fixed-wing aircraft with cameras Note: Illustrative example (1) As compared to the 2019 PSPS events, i.e. if the exact same weather patterns are seen in 2020 as experienced during the largest PSPS events in 2019 our mitigation efforts should reduce the number of customers impacted by those PSPS events by approximately one-third. (2) CPUC Docket: R.19-09-009 Wildfire Mitigation Plan Element | SYSTEM HARDENING | VEGETATION MANAGEMENT | ENHANCED INSPECTIONS | SITUATIONAL AWARENESS | PSPS IMPROVEMENTS See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 20

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Significant Progress in Gas Safety We have demonstrated progress and continued focus on gas system safety since 2010, achieving industry- leading gains in process safety, asset management, and technology innovation. Industry Recognitions and Certifications Gas System Safety Progress 2010 2019 PAS 55 / Best-in-Class Asset Management Gas Average Odor Response 33.3 20.8 ISO 55001 One of the first utilities to receive certification Time Minutes Process Safety Performance 3rd Party Dig In Reduction 3.5 1.04 API RP 754 Indicators Excavation / 1000 Tickets 2010 2011-19 Pipeline Safety Management API RP 1173 Transmission Automated Valves Systems 0 360 Installed NTSB recommended 235 Opened state-of-the-art facilities: Pipeline Strength Tested 0 >1,495 Miles ▪ Gas Control Center, San Ramon ▪ Gas Safety Academy, Winters Pipeline Made Piggable 130 >1,316 ▪ Gas Safety and Innovation, Dublin Miles Distribution Main Replaced 27 863 Miles Incl. all known cast iron 21

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Continued Focus on Gas Safety Our goal is to be the safest, most reliable gas utility in the United States. Gas Operations will further improve safety though strength testing, asset management, workforce safety and reductions in non-conformance. Asset Integrity & Risk Management Public Safety of highest risk transmission Pipeline & Hazardous Materials vintage pipe segments that Safety Administration (PHMSA) are subjected to a high risk of 100 0 significant incidents within 5 years percent land movement in proximity to population planned to be replaced by 2027 of transmission pipelines reduction in all Notice-of- 63 made piggable by 2029 90 Violations (NOVs) and non- conformances within 5 years percent percent See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 22

OPERATIONAL, SAFETY, AND STRUCTURAL IMPROVEMENTS Continued Progress in Generation Safety Generation safety continues to be a priority; we are receiving industry-leading recognition while enhancing our existing programs, technologies and oversight capabilities. Over Next 5 Years: 20192019DCPPDCPPRating:Rating: Since 2015: Over Next 5 Years: >$600 million “Exemplary” performanceperformance rating rating from >$340 million invested in >$600 million investment in “Exemplary” investment in safety nuclearfrom nuclear industry industry independent independent oversight agency; dams, reservoirs, canals and safety improvements to our dams, waterways improvements to our highest rating a nuclear plant can receive reservoirs, canals and waterways oversight agency; highest rating a dams, reservoirs, canals nuclear plant can receive and waterways Nuclear Generation Safety PowerPower Generation Generation Safety Safety ▪ “Exemplary” rating is the 13th ▪ Of PG&E’s 96 dams regulated by for DCPP over its operating the California Division of Safety of life, second to only one other Dams, 90 rated satisfactory (best site in the country performance), 6 fair, 0 poor, and 0 unsatisfactory. All dams rated fair ▪ DCPP is an industry top- have safety improvement quartile performer in projects underway or complete maintaining worker radiation exposure as low as reasonably ▪ Dam Safety Advisory Board achievable (ALARA) employs a panel of external industry experts who continually provide input to enhance our program See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 23

Agenda 1 Recent Progress Enables Timely Emergence 2 Operational, Safety & Structural Improvements 3 Clean Energy Opportunities 4 Sustainable Financials 24

CLEAN ENERGY OPPORTUNITIES Commitment to California’s Clean Energy Future We are recommitting to California’s clean energy future by implementing and advocating for clean energy policy and investing in electrification. Implementing State Policy Continued Policy Promoting Transparency Goals Advocacy and Reporting ▪ Procuring renewables to achieve ▪ Advocating for a federal price on ▪ Producing a Climate Strategy 60% RPS by 2030 and Carbon carbon Report in 2021 with a 2 Degree Neutrality by 2045 Scenario Analysis ▪ Supporting California’s stringent ▪ Offering customer programs to tailpipe emissions standards ▪ Continuing to engage with our achieve 2X energy efficiency in and backing litigation to maintain external Sustainability existing buildings by 2030 comparable federal standards Advisory Council ▪ Investing in charging ▪ Supporting local ordinances ▪ Continuing other voluntary infrastructure to support 5M zero- promoting all-electric new reporting on GHG emissions, emission vehicles by 2030 construction climate-driven risks, and ESG ▪ Targeting pilots and programs to disclosures increase access to clean energy in disadvantaged communities See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 25

CLEAN ENERGY OPPORTUNITIES Transportation Electrification Opportunity We will extend our track record of enabling California’s adoption of advanced energy technologies by investing $385M in transportation electrification by 2025, positioning for long-term load growth. 0.2% 1.2% 2020 2025 2030 CAGR(1) CAGR(1) In the near term, growth of EVs offsets load In the long-term, transportation electrification loss from Distributed Generation and EE is forecasted to drive load growth Electric Vehicles Today 2030 Electric Vehicle Goals ▪ 270 thousand EVs registered to PG&E customers ▪ 2 million EVs registered to PG&E customers to ▪ 1 of 5 EVs in the U.S. are in PG&E’s service area and meet California’s state goal of 5M EVs 11% of new vehicle sales are EVs ▪ Equivalent to the load of 1 million new homes ▪ 35% average annual growth in PG&E territory since 2015 ▪ $1.70/gallon equivalent charging cost, compared to $3.60/gallon of gasoline(2) (1) System electric sales, based on PG&E’s 2019 Integrated Energy Policy Report (IEPR) filed with the California Energy Commission. (2) California 2019 average price of regular gasoline, from U.S. Energy Information Administration. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 26

