EX-99.2
Exhibit 99.2 2019 SECOND QUARTER EARNINGS August 9, 2019Exhibit 99.2
2019 SECOND QUARTER EARNINGS August 9, 2019
Forward Looking Statements This presentation contains statements
regarding management’s expectations and objectives for future periods as well as forecasts and estimates regarding potential liability in connection with the 2018 Camp fire and 2017 Northern California wildfires, the 2019 Wildfire Safety Plan,
2019 assumptions, 2019 IIC guidance, 2019-2023 capital expenditures, 2019-2023 weighted average ratebase, capital expenditures and ratebase assumptions, and general earnings sensitivities for 2019. It also includes assumptions regarding capital
expenditures, authorized rate base, key factors affecting earnings from operations and pending items with potential earnings from operations impact. 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 Pacific Gas and Electric Company (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, the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility, which could be adversely
affected if the Exclusive Filing Period or the Exclusive Solicitation Period is terminated, the ability to develop and obtain applicable bankruptcy court, creditor or regulatory approvals, the effect of any alternative proposals, views or objections
related to the plan of reorganization, potential complexities that may arise in connection with concurrent proceedings involving the bankruptcy court, the U.S. District Court, the CPUC, and the FERC, increased costs related to the Chapter 11 cases,
the ability to obtain sufficient financing sources for ongoing and future operations, disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance; • whether, in
light of the CPUC July 8, 2019 final decision in the Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, the Utility will be able to obtain a substantial recovery of costs related to the 2017
Northern California wildfires; • the impact of the 2018 Camp fire, 2017 Northern California wildfires, and 2015 Butte fire, including whether the Utility will be able to timely recover costs incurred in connection therewith in excess of the
Utility's currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liabilities associated with these fires; the timing and amount of insurance
recoveries; the timing and outcome of the 2017 Northern California Wildfires OII and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an
enforcement action and determined that the Utility failed to comply with applicable laws and regulations; • 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; • whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery; • the timing and outcomes of the 2019 GT&S rate
case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, future applications for WEMA, FHPMA and FRMMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings; • the 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 possibility that PG&E Corporation and the Utility may not be able to obtain exit financing on favorable terms or at all; • 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 to help reduce wildfire threats and improve safety as a result of
climate-driven wildfires and extreme weather, including the Utility’s ability to comply with targets and metrics set forth in the 2019 Wildfire Safety Plan; the cost of the program; and the timing and outcome of any proceeding to recover such
cost through rates; • the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other
events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or
third parties on which the Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility
incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance
coverage is available for these types of claims and sufficient to cover the Utility’s liability; • the timing and outcomes of phase two of the ex parte order instituting investigation (OII), of the safety culture OII, and the locate and
mark OII; • 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 other investigations that have been or may be commenced in the future, and the ultimate amount of
fines, penalties, and remedial and other costs that the Utility may incur as a result; • the ability of PG&E Corporation and the Utility to continue as going concerns (as to which management and their auditors have expressed substantial
doubt); 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, joint quarterly reports on Form 10-Q for the quarters ended March 31, 2019 and
June 30, 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
August 9, 2019. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation, including Appendices, and the accompanying press release were attached to PG&E Corporation’s Current
Report on Form 8-K that was furnished to the SEC on August 9, 2019 and is also available on PG&E Corporation’s website at www.pgecorp.com. 2Forward Looking Statements This presentation contains statements regarding management’s
expectations and objectives for future periods as well as forecasts and estimates regarding potential liability in connection with the 2018 Camp fire and 2017 Northern California wildfires, the 2019 Wildfire Safety Plan, 2019 assumptions, 2019 IIC
guidance, 2019-2023 capital expenditures, 2019-2023 weighted average ratebase, capital expenditures and ratebase assumptions, and general earnings sensitivities for 2019. It also includes assumptions regarding capital expenditures, authorized rate
base, key factors affecting earnings from operations and pending items with potential earnings from operations impact. 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 Pacific Gas and Electric Company (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, the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility, which could be adversely affected if the Exclusive Filing Period or the
Exclusive Solicitation Period is terminated, the ability to develop and obtain applicable bankruptcy court, creditor or regulatory approvals, the effect of any alternative proposals, views or objections related to the plan of reorganization,
potential complexities that may arise in connection with concurrent proceedings involving the bankruptcy court, the U.S. District Court, the CPUC, and the FERC, increased costs related to the Chapter 11 cases, the ability to obtain sufficient
financing sources for ongoing and future operations, disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance; • whether, in light of the CPUC July 8, 2019
final decision in the Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, the Utility will be able to obtain a substantial recovery of costs related to the 2017 Northern California wildfires;
• the impact of the 2018 Camp fire, 2017 Northern California wildfires, and 2015 Butte fire, including whether the Utility will be able to timely recover costs incurred in connection therewith in excess of the Utility's currently authorized
revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liabilities associated with these fires; the timing and amount of insurance recoveries; the timing and outcome of the
2017 Northern California Wildfires OII and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action and determined that the
Utility failed to comply with applicable laws and regulations; • 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; •
whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery; • the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate
cases, 2018 CEMA, future applications for WEMA, FHPMA and FRMMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings; • the 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 possibility that
PG&E Corporation and the Utility may not be able to obtain exit financing on favorable terms or at all; • 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 to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather, including the