CLEAN ENERGY OPPORTUNITIES Building Decarbonization and the Future of Natural Gas In alignment with key stakeholders and in support of California’s zero-carbon objectives, PG&E is committed to managing an equitable and viable transition to zero-carbon alternatives for electric and gas customers. PG&E will: Support Support state & Fund and implement Procure RNG and Continue exploring decarbonization local government incentives and hydrogen to reduce new CNG end uses while keeping policies and programs to support the carbon footprint to reduce emissions energy promote all- electrification of gas from carbon-heavy affordable electric new technologies industries like rail construction and marine In support of targeted decarbonization, PG&E will: • Work with stakeholders to avoid investments in new gas assets that might prove underutilized while maintaining system safety and reliability • Encourage efficient electrification by seeking authorization to spend up to $500M over the next ten years to enable building electrification See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 27

Agenda 1 Recent Progress Enables Timely Emergence 2 Operational, Safety & Structural Improvements 3 Clean Energy Opportunities 4 Sustainable Financials 28

SUSTAINABLE FINANCIALS Attractive Ratebase Profile Sustainable Future Upon Emergence Projected Ratebase Growth ~8% Industry-leading growth from investments in wildfire risk reduction, and safety and reliability 6.5% Disciplined focus on cost optimization to balance ratebase growth and affordable rates Investment to support California’s PG&E PG&E clean energy economy Historical Forecast 2014-2018 2019-2024 Ratebase profile is expected to support strong post-emergence earnings growth. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 29

SUSTAINABLE FINANCIALS Substantial Capital Investments Unprecedented level of system investments, accelerated wildfire risk reduction, and continued execution of gas safety commitments drive substantial capital investments. 2019-2024 CAPEX FORECAST ($B) 2019 Act. 2020 2021 2022 2023 2024 Subject to Ongoing and Future Recovery Requests $7.3-$8.7 $7.6-$8.2 ~$7.5 $7.2-$7.8 $7.4-$8.1 Spend driven by: $7.0 ▪ Wildfire Mitigation Plan Memorandum Account (WMPMA) ▪ Catastrophic Event Memorandum Account (CEMA) 2019 Act. 2020 2021 2022 2023 2024 General Rate Case (GRC) and Gas Transmission & Storage (GT&S) (1) Transmission Owner (TO) AB1054 Fire Risk Mitigation (2) Spend Above Authorized (1) The 2023 GRC will include gas transmission and storage. (2) Capex forecast includes ~$3.2B of fire risk mitigation capital expenditures included in the Utility’s approved wildfire mitigation plans on which PG&E Corporation and the Utility will not earn an equity return. (3) Low end of the range reflects authorized capital expenditures, including the full amount recoverable through a balancing accountwhere applicable. High end of the range includes capital spend above authorized. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 30

SUSTAINABLE FINANCIALS 2019-2022 Wildfire Mitigation Plan Investments PG&E’s AB1054-mandated fire risk mitigation capital expenditures of ~$3.2B is anticipated to be fully expended in 2022. WILDFIRE MITIGATION INVESTMENTS ($B) ~$3.4 ~$2.9 ~$2.8 ~$2.6 1.5 1.4 1.4 1.6 1.3 0.9 0.1 0.9 0.9 0.5 0.6 0.7 2019 2020 2021 2022 ACTUAL FORECAST FORECAST FORECAST CapEx AB1054 CapEx OpEx Note: The 2020 to 2022 wildfire mitigation forecast is as of December 2019 and is consistent with the 5-year forecast. The 2020-22 costs reflect program assumptions that were later updated in the 2020 Wildfire Mitigation Plan filing on February 7, 2020, which forecasts ~$2.6B of annual spend. PG&E is tracking the capex subject to the AB 1054 exclusion in the Wildfire Mitigation Plan Memorandum Account and Wildfire Mitigation Balancing Account. The AB 1054 excluded capex is dependent on the CPUC-approved amounts for PG&E’s WMP capital expenditures. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 31

SUSTAINABLE FINANCIALS Ratebase Growth Forecast WEIGHTED AVERAGE RATEBASE FORECAST BY RATE CASE ($B) Potential Growth Opportunities ~8% CAGR on equity earning ratebase 2019- 2024 (1, 2) ▪ Additional wildfire mitigation $57-$60 $53-$55 ▪ Transportation electrification $50-$51 (Phase II Light Duty) $47-$48 ~$44.5 $40.2 ▪ Additional distributed generation-enabled microgrids ▪ Grid modernization 2019 Act 2020 2021 2022 2023 2024 General Rate Case (GRC) (3) Gas Transmission & Storage (GT&S) (4) Transmission Owner (TO) Spend Above Authorized (1) Ratebasereflects reductions for the following capital items: (a) $240M disallowance by the CPUC in the 2019 GT&S rate case; (b) $3.2B of fire risk mitigation excluded from earning a ROE, pursuant to AB 1054; and (c) $403M the Utility agreed not to seek recovery of as part of the Wildfire OII settlement. (2) Ratebasegrowth including non-equity earnings ratebaseis ~9%. (3) The 2023 GRC will include gas transmission and storage and will move to a four year case cycle. (4) Includes $400M for 2011-2014 spend subject to audit added in 2020. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 32

SUSTAINABLE FINANCIALS 2020 Earnings Overview and Assumptions Substantial progress has been made but there remain a few critical uncertainties that affect earnings. Shifting focus to non-GAAP core earnings and non-core earnings. Non-GAAP Core Earnings (1) in 2020 will be impacted partial period of Chapter 11 case pendency, financing, and regulatory matters. 2020 Non-GAAP Core Earnings Assumptions Key Factors Affecting 2020 Non-GAAP Core Earnings ($ billions) CapEx Ratebase Authorized CPUC ROE across the Enterprise 10.25% 2020 GRC Settlement $4.4 $30.5 Drivers of Variance from Authorized - Net Below the Line and Spend Above 150M-200M 2019 GT&S Decision 0.7 5.4 Authorized 2019 TO Plan under Formula Rates 1.5 8.6 - Unrecovered Interest Expense (2) 150M-250M AB1054 Spend 0.9 - Key Factors Affecting Non-Core Earnings Total ~$7.5 ~$44.5 - Chapter 11 Costs ~1B Financing: $6B of OpCo debt refinanced with securitization - Wildfire Fund-Related Costs 484M in 2021 - Investigation Remedies and Delayed ~110M Cost Recovery (3) + GT&S Capital Audit ~(191M) Key remaining uncertainties (1) Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non- GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as "non-core items" rather than "items impacting comparability". (2) Unrecovered Interest Expense from $4.75B HoldCo and $6B Incremental OpCo Debt. Represents interest expense from second half of 2020. OpCo debt is temporary before take out from securitization. (3) Includes OII penalties and cost recovery associated with Paradise rebuild. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 33

SUSTAINABLE FINANCIALS 2021-2024 Earnings Overview and Assumptions Post emergence, factors impacting non-GAAP core earnings will reduce over time. Key Factors Affecting Non-GAAP Core Earnings (1) (2) 2020 2021 2022 2023 2024 Authorized 10.25% across the Enterprise CPUC ROE Drivers of Net BTL and Spend Above AFUDC back to normal levels in 2021 Variance Authorized Overspend reduced significantly in 2021 from Decreases due to reduction in Unrecovered Interest Expense Authorized HoldCo leverage Non-Core Ch. 11 Costs Earnings Factors Wildfire Fund-Related Costs Remains at $0.5B Investigation Remedies and Delayed Cost Recovery (3) Securitization $1.5 B in 2021 Impacts GT&S Capital Audit (1) Beginning with the quarter and full year periods ended December 31, 2019, PG&E Corporation and the Utility changed the name of their principal non-GAAP earnings metric from "non-GAAP earnings from operations" to "non-GAAP core earnings" in order to align more closely with the terminology used by their industry peers. Likewise, PG&E Corporation and the Utility will now refer to adjustments as "non-core items" rather than "items impacting comparability". (2) In its financial disclosure statement filed on February 18, 2020 with the bankruptcy court, the company also references adjustments to arrive at forecasted non-GAAP Normalized Estimated Net income for 2021. (3) Includes OII penalties and cost recovery associated with Paradise rebuild. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 34

SUSTAINABLE FINANCIALS Cost Savings Areas of Focus Identified an average of $1B per year in operational costs through 2025. These savings will moderate the expected increase on customer bills to support infrastructure investment. Plan of Reorganization results in an additional $1B in net interest savings to customers. Average Annual Savings of $1B through 2025 Process Real Estate & Energy Costs Redesign Other • Work and resource • Monetization of • Surplus property planning excess renewable disposition energy • Contract • Headquarters management redesign $4.9B $0.8B $0.8B through 2025 through 2025 through 2025 2020 • CPUC approved EE 2020 plan with $56.5M forecasted savings achievements • Realized $127.5M in excess renewables sales for 2020 Safety is PG&E’s highest responsibility. PG&E’s commitment to safety should never be compromised for cost reductions or other efficiencies. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 35

SUSTAINABLE FINANCIALS AB1054 Wildfire Fund California established Wildfire Fund to address timely compensation for victims and liquidity needs for Investor-Owned Utilities (IOUs). Total Funding and Participation Fund Mechanics Upon Plan of Reorganization confirmation by Wildfire Fund claims paid by fund followed by CPUC review: June 30, 2020, PG&E expects to be fully eligible for participation. Claims filed against IOU IOU seeks payment from fund for eligible claims exceeding $1B, WILDFIRE FUND FUNDING SOURCES ($B) request is reviewed by fund administrator before releasing funds Additional Funding 3.0 IOU Ongoing over 10 Years Contribution IOU files cost recovery application at the CPUC for claims above insurance (1) DWR CPUC to evaluate if utility conduct was reasonable (2) Surcharge $21B 10.5 Repays SMIF in Net Allowed costs Disallowed costs Loan Contributions from IOUs and Wildfire Fund is not IOU reimburses the Fund Customers reimbursed (subject to the cap) Capitalization by PG&E Initial June 2020 4.8 Contribution ~$10B Shareholder Liability Cap Current 0.3 SDG&E For utility caused fires deemed imprudent, the Fund is re-infused up Capitalization 2.4 SCE to the liability cap, currently estimated at ~$2.4B (calculated based on $4.8B 2.0 SMIF Loan 20% of PG&E Equity T&D ratebase for 2019). Applies to aggregate reimbursements to the fund over a rolling three calendar year period. (1) Amounts above insurance that are not covered by the wildfire fund could be recovered from customers if the utility conduct was deemed reasonable. (2) Serious doubt standard applies as long as utility has received its safety certification for the year in which the fire occurred. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 36

Conclusion Our five-year outlook is positioned for significant growth and sustained performance We are positioned to emerge from Chapter 11 and provide safe, affordable, and clean energy to our customers for the long term 37