Utility’s ability to comply with targets and metrics set forth in the 2019 Wildfire Safety Plan; the cost of the program; and the timing and outcome of any proceeding to recover such cost through rates; • the impact of wildfires,
droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause unplanned outages, reduce
generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the
reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage
or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and
sufficient to cover the Utility’s liability; • the timing and outcomes of phase two of the ex parte order instituting investigation (OII), of the safety culture OII, and the locate and mark OII; • 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 other investigations that have been or may be commenced in the future, and the ultimate amount of fines, penalties, and remedial and other costs that the
Utility may incur as a result; • the ability of PG&E Corporation and the Utility to continue as going concerns (as to which management and their auditors have expressed substantial doubt); 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, joint quarterly reports on Form 10-Q for the quarters ended March 31, 2019 and June 30, 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 August 9, 2019. PG&E Corporation and the Utility
undertake no obligation to update information contained herein. This presentation, including Appendices, and the accompanying press release were attached to PG&E Corporation’s Current Report on Form 8-K that was furnished to the SEC on
August 9, 2019 and is also available on PG&E Corporation’s website at www.pgecorp.com. 2
(1) (2) 2019 Wildfire Safety Plan Progress 2019 Forecast Spend YTD Spend
5-Year Forecast Spend ~$1.2B Expense ~$700M Expense ~$3.2B Expense (3) (3) ~$1.3B Capital ~$300M Capital ~$5.0B Capital Enhanced Inspections System Hardening and Resiliency Vegetation Management Transmission –Visual (# of Structures) Stronger
and more resilient poles and Enhanced vegetation management covered power lines (# of Line Miles) (# of Miles) 97% 49,760 structures inspected 32% 56% hardened inspected 150 highest risk miles 2,450 mi Transmission – Aerial (# of Structures)
95% Enhanced Situational Awareness 20% 49,760 structures inspected cleared 2,450 mi Weather Stations (# of Stations) Distribution (# of Poles) 62% Enhanced Operational Practices 100% completed 400 Stations 694,250 poles inspected Expanded Automation
(# of Reclosers) High-Definition Cameras (# of Cameras) Substation (# of Sites) 100% 44% 100% completed 287 Reclosers completed 71 Cameras 200 substations inspected (1) Reflects 2019 Wildfire Safety Plan progress in Tier 2 and Tier 3 high fire
threat districts as of June 30, 2019. (2) Wildfire Safety Plan spend pending CPUC and FERC approval. 2019 spend reflects the mid-point of proposed range of costs as outlined in the February 6, 2019 Wildfire Mitigation Plan submitted to the CPUC with
the exception of the Enhanced Inspection and Public Safety Power Shut-off programs, which have mid-point forecasts of ~$750M (OpEx) and ~$70M (CapEx), respectively. 2020-2022 forecasted costs reflect amounts requested in the 2020 General Rate Case,
with escalation applied to 2023. PG&E is in the process of preparing a five-year financial forecast, including projected expense and capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is currently
evaluating these assumptions, amounts may materially increase from the current forecast. (3) Pursuant to AB 1054, PG&E Corporation and the Utility will not earn an equity return on approximately $3.2B of fire risk mitigation capital expenditures
included in the Utility’s approved wildfire mitigation plans. 3 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.(1) (2) 2019 Wildfire
Safety Plan Progress 2019 Forecast Spend YTD Spend 5-Year Forecast Spend ~$1.2B Expense ~$700M Expense ~$3.2B Expense (3) (3) ~$1.3B Capital ~$300M Capital ~$5.0B Capital Enhanced Inspections System Hardening and Resiliency Vegetation Management
Transmission –Visual (# of Structures) Stronger and more resilient poles and Enhanced vegetation management covered power lines (# of Line Miles) (# of Miles) 97% 49,760 structures inspected 32% 56% hardened inspected 150 highest risk miles
2,450 mi Transmission – Aerial (# of Structures) 95% Enhanced Situational Awareness 20% 49,760 structures inspected cleared 2,450 mi Weather Stations (# of Stations) Distribution (# of Poles) 62% Enhanced Operational Practices 100% completed
400 Stations 694,250 poles inspected Expanded Automation (# of Reclosers) High-Definition Cameras (# of Cameras) Substation (# of Sites) 100% 44% 100% completed 287 Reclosers completed 71 Cameras 200 substations inspected (1) Reflects 2019 Wildfire
Safety Plan progress in Tier 2 and Tier 3 high fire threat districts as of June 30, 2019. (2) Wildfire Safety Plan spend pending CPUC and FERC approval. 2019 spend reflects the mid-point of proposed range of costs as outlined in the February 6, 2019
Wildfire Mitigation Plan submitted to the CPUC with the exception of the Enhanced Inspection and Public Safety Power Shut-off programs, which have mid-point forecasts of ~$750M (OpEx) and ~$70M (CapEx), respectively. 2020-2022 forecasted costs
reflect amounts requested in the 2020 General Rate Case, with escalation applied to 2023. PG&E is in the process of preparing a five-year financial forecast, including projected expense and capital expenditure assumptions, in connection with the
Chapter 11 proceedings. While PG&E is currently evaluating these assumptions, amounts may materially increase from the current forecast. (3) Pursuant to AB 1054, PG&E Corporation and the Utility will not earn an equity return on
approximately $3.2B of fire risk mitigation capital expenditures included in the Utility’s approved wildfire mitigation plans. 3 See the Forward Looking Statements for factors that could cause actual results to differ materially from the
guidance presented and underlying assumptions.
Q2 2019 Earnings Results Q2 YTD 2019 Earnings EPS Earnings EPS ($ in
millions, except per share amounts) Loss on a GAAP basis $ (2,553) $ ( 4.83) $ (2,420) $ (4.58) Items Impacting Comparability 2017 Northern California wildfire-related costs 1,445 2.73 1,470 2.78 2018 Camp fire-related costs 1 ,433 2.71 1 ,571 2.98
Electric asset inspection costs 198 0 .37 349 0 .66 Chapter 11-related costs 58 0.11 155 0 .29 Non-GAAP Earnings from Operations $ 581 $ 1.10 $ 1 ,125 $ 2.13 Q2 YTD 2019 Items Impacting Comparability ($ in millions, pre-tax) 2017 Northern
California wildfire-related costs $ 2, 007 $ 2,041 2018 Camp fire-related costs 1, 990 2,181 Electric asset inspection costs 275 485 Chapter 11-related costs 56 183 Note: Amounts may not sum due to rounding. Non-GAAP Earnings from Operations is not
calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit A for a reconciliation 4 of Earnings per Share (“EPS”) on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G
for the use of non-GAAP financial measures. Q2 2019 Earnings Results Q2 YTD 2019 Earnings EPS Earnings EPS ($ in millions, except per share amounts) Loss on a GAAP basis $ (2,553) $ ( 4.83) $ (2,420) $ (4.58) Items Impacting Comparability 2017
Northern California wildfire-related costs 1,445 2.73 1,470 2.78 2018 Camp fire-related costs 1 ,433 2.71 1 ,571 2.98 Electric asset inspection costs 198 0 .37 349 0 .66 Chapter 11-related costs 58 0.11 155 0 .29 Non-GAAP Earnings from Operations $
581 $ 1.10 $ 1 ,125 $ 2.13 Q2 YTD 2019 Items Impacting Comparability ($ in millions, pre-tax) 2017 Northern California wildfire-related costs $ 2, 007 $ 2,041 2018 Camp fire-related costs 1, 990 2,181 Electric asset inspection costs 275 485 Chapter
11-related costs 56 183 Note: Amounts may not sum due to rounding. Non-GAAP Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit A for a reconciliation 4 of Earnings
per Share (“EPS”) on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G for the use of non-GAAP financial measures.