Appendix

APPENDIX Refresher: Revenue Sources and Standard Rate Cases Roughly two-thirds of PG&E’s revenues are associated with owning and operating gas, electric, and generation infrastructure. The remaining third are pass-through costs associated with commodity procurement. 2019 Revenue Sources (1) PG&E’s Standard Rate Cases Next Rate Rate Case and Time Period Case Regulatory Rate Case Cycle of Current ~8% Effective Jurisdiction Rate Case Gas Transmission Year ~52% & Storage General Rate Case General Rate Case (GRC) Every 4 years 2020-2022 2023 ~10% CPUC Electric ~30% Transmission Gas Transmission & Storage (GT&S) (2) Every 4 years 2019-2022 2023 Pass-through CPUC Transmission Owner Rates are In effect until (TO) Formula Rate (3) 2019+ updated replaced California Public Utilities Commission (CPUC) FERC annually Federal Energy Regulatory Commission (FERC) Cost of Capital Every 3 years (4) 2020-2022 TBD CPUC (1) Operating revenue reflects accrued, authorized revenue and recorded pass-through expenses, assuming no balancing account under or over earning or catch-up. (2) Gas Transmission & Storage will be subsumed under the General Rate Case in the 2023 filing. (3) TO20 Formula rate became effective May 1, 2019 – December 31, 2019 (subject to refund pending settlement or litigation outcome). Thereafter, the Formula rate will be subject to the annual update filing process to be filed with FERC on December 1 of every year (on an informational basis) for the rates that will be effective on January 1 of the upcoming year. In addition to the rate update feature, the true-up component of the Formula rate ensures that PG&E will recover the actual cost incurred to provide service. (4) The Cost of Capital framework requires the utility to file an application every three years to establish a new Cost of Capital, primarily for the utility’s cost of debt, cost of preferred, cost of equity and capital structure. On April 22, 2019, PG&E filed its 2020 Cost of Capital application and ultimately proposed a return on equity (ROE) of 12% after AB 1054 was enacted into law. The CPUC issued a final decision in December 2019 maintaining PG&E’s ROE at 10.25%, common equity percentage at 52%, and reduced the preferred stock percentage from 1.0% to 0.5%. 39

APPENDIX Resolution of Key Issues Remaining key regulatory issues and Chapter 11 proceedings are on track to be largely resolved by Q2 2020. Status as of 2/18/20 2020 Milestones (1) Q1 Q2 Wildfire, Trade RSAs: TCC, Subros, Public Entities Hearing on Payables, and Pending: FEMA, CalOES, CalFire and Objection to FEMA Other Claims other state entities, Trade Payables Claims 2/26 Chapter 11 RSA with Consenting Noteholders Debt RSA Approved 2/5 Plan to Refinance HoldCo Debt Plan of Hearing on Hearing on Plan 1/31: Amended POR Filed with Court Disclosure Confirmation Reorganization Statement 3/10 5/27 2019 GT&S Final Decision Cost of Capital Final Decision Ratemaking 2020 GRC Settlement Pending CPUC Decision Decision Expected (3) TO19 Final Decision(2) TO18 / TO20 Pending FERC Decisions(2) Pending FERC Decisions Ex Parte OII Settlement Approved Wildfire OII Settlement Pending CPUC Decision Decision Expected (3) Regulatory Locate & Mark OII Settlement Pending CPUC Decision Decision Expected (3) Matters Proposed Plan of Testimony and In Process Decision Evidentiary Hearings Reorganization OII Expected in April Safety Culture OII In Process Pending CPUC Decision (1) The rate case timelines outlined reflect expected filing and decision time frames; actual timing may differ. (2) TO18 pending FERC decision and TO20 is currently in settlement negotiations. The approved TO19 settlement will be 98.5% of TO18 rate case outcome. (3) Subject to CPUC approval. 40

APPENDIX Expected Residential Rate and Bill Trajectory Safety-related spend is driving higher rate and bill growth. PG&E is implementing affordability initiatives and is actively identifying efficiency opportunities to mitigate bill impact. Expected Electric and Gas Rates Expected Average Monthly Residential Customer Bill Growth (3) Electric System Average Bundled Rate (1) $250 30 Total Bill CAGR = 5% 20 CAGR = 4% $200 10 Cents Cents per kWh $150 0 2019 2020 2021 2022 2023 2024 $100 Gas Average Residential Rate (2) 3 $50 2 CAGR = 7% Therm $0 1 $ / / $ 2019 2020 2021 2022 2023 2024 0 Electric Bill Gas Bill 2019 2020 2021 2022 2023 2024 (1) 2019 electric system average bundled rate reflects actual as of 10/1/2019. (2) 2019 gas average residential rate reflects 2019 full year average. (3) Average monthly residential bill is based on household usage assumptions in California Energy Demand 2020-2030 Baseline Forecast – Mid Demand Case. See the Forward-Looking Statements for factors that could cause actual results to differ materially from the guidance provided and underlying assumptions. 41

APPENDIX Accountability in Compensation Incentives Substantially increased weighting of safety-related metrics in Short-Term Incentive Plan from 10% in 2009 to 65% in 2019. The peer average safety weighting was 13% in 2018. PG&E’s performance-based compensation program will align with customer welfare, including safety as its most critical element, but also reliability and affordability. Historical Safety Weighting 2020 Proposed Incentive Plan Measures 65% 65% Short-Term Long-Term 50% 50% 50% 50% Incentive Plan (STIP) Incentive Plan (LTIP) Customer Welfare (75%) Public Safety and Prioritizing public and Reliability (50%) employee safety • System Hardening (25%) Earnings• Electric Operations from Operations (25%) • Microgrid Implementation • Gas Operations (15%) Index (25%) 10% 10% • Generation (10%) 5% 5% 5% 13% Customer Experience (50%) 0% • Workforce Safety (15%) • Reliability (10%) • Customer Satisfaction Score (1) (25%) 2010 2015 2016 2017 2018 2019 Financial Stability (25%) • PSPS Notification Accuracy (2) (25%) LTIP STIP KEIP 2018 Peer Avg • Core Earnings Per Share (1) LTIP does not apply for 2019; 65% safety weighting proposed under the original KEIP (Key Employee Incentive Program) denied by Bankruptcy Court. Note: CEOs are not KEIP participants (2) KEIP = Key Employee Incentive Program 42

Exhibit B Financial Projections Introduction1 The following income and cash flow statements for the annual periods from January 1, 2020 through December 31, 2024 (the “Projection Period”) and the balance sheet as of the end of the year for each of the years 2020 through 2024 for the Debtors (“Consolidated Financial Projections”) are based on forecasts of operating results during the five-year period ending December 31, 2024. Included below is a summary of key assumptions to the Consolidated Financial Projections (in each case, the “Assumptions”). The Consolidated Financial Projections and the Assumptions should be read in conjunction with the Plan and the Disclosure Statement. The Debtors, with the assistance of their advisors, have prepared these Consolidated Financial Projections to assist the Bankruptcy Court in determining whether the Plan meets the feasibility test of section 1129(a)(11) of the Bankruptcy Code. Other than limited information related to rate base and capital expenditures, the Debtors generally do not publish their projections or their anticipated financial position or results of operations. Accordingly, the Debtors do not anticipate that they will, and disclaim any obligation to, furnish updated projections to holders of Claims or Interests, or to include such information in documents required to be filed with the U.S. Securities and Exchange Commission (the “SEC”) or otherwise make public such information. The Consolidated Financial Projections have been prepared by the management of the Debtors, in consultation with the Debtors’ financial and restructuring advisors, Lazard Freres & Co. LLC and AP Services, LLC. The Consolidated Financial Projections were not prepared to comply with the guidelines for prospective financial statements published by the American Institute of Certified Public Accountants or the rules and regulations of the SEC, and by their nature are not financial statements prepared in accordance with accounting principles generally accepted in the United States of America. The Debtors independent accountants have neither examined nor compiled the accompanying Consolidated Financial Projections and accordingly do not express an opinion or any other form of assurance with respect to the Consolidated Financial Projections, assume no responsibility for the Consolidated Financial Projections and disclaim any association with the Consolidated Financial Projections. The Consolidated Financial Projections do not reflect the impact of fresh start reporting in accordance with American Institute of Certified Public Accountants statement of position 90-7, financial reporting by entities in reorganization under the Bankruptcy Code. The Debtors do not expect to be subject to fresh start reporting at or following the Effective Date. The Consolidated Financial Projections contain forward-looking statements that are not historical facts, including statements about the beliefs, expectations, estimates, future plans and strategies of the Debtors, as well as forecasts based on our Plan which reflects settlements reached with various parties, regarding settlement of liabilities in connection with the 2018 Camp fire, 2017 Northern California wildfires and the 2015 Butte fire, the confirmation of the Plan on the Effective Date, the continuing availability of sufficient borrowing capacity or other financing to fund operations, the Utility’s participation in the statewide wildfire fund created by AB 1054, the Debtors’ anticipated sources and uses upon emergence from Chapter 11, the outcome of regulatory 1 Capitalized terms used but not otherwise defined herein have the meanings given to such terms in the Disclosure Statement to which this Appendix is attached. 1

cases and the effect on earnings of such cases, projections of wildfire-related expenditures, anticipated regulatory and legislative policy, anticipated capital expenditures of the Debtors, anticipated costs of operations of the Debtors, dividend payments (both Utility preferred stock and PG&E Corporation common stock) and the various assumptions described in detail below. These statements are based on current expectations and assumptions, which management believes are reasonable, and on information currently available to management, but are necessarily subject to various risks and uncertainties. In addition to the risk that these assumptions prove to be inaccurate, factors that could cause actual results to differ materially from those contemplated by the forward-looking statements include factors disclosed in PG&E Corporation’s and the Utility’s annual report on Form 10-K for the year ended December 31, 2019 and other reports filed with the SEC, which are available on PG&E Corporation’s website at www.pgecorp.com and on the SEC website at www.sec.gov. Additional factors include, but are not limited to, those associated with the Chapter 11 cases of PG&E Corporation and the Utility that commenced on January 29, 2019. PG&E Corporation and the Utility undertake no obligation to publicly update or revise any forward-looking statements, whether due to new information, future events or otherwise, except to the extent required by law. The Consolidated Financial Projections, while presented with numerical specificity, are necessarily based on a variety of estimates and assumptions which, though considered reasonable by the Debtors, may not be realized and are inherently subject to significant business, economic, competitive, industry, regulatory, market and financial uncertainties and contingencies, many of which are beyond the control of the Debtors. The Debtors caution that no representations can be made or are made as to the accuracy of the Consolidated Financial Projections or to the Debtors’ ability to achieve the projected results. Some assumptions inevitably will be incorrect. Moreover, events and circumstances occurring subsequent to the date on which these Consolidated Financial Projections were prepared may be different from those assumed, or, alternatively, may have been unanticipated, and thus the occurrence of these events may affect financial results in a materially adverse or materially beneficial manner. The Debtors do not intend and do not undertake any obligation to update or otherwise revise the Consolidated Financial Projections to reflect events or circumstances existing or arising after the date of these Consolidated Financial Projections. Therefore, the Consolidated Financial Projections may not be relied upon as a guarantee or other assurance of the actual results that will occur. In deciding whether to vote to accept or reject the Plan, holders of Claims and Interests must make their own determinations as to the reasonableness of such assumptions and the reliability of the Consolidated Financial Projections. These Consolidated Financial Projections were developed for purposes of the formulation and negotiation of the Plan and to enable the holders of Claims and Interests entitled to vote under the Plan to make an informed judgment about the Plan and should not be used or relied upon for any other purpose, including the purchase or sale of securities of, or Claims or Interests in, the Debtors or any of their affiliates. Use of Non-GAAP Financial Measures The Consolidated Financial Projections contains financial information based on “non-GAAP core earnings” in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of items impacting comparability. “Non-GAAP core earnings” is a non-GAAP financial measure and is calculated as income available for common shareholders less non-core items. “Non-core items” includes items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods. The Debtors use non-GAAP core earnings to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. The Debtors believe that non-GAAP core earnings provides additional insight into the 2

underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance. Non-GAAP core earnings is not a substitute or alternative for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies. Select Assumptions for PG&E’s Financial Forecast 2020-2024 The Consolidated Financial Projections contained herein are based on, but not limited to, factors such as general business, economic, competitive, regulatory, market, financial and environmental conditions, as well as the assumptions detailed below. Many of these factors and assumptions are beyond the control of the Debtors and do not take into account the uncertainty and disruptions of business that may accompany an in- court restructuring. Accordingly, the assumptions should be reviewed in conjunction with a review of the risk factors set forth in the Disclosure Statement and in the Debtors’ public filing. General Assumptions • In light of the forms of distribution contemplated by the Plan (which include cash as well as new PG&E Corporation common stock and the new debt securities of the Utility), the Consolidated Financial Projections were developed on a consolidated basis rather than on a separate legal entity basis. The Consolidated Financial Projections were developed by management with the assistance of the Debtors’ advisors and are presented solely for purposes of the formulation and negotiation of the Plan in order to present the anticipated impact of the Plan. No representation or warranty, express or implied, is provided in relation to the fairness, accuracy, correctness, completeness, or reliability of the information, opinions, or conclusions expressed herein. • The Consolidated Financial Projections assume that the Plan will be consummated in accordance with its terms and that all transactions contemplated by the Plan will be consummated on June 30, 2020. • The Consolidated Financial Projections also assume that: (1) there will be no material change in legislation or regulations, or the administration thereof, that would have an unexpected effect on the operations of the Debtors; and (2) there will be no change in generally accepted accounting principles in the United States that would have a material effect on the reported financial results of the Debtors. Assumptions Underlying Revenue Projections and Cost Recovery Base Revenue The Consolidated Financial Projections assume: • Base revenues for electric distribution, natural gas distribution and electric generation operations are consistent with the Utility’s proposed settlement agreement (the “2020 GRC Settlement”) filed on December 20, 2019 with the California Public Utility Commission (“CPUC”) in its 2020 General Rate Case (“GRC”) for 2020-2022. Spending for wildfire-related programs included in the 2020 GRC Settlement associated with system hardening, vegetation management, public safety power shutoffs and excess liability insurance, is anticipated to be well above amounts specified, and this incremental spending is recoverable through balancing accounts up to a two-year lag. Base revenue for the years 2023 and 2024 assumes an increase in authorized annual revenue requirement sufficient to cover the forecasted GRC costs and authorized rate of return. • Formula rates for the recovery of costs for electric transmission facilities are determined by the Transmission Owner (“TO”) rate cases with the Federal Energy Regulatory Commission (“FERC”). Under the formula rate mechanism, transmission revenues are updated to the actual cost of service 3

annually. All transmission wildfire-related costs are assumed to be fully recoverable consistent with the formula rate mechanism. • Base revenues for the Utility’s natural gas transmission and storage services are consistent with the final decision issued in the Utility’s 2019 gas transmission and storage (“GT&S”) case, as approved by the CPUC on September 12, 2019 for 2019-2022. Base revenue for the years 2023 and 2024 assumes an increase in the authorized GT&S annual revenue requirement sufficient to cover forecasted expenses, except for amounts not recoverable. Aggregate GT&S capital expenditures of $576 million over the years 2011 through 2014 that are currently subject to audit by the CPUC are assumed to be approved by the CPUC and restored to the Utility’s rate base in 2020. • Base operating and maintenance expenses excluding wildfire-related costs are forecast to be generally in line with the Utility’s settlements and final decisions in its rate cases, including those described above. Incremental Wildfire-Related and Other Costs The Consolidated Financial Projections assume full recovery of wildfire-related costs currently deferred as regulatory assets on the balance sheet and additional future spending beyond the programs included in the 2020 GRC Settlement: • Full recovery over the Projection Period of approximately $2.5 billion of costs related to restoration, prevention, and insurance that are on the Utility’s balance sheet as deferred costs as of December 31, 2019. Interim rate relief and accelerated will be granted by the CPUC allowing approximately $1.4 billion of these costs to be recovered in 2020 and 2021 on an accelerated basis. • Consistent with the Utility’s settlement agreement in the Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire (the “Wildfires OII”) submitted to the CPUC on December 17, 2019, the Utility will receive no recovery of costs totaling approximately $1.675 billion contemplated by the Wildfires OII settlement relating to certain wildfire-related costs and shareholder- funded system enhancement initiatives. • For wildfire-related programs, including wildfire-related inspections and maintenance costs, that are in addition to programs requested in the 2020 GRC Settlement, recovery of costs will be allowed by the CPUC through memorandum accounts and collected on a three-year lag. • Recovery of incremental capital expenditures in 2020 and 2021 related to implementing microgrid- enabling distributed generation, consistent with its proposal for cost recovery authorization submitted to the CPUC in connection with the CPUC’s Order Instituting Rulemaking regarding microgrids. • Pursuant to the requirements of Assembly Bill (“AB”) 1054, approximately $3.2 billion of fire risk mitigation capital expenditures will be excluded from the Utility’s equity rate base and will therefore not earn a return on equity. Such expenditures are assumed to be substantially incurred over the period from August 2019 through December 31, 2022 and are assumed to be funded with debt until securitization bond proceeds are received. Assumptions Underlying Regulatory and Policy Projections The Consolidated Financial Projections assume: • The Utility’s authorized Return on Equity will be 10.25% (as authorized through 2023 by the CPUC in its final decision issued December 19, 2019) throughout the Projection Period. The Consolidated Financial Projections also reflect a capital structure that is consistent with the terms of the Restructuring Support Agreement (the “Noteholder RSA”) dated January 22, 2020, resulting in a 4