Q2 2019: Quarter over Quarter Comparison Non-GAAP Earnings per Share
from Operations $1.40 ($0.05) $1.20 ($0.03) $0.07 ($0.01) ($0.01) ($0.03) $1.00 $0.80 $0.60 $1.16 $1.10 $0.40 $0.20 $0.00 Q2 2018 Resolution of 2018 Vegetation Timing of Taxes Liability Insurance Increase in Shares Growth in Rate Q2 2019 EPS from
Regulatory Items Management Costs Premiums Outstanding Base Earnings EPS from Operations Operations Non-GAAP Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit A for
a reconciliation 5 of Earnings per Share (“EPS”) on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G for the use of non-GAAP financial measures. Q2 2019: Quarter over Quarter Comparison Non-GAAP Earnings per
Share from Operations $1.40 ($0.05) $1.20 ($0.03) $0.07 ($0.01) ($0.01) ($0.03) $1.00 $0.80 $0.60 $1.16 $1.10 $0.40 $0.20 $0.00 Q2 2018 Resolution of 2018 Vegetation Timing of Taxes Liability Insurance Increase in Shares Growth in Rate Q2 2019 EPS
from Regulatory Items Management Costs Premiums Outstanding Base Earnings EPS from Operations Operations Non-GAAP Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit
A for a reconciliation 5 of Earnings per Share (“EPS”) on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G for the use of non-GAAP financial measures.
2019 Assumptions Capital Expenditures Key Factors Affecting ($ millions)
Earnings from Operations 2019 - Higher financing costs General Rate Case 4,500 - Incremental wildfire risk mitigation costs Gas Transmission and Storage 800 - Insurance premiums, net of regulatory cost recovery Transmission Owner 19 1,800 +
Incentive revenues, efficiencies and other benefits Total Cap Ex $7.1 billion Expected earnings below authorized: ~$100M to ~$200M (after-tax) Authorized Ratebase* (weighted average) ($ billions) Pending Items with Potential (1) Equity Ratio: 52%
Return on Equity: 10.25% Earnings from Operations Impact 2019 • 2019 Gas Transmission & Storage rate case General Rate Case 27.6 • Transmission Owner 18, 19, and 20 rate cases Gas Transmission and Storage 4.8 • Transmission
Owner 20 return on equity Transmission Owner 8.1 • Gas Transmission & Storage cap ex subject to audit Total Ratebase $40.5 billion ($400 million rate base from 2011-2014) *Base earnings plan assumes CPUC-currently authorized return on
equity across enterprise Note 1: Due to the net charges recorded in connection with the 2018 Camp fire and 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital
structure condition on February 28, 2019. The waiver is subject to CPUC approval. 6 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.2019
Assumptions Capital Expenditures Key Factors Affecting ($ millions) Earnings from Operations 2019 - Higher financing costs General Rate Case 4,500 - Incremental wildfire risk mitigation costs Gas Transmission and Storage 800 - Insurance premiums,
net of regulatory cost recovery Transmission Owner 19 1,800 + Incentive revenues, efficiencies and other benefits Total Cap Ex $7.1 billion Expected earnings below authorized: ~$100M to ~$200M (after-tax) Authorized Ratebase* (weighted average) ($
billions) Pending Items with Potential (1) Equity Ratio: 52% Return on Equity: 10.25% Earnings from Operations Impact 2019 • 2019 Gas Transmission & Storage rate case General Rate Case 27.6 • Transmission Owner 18, 19, and 20 rate
cases Gas Transmission and Storage 4.8 • Transmission Owner 20 return on equity Transmission Owner 8.1 • Gas Transmission & Storage cap ex subject to audit Total Ratebase $40.5 billion ($400 million rate base from 2011-2014) *Base
earnings plan assumes CPUC-currently authorized return on equity across enterprise Note 1: Due to the net charges recorded in connection with the 2018 Camp fire and 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to
the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval. 6 See the Forward Looking Statements for factors that could cause actual results to differ materially from the
guidance presented and underlying assumptions.
2019 Items Impacting Comparability Guidance ($ millions, pre-tax) (1)
2,190 - 2,240 2018 Camp fire-related costs (2) 2,050 - 2,090 2017 Northern California wildfire-related costs (3) 600 - 900 Electric asset inspection costs (4) ~360 - ~430 Chapter 11-related costs Estimated 2019 Items Impacting Comparability Guidance
Total ~$5,200 - ~5,660 (1) 2018 Camp fire-related costs reflect estimated third-party claims, Utility clean-up and repair, legal, and other costs associated with the 2018 Camp fire. (2) 2017 Northern California wildfire-related costs reflect
estimated third-party claims, legal, and other costs associated with the 2017 Northern California wildfires. (3) Electric asset inspection costs represent estimated incremental costs to complete enhanced and accelerated inspections of electric
transmission and distribution assets and certain resulting repairs that are not probable of recovery. (4) Chapter 11-related costs include estimated external legal, financing and other fees, net of interest income, directly associated with PG&E
Corporation’s and the Utility’s Chapter 11 cases. Changes from prior quarter noted in blue See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying
assumptions. See Appendix 1, Exhibit E for PG&E Corporation’s 2019 Items Impacting Comparability Guidance and Exhibit G for Use of Non-GAAP Financial Measures. 72019 Items Impacting Comparability Guidance ($ millions, pre-tax) (1) 2,190 -
2,240 2018 Camp fire-related costs (2) 2,050 - 2,090 2017 Northern California wildfire-related costs (3) 600 - 900 Electric asset inspection costs (4) ~360 - ~430 Chapter 11-related costs Estimated 2019 Items Impacting Comparability Guidance Total
~$5,200 - ~5,660 (1) 2018 Camp fire-related costs reflect estimated third-party claims, Utility clean-up and repair, legal, and other costs associated with the 2018 Camp fire. (2) 2017 Northern California wildfire-related costs reflect estimated
third-party claims, legal, and other costs associated with the 2017 Northern California wildfires. (3) Electric asset inspection costs represent estimated incremental costs to complete enhanced and accelerated inspections of electric transmission
and distribution assets and certain resulting repairs that are not probable of recovery. (4) Chapter 11-related costs include estimated external legal, financing and other fees, net of interest income, directly associated with PG&E
Corporation’s and the Utility’s Chapter 11 cases. Changes from prior quarter noted in blue See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying
assumptions. See Appendix 1, Exhibit E for PG&E Corporation’s 2019 Items Impacting Comparability Guidance and Exhibit G for Use of Non-GAAP Financial Measures. 7
Cap Ex Forecast (1) 2018-2023 Capital Expenditures ~$7B $7.1B ~$0.2B
~$0.1B ~$1.0B $6.6B ~$5.7B (3) CWSP $~700M Other GRC $~300M 2018 Recorded 2019 Currently Incremental Incremental Incremental Authorized Authorized GRC Request GT&S Request TO Request Plus Requested CapEx CapEx Range of ~$5.7B to ~$7B annually
from 2020-2023 (2) General Rate Case Gas Transmission & Storage Electric Transmission Owner CWSP Range Changes from prior quarter noted in blue (1) PG&E is in the process of preparing a five-year financial forecast, including projected
capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is currently evaluating capital expenditure assumptions, amounts may materially increase from the current forecast. (2) General Rate Case spend includes
transportation electrification. (3) Community Wildfire Safety Program (CWSP) proposed spend. See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.