weighted-average cost of debt of approximately 4.3%2 upon PG&E Corporation’s and the Utility’s emergence from Chapter 11. • Consistent with the terms of AB 1054, an initial contribution by the Utility to the Go-Forward Wildfire Fund established thereunder of $4.8 billion upon emergence, to be amortized over ten years and ongoing contributions by the Utility to the Go-Forward Wildfire Fund of $193 million per year over the Projection Period. • The payment of various penalties by the Utility, including general fund payments, shareholder-paid initiatives, and agreements not to seek rate recovery for specified expenses pursuant to the following Orders Instituting Investigation (“OIIs”): • Locate & Mark OII: In February 2020, the presiding officer in this OII issued a decision modifying the settlement agreement between the Utility and the CPUC submitted on October 3, 2019. Consistent with the terms of the settlement agreement, as modified, the Consolidated Financial Projections assume payments and unrecovered expenses by the Utility in the amount of $110 million during 2020-2022. • Phase II Ex-Parte OII: On December 5th, 2019, the CPUC approved a settlement agreement between certain public entities and the Utility pursuant to which the Utility agreed to pay an incremental penalty of $10 million. The Consolidated Financial Projections assume that this penalty is paid in 2020. • Wildfires OII: As described above, on December 17, 2019, the Utility submitted a settlement agreement to the CPUC in connection with the Wildfires OII in which it agreed not to seek cost recovery for $1.675 billion of wildfire-related expenditures. The Consolidated Financial Projections assume that these costs will not be recovered. Financing Considerations • The financing assumptions underlying the Consolidated Financial Projections are consistent with the Utility’s testimony filed with the CPUC on January 31, 2020 in connection with the CPUC’s Plan of Reorganization OII. The Consolidated Financial Projections assume total sources of funding and corresponding uses of approximately $59 billion ($57.65 billion upon emergence), as summarized in the following tables: Expected Sources (in millions) Equity issuance for cash $9,000 Equity issued into Fire Victim Trust (as defined below) 6,750 New PG&E Corporation Debt 4,750 Reinstated Utility Debt 9,575 New Utility Notes 23,775 Insurance Proceeds 2,200 Cash immediately prior to Emergence 1,600 Deferred Wildfire Claims Settlement 1,350 Total Sources $59,000 2 Inclusive of amortization of fees. 5

Expected Uses (in millions) Payment to holders of wildfire-related claims $24,150 2017/2018 Wildfire Claims Settlement (Deferred Payment) 1,350 Contributions to Go-Forward Wildfire Fund pursuant to AB 1054 5,000 Repayment of Debtor-In-Possession Financing 2,000 Pre-petition Debt to be repaid or reinstated 22,180 Trade Claims and Other Costs 2,300 Accrued Interest 1,270 Cash immediately following Emergence 750 Total Uses $59,000 • The Consolidated Financial Projections assume, in connection with PG&E Corporation and the Utility’s exit financing, that the CPUC will authorize the exclusion of $6 billion of temporary New Utility Notes from the Utility’s capital structure. The Consolidated Financial Projections further assume that the CPUC will authorize the securitization of $7 billion of wildfire-related claims costs by March 31, 2021 that will be rate-neutral on a net present value basis to customers, the proceeds of which will be used to retire the $6 billion of temporary New Utility Notes and to make payments as part of the $1.35 billion deferred settlement to the trust to be established under the Plan for the benefit of holders of wildfire-related claims (“Fire Victim Trust”). The authorization to securitize $7 billion of wildfire claims on an NPV neutral basis results in a $2.1 billion charge at inception as a result of an undiscounted regulatory liability associated with revenue credits funded by the NOL monetization. Securitization revenues, revenue credits, and interest expense on the $7 billion of securitized debt are fully offset by net amortization of the securitization regulatory asset and undiscounted regulatory liability. • The securitization proposal reflected in the forecast includes revenue credits of $1.15 billion in 2021 and $397 million in 2022 that are not funded by NOL monetization. The timing and amounts of customer credits are still to be determined and are subject to material change and regulatory approval. • The Consolidated Financial Projections assume that the Debtors will face no incremental wildfire liabilities related to pre-petition wildfires beyond the $25.5 billion of wildfire-related claims that the Debtors have committed as of the date hereof to pay under the Plan pursuant to various settlement agreements with the holders of wildfire-related claims. The Consolidated Financial Projections further assume the Debtors will not face any liabilities related to postpetition wildfires that are not covered by insurance. • Common dividends are assumed to be restored once Utility equity ratio achieves 52% on a regulatory basis and are moderated to allow Holding Company debt reduction throughout the forecast period. This assumption does not reflect a commitment on the Board or management's part to a specific future dividend policy. • The Consolidated Financial Projections assume that additional equity is raised in 2021. This financing need may either be met through equity issuance or maintaining Holding Company debt levels. 6