8Cap Ex Forecast (1) 2018-2023 Capital Expenditures ~$7B $7.1B ~$0.2B ~$0.1B ~$1.0B $6.6B ~$5.7B (3) CWSP $~700M Other GRC $~300M 2018 Recorded 2019 Currently Incremental Incremental Incremental Authorized Authorized GRC Request GT&S Request TO
Request Plus Requested CapEx CapEx Range of ~$5.7B to ~$7B annually from 2020-2023 (2) General Rate Case Gas Transmission & Storage Electric Transmission Owner CWSP Range Changes from prior quarter noted in blue (1) PG&E is in the process of
preparing a five-year financial forecast, including projected capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is currently evaluating capital expenditure assumptions, amounts may materially increase
from the current forecast. (2) General Rate Case spend includes transportation electrification. (3) Community Wildfire Safety Program (CWSP) proposed spend. See the Forward Looking Statements for factors that could cause actual results to differ
materially from the guidance presented and underlying assumptions. 8
Expected Ratebase Growth (1) 2018-2023 Weighted Average Ratebase ~7
– 8.5% CAGR ~$52.0-56.0B ~$49.5-52.5B ~$47.0-49.0B ~$44.5-45.5B ~$40.5B $36.8B (3) (4) 2018 2019 2020 2021 2022 2023 (2) General Rate Case Gas Transmission & Storage Electric Transmission Owner Range Changes from prior quarter noted in
blue (1) Weighted average ratebase reflects the estimated impacts from the Tax Cuts and Jobs Act. It has not been reduced to reflect the $300M disallowance proposed by the CPUC in its proposed decision for 2019 GT&S. PG&E is in the process
of preparing a five-year financial forecast, including projected capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is currently evaluating capital expenditure assumptions, amounts may materially increase
from the current forecast. (2) General Rate Case spend includes transportation electrification. (3) Includes $400M for 2011-2014 spend subject to audit added in 2020. (4) Includes ~$600M related to enhanced inspections as well as restoration work in
2019 that have not been authorized by the CPUC or FERC and the Utility is not currently earning a return on these amounts. 9 See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance
presented and underlying assumptions.Expected Ratebase Growth (1) 2018-2023 Weighted Average Ratebase ~7 – 8.5% CAGR ~$52.0-56.0B ~$49.5-52.5B ~$47.0-49.0B ~$44.5-45.5B ~$40.5B $36.8B (3) (4) 2018 2019 2020 2021 2022 2023 (2) General Rate Case
Gas Transmission & Storage Electric Transmission Owner Range Changes from prior quarter noted in blue (1) Weighted average ratebase reflects the estimated impacts from the Tax Cuts and Jobs Act. It has not been reduced to reflect the $300M
disallowance proposed by the CPUC in its proposed decision for 2019 GT&S. PG&E is in the process of preparing a five-year financial forecast, including projected capital expenditure assumptions, in connection with the Chapter 11 proceedings.
While PG&E is currently evaluating capital expenditure assumptions, amounts may materially increase from the current forecast. (2) General Rate Case spend includes transportation electrification. (3) Includes $400M for 2011-2014 spend subject to
audit added in 2020. (4) Includes ~$600M related to enhanced inspections as well as restoration work in 2019 that have not been authorized by the CPUC or FERC and the Utility is not currently earning a return on these amounts. 9 See the Forward
Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.
Cap Ex and Ratebase Assumptions Base Case Assumptions 2020 2021 2022
2023 2017 GRC Decision General Rate Case L (1) 2020 GRC Filing (including CWSP) H 2015 GT&S Phase 2 Decision Gas Transmission & Storage L 2019 GT&S Filing H TO17 Settlement Transmission Owner L H TO20 Filing EV Phase 1 EV Phase 2
Light-Duty EV Infrastructure L&H SB350 L&H SB350 Approved Pending and future filings Potential Future Updates • 2020 and 2023 GRC rate cases • 2019 and 2022 Gas Transmission & Storage rate cases • 2018, 2019, 2020 and
future Transmission Owner rate cases • Wildfire mitigation investments • Future transportation electrification • Future storage opportunities • Plan of Reorganization Changes from prior quarter noted in blue (1) Represents
Community Wildfire Safety Program (CWSP) system hardening at proposed spending levels. See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. 10Cap
Ex and Ratebase Assumptions Base Case Assumptions 2020 2021 2022 2023 2017 GRC Decision General Rate Case L (1) 2020 GRC Filing (including CWSP) H 2015 GT&S Phase 2 Decision Gas Transmission & Storage L 2019 GT&S Filing H TO17 Settlement
Transmission Owner L H TO20 Filing EV Phase 1 EV Phase 2 Light-Duty EV Infrastructure L&H SB350 L&H SB350 Approved Pending and future filings Potential Future Updates • 2020 and 2023 GRC rate cases • 2019 and 2022 Gas
Transmission & Storage rate cases • 2018, 2019, 2020 and future Transmission Owner rate cases • Wildfire mitigation investments • Future transportation electrification • Future storage opportunities • Plan of
Reorganization Changes from prior quarter noted in blue (1) Represents Community Wildfire Safety Program (CWSP) system hardening at proposed spending levels. See the Forward Looking Statements for factors that could cause actual results to differ
materially from the guidance presented and underlying assumptions. 10
AppendixAppendix
Table of Contents Appendix 1 – Supplemental Earnings Materials
Slides 13-28 Appendix 2 – Overview of Regulatory Cases Slides 29-32 12Table of Contents Appendix 1 – Supplemental Earnings Materials Slides 13-28 Appendix 2 – Overview of Regulatory Cases Slides 29-32 12
Appendix 1 – Supplemental Earnings Materials Exhibit A:
Reconciliation of PG&E Corporation’s Consolidated Loss Attributable to Common Slides 14-16 Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Exhibit B: Key
Drivers of PG&E Corporation’s Non-GAAP Earnings per Common Share Slide 17 (“EPS”) from Operations Exhibit C: Operational Performance Metrics Slides 18-19 Exhibit D: Sales and Sources Summary Slide 20 Exhibit E: PG&E
Corporation’s 2019 Items Impacting Comparability Guidance Slides 21-22 Exhibit F: 2019 General Earnings Sensitivities Slide 23 Exhibit G: Use of Non-GAAP Financial Measures Slide 24 Exhibit H: GAAP Net Loss to Non-GAAP Adjusted EBITDA
Reconciliation Slide 25 Exhibit I: Expected Timelines of Selected Regulatory Cases Slides 26-28 13Appendix 1 – Supplemental Earnings Materials Exhibit A: Reconciliation of PG&E Corporation’s Consolidated Loss Attributable to Common
Slides 14-16 Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Exhibit B: Key Drivers of PG&E Corporation’s Non-GAAP Earnings per Common Share Slide 17
(“EPS”) from Operations Exhibit C: Operational Performance Metrics Slides 18-19 Exhibit D: Sales and Sources Summary Slide 20 Exhibit E: PG&E Corporation’s 2019 Items Impacting Comparability Guidance Slides 21-22 Exhibit F:
2019 General Earnings Sensitivities Slide 23 Exhibit G: Use of Non-GAAP Financial Measures Slide 24 Exhibit H: GAAP Net Loss to Non-GAAP Adjusted EBITDA Reconciliation Slide 25 Exhibit I: Expected Timelines of Selected Regulatory Cases Slides 26-28
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Exhibit A: Reconciliation of PG&E Corporation’s Consolidated
Loss Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended (in millions, except per
share amounts) June 30, June 30, Earnings per Earnings per Common Share Common Share Earnings (Diluted) Earnings (Diluted) (in millions, except per share amounts) 2019 2018 2019 2018 2019 2018 2019 2018 PG&E Corporation’s Loss on a GAAP
basis $ (2,553) $ (984) $ (4.83) $ (1.91) $ (2,420) $ (542) $ (4.58) $ (1.05) (1) Items Impacting Comparability: (2) 2017 Northern California wildfire-related costs 1,445 1,592 2.73 3.08 1,470 1,608 2.78 3.11 (3) 2018 Camp fire-related costs 1,433
— 2.71 — 1,571 — 2.98 — (4) Electric asset inspection costs 198 — 0.37 — 349 — 0.66 — (5) Chapter 11-related costs 58 — 0.11 — 155 — 0.29 — (6) Pipeline-related expenses —
9 — 0.02 — 16 — 0.03 (7) 2015 Butte fire-related costs, net of insurance — 7 — 0.01 — 11 — 0.02 (8) 2017 insurance premium cost recoveries — (23) — (0.04) — (23) — (0.04) PG&E
Corporation’s Non-GAAP Earnings (9) from Operations $ 581 $ 601 $ 1.10 $ 1.16 $ 1,125 $ 1,070 $ 2.13 $ 2.07 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, except for certain Chapter 11- related costs, which are not tax deductible. Amounts may not sum due to rounding. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of
operations and affect comparability of financial results between periods, consisting of the items listed in the table above. See Exhibit G: Use of Non-GAAP Financial Measures. (2) The Utility incurred costs of $2.0 billion (before the tax impact of
$561 million) and $2.0 billion (before the tax impact of $571 million) during the three and six months ended June 30, 2019, respectively, associated with the 2017 Northern California wildfires. This includes accrued charges of $2.0 billion (before
the tax impact of $560 million) during the three and six months ended June 30, 2019 related to an increase in the recorded liability related to third-party claims. The Utility also incurred costs of $7 million (before the tax impact of $2 million)
and $41 million (before the tax impact of $11 million) during the three and six months ended June 30, 2019, respectively, for legal and other costs. Three Months Ended Six Months Ended (in millions, pre-tax) June 30, 2019 June 30, 2019 Third-party
claims $ 2,000 $ 2,000 Legal and other costs 7 41 $ 2,007 $ 2,041 2017 Northern California wildfire-related costs 14Exhibit A: Reconciliation of PG&E Corporation’s Consolidated Loss Attributable to Common Shareholders in Accordance with
Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended (in millions, except per share amounts) June 30, June 30, Earnings per Earnings per
Common Share Common Share Earnings (Diluted) Earnings (Diluted) (in millions, except per share amounts) 2019 2018 2019 2018 2019 2018 2019 2018 PG&E Corporation’s Loss on a GAAP basis $ (2,553) $ (984) $ (4.83) $ (1.91) $ (2,420) $ (542) $
(4.58) $ (1.05) (1) Items Impacting Comparability: (2) 2017 Northern California wildfire-related costs 1,445 1,592 2.73 3.08 1,470 1,608 2.78 3.11 (3) 2018 Camp fire-related costs 1,433 — 2.71 — 1,571 — 2.98 — (4) Electric
asset inspection costs 198 — 0.37 — 349 — 0.66 — (5) Chapter 11-related costs 58 — 0.11 — 155 — 0.29 — (6) Pipeline-related expenses — 9 — 0.02 — 16 — 0.03 (7) 2015 Butte