PG&E Corporation Consolidated CONDENSED CONSOLIDATED PROJECTED INCOME STATEMENTS ($ millions) 2020 2021 2022 2023 2024 INCOME STATEMENT Net Operating Revenues 15,512 15,408 16,866 18,256 19,028 Memo: Total Cost of Energy 3,400 3,716 3,684 3,450 3,490 Operating Expenses Operating and maintenance (8,807) (8,869) (8,700) (8,921) (8,972) Depreciation, amort. & decommissioning (3,444) (3,693) (3,916) (4,229) (4,510) Net securitization regulatory deferral (1,083) 265 (137) (142) Total Operating Expenses (12,251) (13,645) (12,351) (13,287) (13,624) Operating Income 3,261 1,763 4,515 4,970 5,405 Total Interest Expense (1,296) (1,757) (1,839) (1,914) (1,965) State Wildfire Insurance Fund Contribution and Prepayment Amortization (672) (672) (672) (672) (672) Other Income/(Expense), net (1,057) (166) (166) (180) (193) Income Before Income Taxes 236 (832) 1,838 2,203 2,575 Income tax provision 232 792 23 (73) (188) Preferred dividend requirement (14) (14) (14) (14) (14) TOTAL EARNINGS AVAIL FOR COMMON STOCK 454 (54) 1,847 2,116 2,373 Non-GAAP Core Earnings Adjustments Bankruptcy and Legal Costs 1,065 28 Investigation Remedies and Delayed Cost Recovery 110 42 48 GT&S Capital Audit (191) Amortization of Wildfire Insurance Fund Contribution 484 484 484 484 484 Net Securitization Inception Charge 1,539 NON-GAAP CORE EARNINGS 1,922 2,039 2,379 2,600 2,857 Forecasted 2021 Normalized Estimated Net Income (“NENI”), as defined in the Backstop Commitment Letter filed with the SEC on December 26, 2019, excludes the following items that are otherwise included in the presentation of forecasted 2021 Core Earnings: approximately $55 million related to unrecoverable Gas Transmission and Storage costs, approximately $45 million related to delayed capital recovery and approximately $20 million of earnings below authorized amounts. In addition to the adjustments referenced above, NENI includes the post- tax annual contribution to the Go-Forward Wildfire Fund, which is excluded from Core Earnings. 7

PG&E Corporation Consolidated CONDENSED CONSOLIDATED PROJECTED BALANCE SHEETS ($ millions) 2020 2021 2022 2023 2024 ASSETS Current Assets Cash and Cash Equivalents 757 989 649 574 544 Accounts Receivable 2,788 2,721 2,937 3,166 3,283 Regulatory Balancing Accounts, net of Liabiltiies (1) 747 1,619 1,677 1,040 743 Prepaid Expenses, Inventories and Collateral 1,742 1,836 1,920 1,993 2,057 Total Current Assets 6,035 7,165 7,182 6,773 6,628 Net Property, Plant and Equipment 66,340 71,347 75,809 80,991 85,277 Other Noncurrent Assets Nuclear Decommissioning Assets 3,291 3,409 3,527 3,645 3,763 Wildfire Fund Contribution 4,320 3,840 3,360 2,880 2,400 Regulatory Assets and Other 8,004 7,751 7,543 7,572 7,768 Total Other Noncurrent Assets 15,615 15,000 14,430 14,097 13,930 TOTAL ASSETS 87,990 93,511 97,421 101,861 105,835 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts Payable 2,152 2,140 2,063 2,005 1,986 Short Term Borrowing 1,720 2,000 2,000 2,000 2,000 Other Current Liabilities 1,648 1,853 1,631 1,421 1,350 Accrued Wildfire Liability (Gross) 1,350 0 0 0 0 Total Current Liabilities 6,870 5,992 5,694 5,426 5,336 Noncurrent Liabilities Deferred Income Taxes (320) (1,112) (1,147) (1,082) (906) Long-term debt 37,843 34,581 35,855 36,829 36,950 Memo: HoldCo Portion of Long Term Debt 4,750 3,500 3,100 2,900 2,250 Securitized bonds 0 7,676 8,287 8,864 9,403 Regulatory Liabilities 9,716 11,250 11,527 12,436 13,426 Asset Retirement Obligations 6,002 6,161 6,320 6,320 6,320 Other 6,099 6,086 6,328 6,673 7,005 Total Noncurrent Liabilities 59,340 64,643 67,172 70,039 72,199 Shareholders' Equity Total Shareholders' Equity 21,528 22,623 24,304 26,143 28,049 Noncontrolling Interest - Preferred Stock of Subsidiary 252 252 252 252 252 Total Shareholders' Equity 21,780 22,875 24,556 26,395 28,301 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 87,990 93,511 97,421 101,861 105,835 (1)Includes accounts classified as noncurrent in GAAP financial statements 8

PG&E Corporation Consolidated CONDENSED CONSOLIDATED PROJECTED STATEMENTS OF CASH FLOWS ($ millions) 2020 2021 2022 2023 2024 CASH FLOW STATEMENT Cash Flows From Operations: Net Income 468 (40) 1,861 2,130 2,387 Depreciation and Amortization 3,439 3,683 3,907 4,219 4,500 Net Amortization of Securitization Regulatory Assets and Liabilities (1,054) (265) 137 142 Wildfire Insurance Fund Amortization 480 480 480 480 480 Wildfire Insurance Fund Contribution (4,800) Change in Deferred Taxes (232) (792) (35) 64 176 Changes in Operating Assets and Liabilities 52 192 (374) (340) (208) Change in Balancing Accounts and Regulatory Assets (221) 1,452 125 815 479 Other Noncurrent Assets and Liabilities 910 42 39 55 25 Change in Other Working Capital 155 50 68 (71) (57) Payment of Liabilities Subject to Compromise, net of Insurance Proceeds (25,547) (1,350) Net Cash from Operations (25,295) 2,663 5,805 7,489 7,925 Investing Activities: Capital Expenditures (8,086) (8,140) (7,730) (8,702) (8,015) Net Change in Nuclear Decommissioning Funds (118) (118) (118) (118) (118) Proceeds from Asset Sales 1,322 0 0 0 0 Net Cash Used In Investing (6,882) (8,258) (7,848) (8,820) (8,133) Financing Activities: Holding Company Financing 19,850 (100) (400) (200) (650) Short and Long Term Utility Debt Issued (Matured/Repurchased) 11,552 (1,735) 1,670 1,171 769 Securitization Bonds Issued 0 7,676 611 576 540 Preferred Dividends Disbursed (42) (14) (14) (14) (14) Common dividends 0 0 (166) (277) (467) Net Cash Provided by Financing 31,360 5,827 1,701 1,257 178 NET CHANGE IN CASH (817) 232 (341) (75) (30) 9

StreetInsider

Log in to your account:

Form 8-K PACIFIC GAS & ELECTRIC For: Feb 18 Filed by: PG&E Corp

Categories

Next Articles