fire-related costs, net of insurance — 7 — 0.01 — 11 — 0.02 (8) 2017 insurance premium cost recoveries — (23) — (0.04) — (23) — (0.04) PG&E Corporation’s Non-GAAP Earnings (9) from Operations
$ 581 $ 601 $ 1.10 $ 1.16 $ 1,125 $ 1,070 $ 2.13 $ 2.07 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, except for certain Chapter 11- related costs, which are
not tax deductible. Amounts may not sum due to rounding. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between
periods, consisting of the items listed in the table above. See Exhibit G: Use of Non-GAAP Financial Measures. (2) The Utility incurred costs of $2.0 billion (before the tax impact of $561 million) and $2.0 billion (before the tax impact of $571
million) during the three and six months ended June 30, 2019, respectively, associated with the 2017 Northern California wildfires. This includes accrued charges of $2.0 billion (before the tax impact of $560 million) during the three and six months
ended June 30, 2019 related to an increase in the recorded liability related to third-party claims. The Utility also incurred costs of $7 million (before the tax impact of $2 million) and $41 million (before the tax impact of $11 million) during the
three and six months ended June 30, 2019, respectively, for legal and other costs. Three Months Ended Six Months Ended (in millions, pre-tax) June 30, 2019 June 30, 2019 Third-party claims $ 2,000 $ 2,000 Legal and other costs 7 41 $ 2,007 $ 2,041
2017 Northern California wildfire-related costs 14
Exhibit A: Reconciliation of PG&E Corporation’s Consolidated
Income (Loss) Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Second Quarter, 2019 vs. 2018 (in millions, except per share amounts) (3) The
Utility incurred costs of $2.0 billion (before the tax impact of $557 million) and $2.2 billion (before the tax impact of $610 million) during the three and six months ended June 30, 2019, respectively, associated with the 2018 Camp fire. This
includes accrued charges of $1.9 billion (before the tax impact of $532 million) during the three and six months ended June 30, 2019 related to an increase in the recorded liability related to third-party claims. The Utility also incurred costs of
$71 million (before the tax impact of $20 million) and $250 million (before the tax impact of $70 million) during the three and six months ended June 30, 2019, respectively, for clean-up and repair costs. In addition, the Utility incurred costs of
$19 million (before the tax impact of $5 million) and $32 million (before the tax impact of $9 million) during the three and six months ended June 30, 2019, respectively, for legal and other costs. Three Months Ended Six Months Ended (in millions,
pre-tax) June 30, 2019 June 30, 2019 Third-party claims $ 1,900 $ 1,900 Utility clean-up and repair costs 71 250 Legal and other costs 19 32 2018 Camp fire-related costs $ 1,990 $ 2,181 (4) The Utility incurred costs of $275 million (before the tax
impact of $77 million) and $485 million (before the tax impact of $136 million) during the three and six months ended June 30, 2019, respectively, for incremental operating expenses related to enhanced and accelerated inspections of electric
transmission and distribution assets, and certain resulting repairs that are not probable of recovery. (5) The Utility incurred costs of $56 million (before the incremental net tax expense of $2 million) and $183 million (before the tax impact of
$28 million) during the three and six months ended June 30, 2019, respectively, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 Cases. This includes $114 million (before the tax impact of $32 million) during
the six months ended June 30, 2019 for debtor-in-possession (“DIP”) financing costs. The Utility also incurred legal and other costs of $77 million (before the tax impact of $4 million) and $101 million (before the tax impact of $5
million) during the three and six months ended June 30, 2019, respectively ($64 million and $82 million of legal and other costs during the three and six months ended June 30, 2019, respectively, are not tax deductible.) These costs were partially
offset by interest income of $21 million (before the tax impact of $6 million) and $32 million (before the tax impact of $9 million) recorded during the three and six months ended June 30, 2019, respectively. Three Months Ended Six Months Ended (in
millions, pre-tax) June 30, 2019 June 30, 2019 DIP financing costs $ — $ 114 Legal and other costs 77 101 Interest income (21) (32) Chapter 11-related costs $ 56 $ 183 15Exhibit A: Reconciliation of PG&E Corporation’s Consolidated
Income (Loss) Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Second Quarter, 2019 vs. 2018 (in millions, except per share amounts) (3) The
Utility incurred costs of $2.0 billion (before the tax impact of $557 million) and $2.2 billion (before the tax impact of $610 million) during the three and six months ended June 30, 2019, respectively, associated with the 2018 Camp fire. This
includes accrued charges of $1.9 billion (before the tax impact of $532 million) during the three and six months ended June 30, 2019 related to an increase in the recorded liability related to third-party claims. The Utility also incurred costs of
$71 million (before the tax impact of $20 million) and $250 million (before the tax impact of $70 million) during the three and six months ended June 30, 2019, respectively, for clean-up and repair costs. In addition, the Utility incurred costs of
$19 million (before the tax impact of $5 million) and $32 million (before the tax impact of $9 million) during the three and six months ended June 30, 2019, respectively, for legal and other costs. Three Months Ended Six Months Ended (in millions,
pre-tax) June 30, 2019 June 30, 2019 Third-party claims $ 1,900 $ 1,900 Utility clean-up and repair costs 71 250 Legal and other costs 19 32 2018 Camp fire-related costs $ 1,990 $ 2,181 (4) The Utility incurred costs of $275 million (before the tax
impact of $77 million) and $485 million (before the tax impact of $136 million) during the three and six months ended June 30, 2019, respectively, for incremental operating expenses related to enhanced and accelerated inspections of electric
transmission and distribution assets, and certain resulting repairs that are not probable of recovery. (5) The Utility incurred costs of $56 million (before the incremental net tax expense of $2 million) and $183 million (before the tax impact of
$28 million) during the three and six months ended June 30, 2019, respectively, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 Cases. This includes $114 million (before the tax impact of $32 million) during
the six months ended June 30, 2019 for debtor-in-possession (“DIP”) financing costs. The Utility also incurred legal and other costs of $77 million (before the tax impact of $4 million) and $101 million (before the tax impact of $5
million) during the three and six months ended June 30, 2019, respectively ($64 million and $82 million of legal and other costs during the three and six months ended June 30, 2019, respectively, are not tax deductible.) These costs were partially
offset by interest income of $21 million (before the tax impact of $6 million) and $32 million (before the tax impact of $9 million) recorded during the three and six months ended June 30, 2019, respectively. Three Months Ended Six Months Ended (in
millions, pre-tax) June 30, 2019 June 30, 2019 DIP financing costs $ — $ 114 Legal and other costs 77 101 Interest income (21) (32) Chapter 11-related costs $ 56 $ 183 15
Exhibit A: Reconciliation of PG&E Corporation’s Consolidated
Income (Loss) Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations (6) The Utility incurred costs of $12 million (before the tax impact of $3 million)
and $22 million (before the tax impact of $6 million) during the three and six months ended June 30, 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. (7) The Utility incurred costs, net of insurance, of $10 million (before the tax impact of $3 million) and $15 million (before the tax impact of $4 million) during the three and six months ended June 30, 2018,
respectively, associated with the 2015 Butte fire. This includes $10 million (before the tax impact of $3 million) and $22 million (before the tax impact of $6 million) during the three and six months ended June 30, 2018, respectively, for legal
costs. These costs were partially offset by $7 million (before the tax impact of $2 million) recorded during the six months ended June 30, 2018 for contractor insurance recoveries. Three Months Ended Six Months Ended (in millions, pre-tax) June 30,
2018 June 30, 2018 Legal costs $ 10 $ 22 Insurance recoveries — (7) 2015 Butte fire-related costs, net of insurance $ 10 $ 15 (8) As a result of the California Public Utilities Commission’s (“CPUC”) June 2018 decision
authorizing a Wildfire Expense Memorandum Account (“WEMA”), the Utility recorded $32 million (before the tax impact of $9 million) during the three and six months ended June 30, 2018 for probable cost recoveries of insurance premiums
incurred in 2017 above amounts included in authorized revenue requirements. (9) “Non-GAAP earnings from operations” is a non-GAAP financial measure. See Exhibit G: Use of Non-GAAP Financial Measures. 16Exhibit A: Reconciliation of
PG&E Corporation’s Consolidated Income (Loss) Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations (6) The Utility incurred costs of $12
million (before the tax impact of $3 million) and $22 million (before the tax impact of $6 million) during the three and six months ended June 30, 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. (7) The Utility incurred costs, net of insurance, of $10 million (before the tax impact of $3 million) and $15 million (before the tax impact of $4 million) during the three
and six months ended June 30, 2018, respectively, associated with the 2015 Butte fire. This includes $10 million (before the tax impact of $3 million) and $22 million (before the tax impact of $6 million) during the three and six months ended June
30, 2018, respectively, for legal costs. These costs were partially offset by $7 million (before the tax impact of $2 million) recorded during the six months ended June 30, 2018 for contractor insurance recoveries. Three Months Ended Six Months
Ended (in millions, pre-tax) June 30, 2018 June 30, 2018 Legal costs $ 10 $ 22 Insurance recoveries — (7) 2015 Butte fire-related costs, net of insurance $ 10 $ 15 (8) As a result of the California Public Utilities Commission’s
(“CPUC”) June 2018 decision authorizing a Wildfire Expense Memorandum Account (“WEMA”), the Utility recorded $32 million (before the tax impact of $9 million) during the three and six months ended June 30, 2018 for probable
cost recoveries of insurance premiums incurred in 2017 above amounts included in authorized revenue requirements. (9) “Non-GAAP earnings from operations” is a non-GAAP financial measure. See Exhibit G: Use of Non-GAAP Financial Measures.
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Exhibit B: Key Drivers of PG&E Corporation’s Non-GAAP
Earnings per Common Share (“EPS”) from Operations Second Quarter, 2019 vs. 2018 Second Quarter 2019 vs. 2018 YTD 2019 vs. 2018 (in millions, except per share amounts) Earnings per Earnings per Common Common Share Share Earnings (Diluted)
Earnings (Diluted) (1) 2018 Non-GAAP Earnings from Operations $ 601 $ 1.16 $ 1,070 $ 2.07 (2) Resolution of 2018 regulatory items (29) (0.05) (29) (0.05) (3) Vegetation management costs (17) (0.03) (32) (0.06) (4) Timing of taxes (6) (0.01) 15 0.03
(5) Liability insurance premiums (4) (0.01) 17 0.03 Increase in shares outstanding — (0.03) — (0.05) Miscellaneous (2) — 14 0.03 Growth in rate base earnings 38 0.07 70 0.13 (1) 2019 Non-GAAP Earnings from Operations $ 581 $ 1.10 $
1,125 $ 2.13 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 earnings from operations and (ii) EPS on a GAAP basis to non-GAAP EPS from operations. (2) Represents the impact of various regulatory matters resolved during the three and six months ended June 30, 2018, with no similar
impact in 2019. (3) Represents the increase in routine vegetation management costs incurred during the three and six months ended June 30, 2019, which are not recoverable through authorized revenue requirements. (4) 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. (5) Represents insurance premium costs incurred in the
first quarter of 2018, above amounts included in authorized revenue requirements, which became probable of recovery in the second quarter of 2018 as a result of the CPUC’s June 2018 decision authorizing a WEMA, with no similar impact in 2019.
Also represents lower insurance premium costs during the three and six months ended June 30, 2019, due to the accelerated amortization of a portion of the Utility’s liability insurance premiums during the fourth quarter of 2018 as a result of
the 2018 Camp fire. 17Exhibit B: Key Drivers of PG&E Corporation’s Non-GAAP Earnings per Common Share (“EPS”) from Operations Second Quarter, 2019 vs. 2018 Second Quarter 2019 vs. 2018 YTD 2019 vs. 2018 (in millions, except per
share amounts) Earnings per Earnings per Common Common Share Share Earnings (Diluted) Earnings (Diluted) (1) 2018 Non-GAAP Earnings from Operations $ 601 $ 1.16 $ 1,070 $ 2.07 (2) Resolution of 2018 regulatory items (29) (0.05) (29) (0.05) (3)
Vegetation management costs (17) (0.03) (32) (0.06) (4) Timing of taxes (6) (0.01) 15 0.03 (5) Liability insurance premiums (4) (0.01) 17 0.03 Increase in shares outstanding — (0.03) — (0.05) Miscellaneous (2) — 14 0.03 Growth in
rate base earnings 38 0.07 70 0.13 (1) 2019 Non-GAAP Earnings from Operations $ 581 $ 1.10 $ 1,125 $ 2.13 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 earnings from operations and (ii) EPS on a GAAP basis to non-GAAP EPS from operations. (2) Represents the impact of various
regulatory matters resolved during the three and six months ended June 30, 2018, with no similar impact in 2019. (3) Represents the increase in routine vegetation management costs incurred during the three and six months ended June 30, 2019, which
are not recoverable through authorized revenue requirements. (4) 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. (5) Represents insurance premium costs incurred in the first quarter of 2018, above amounts included in authorized revenue requirements, which became probable of recovery in the second quarter of 2018 as a
result of the CPUC’s June 2018 decision authorizing a WEMA, with no similar impact in 2019. Also represents lower insurance premium costs during the three and six months ended June 30, 2019, due to the accelerated amortization of a portion of
the Utility’s liability insurance premiums during the fourth quarter of 2018 as a result of the 2018 Camp fire. 17
Exhibit C: Operational Performance Metrics Meets YTD 2019 Performance
Results YTD Actual 2019 Target (1) Target Safety Nuclear Operations Safety Diablo Canyon Power Plant (DCPP) Reliability and Safety 99.9 93.7 P Electric Operations Safety Public Safety Index 0.6 1.0 Gas and Electric Operations Safety Asset Records
Duration Index 1.2 1.0 P Gas Operations Safety Gas First-Time In-Line Inspection 87.0 183.0 P Employee Safety Serious Injuries and Fatalities Corrective Actions Index 1.3 1.0 P Customer Escalated Customer Complaints 10.2 12.2 P Financial 1 Non-GAAP
Earnings from Operations $1,125 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 earnings from operations 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 earnings from operations is not publicly reported. 18Exhibit C: Operational Performance Metrics Meets YTD 2019 Performance Results YTD Actual 2019 Target (1) Target Safety
Nuclear Operations Safety Diablo Canyon Power Plant (DCPP) Reliability and Safety 99.9 93.7 P Electric Operations Safety Public Safety Index 0.6 1.0 Gas and Electric Operations Safety Asset Records Duration Index 1.2 1.0 P Gas Operations Safety Gas
First-Time In-Line Inspection 87.0 183.0 P Employee Safety Serious Injuries and Fatalities Corrective Actions Index 1.3 1.0 P Customer Escalated Customer Complaints 10.2 12.2 P Financial 1 Non-GAAP Earnings from Operations $1,125 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 earnings from operations 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 earnings from operations is not publicly reported. 18
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 earnings from operations” (shown in millions of dollars)
is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” 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. 19Definitions 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 earnings from operations” (shown in millions of dollars) is a non-GAAP financial measure and is
calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” 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. 19
Exhibit D: Pacific Gas and Electric Company Sales and Sources Summary
Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Sales from Energy Deliveries (in millions kWh) 18,004 18,705 36,439 37,525 Total Electric Customers at June 30 — — 5,439,578
5,420,082 Total Gas Sales (in Bcf) 157 169 416 401 Total Gas Customers at June 30 — — 4,510,566 4,491,527 Sources of Electric Energy Deliveries (in millions kWh): Total Utility Generation 8,529 7,414 17,189 14,737 Total Utility Net
Purchases/(Sales) (1,155) 7,333 289 13,443 10,021 6,604 19,595 12,359 Direct Access and Community Choice Aggregator Purchases (1) 18,004 18,705 36,439 37,525 Total Electric Energy Delivered Diablo Canyon Performance: Overall Capacity Factor
(including refuelings) 100 % 99 % 89 % 88 % 2/10/19/ - 2/11/18 - Refueling Outage Period None None 3/18/19 3/22/18 Refueling Outage Duration during the Period (days) None None 36 39 (1) Includes other sources/(uses) of electric energy totaling 609
million kWh and (2,646) million kWh for the three months ended June 30, 2019 and 2018, respectively, and (634) million kWh and (3,014) million kWh for the six months ended June 30, 2019 and 2018, respectively. Please see the 2018 Annual Report on
Form 10-K for additional information about operating statistics. 20Exhibit D: Pacific Gas and Electric Company Sales and Sources Summary Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Sales
from Energy Deliveries (in millions kWh) 18,004 18,705 36,439 37,525 Total Electric Customers at June 30 — — 5,439,578 5,420,082 Total Gas Sales (in Bcf) 157 169 416 401 Total Gas Customers at June 30 — — 4,510,566 4,491,527
Sources of Electric Energy Deliveries (in millions kWh): Total Utility Generation 8,529 7,414 17,189 14,737 Total Utility Net Purchases/(Sales) (1,155) 7,333 289 13,443 10,021 6,604 19,595 12,359 Direct Access and Community Choice Aggregator
Purchases (1) 18,004 18,705 36,439 37,525 Total Electric Energy Delivered Diablo Canyon Performance: Overall Capacity Factor (including refuelings) 100 % 99 % 89 % 88 % 2/10/19/ - 2/11/18 - Refueling Outage Period None None 3/18/19 3/22/18 Refueling
Outage Duration during the Period (days) None None 36 39 (1) Includes other sources/(uses) of electric energy totaling 609 million kWh and (2,646) million kWh for the three months ended June 30, 2019 and 2018, respectively, and (634) million kWh and
(3,014) million kWh for the six months ended June 30, 2019 and 2018, respectively. Please see the 2018 Annual Report on Form 10-K for additional information about operating statistics. 20
Exhibit E: PG&E Corporation’s 2019 Items Impacting
Comparability (“IIC”) Guidance 2019 IIC Guidance (in millions, after-tax) Low High (1) Estimated Items Impacting Comparability: (2) 2017 Northern California wildfire-related costs $ 1,505 $ 1,476 (3) 2018 Camp fire-related costs 1,613
1,577 (4) Electric asset inspection costs 648 432 (5) Chapter 11-related costs ~338 ~287 Estimated IIC Guidance $ ~4,104 $ ~3,772 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98%
for 2019, except for certain Chapter 11-related costs. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between
periods. See Exhibit G: Use of Non-GAAP Financial Measures. (2) “2017 Northern California wildfire-related costs” refers to estimated third-party claims and legal and other costs associated with the 2017 Northern California wildfires.
The total offsetting tax impact for the low and high IIC guidance range is $585 million and $574 million, respectively. 2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range Third-party claims $ 2,000 $ 2,000 Legal and other
costs 90 50 2017 Northern California wildfire-related costs $ 2,090 $ 2,050 (3) “2018 Camp fire-related costs” refers to estimated third-party claims, Utility clean-up and repair costs, and legal and other costs associated with the 2018
Camp fire. The total offsetting tax impact for the low and high IIC guidance range is $627 million and $613 million, respectively. 2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range Third-party claims $ 1,900 $ 1,900 Utility
clean-up and repair costs 270 250 Legal and other costs 70 40 2018 Camp fire-related costs $ 2,240 $ 2,190 Actual financial results for 2019 may differ materially from the guidance provided. For a discussion of the factors that may affect future
results, see the Forward-Looking Statements. 21Exhibit E: PG&E Corporation’s 2019 Items Impacting Comparability (“IIC”) Guidance 2019 IIC Guidance (in millions, after-tax) Low High (1) Estimated Items Impacting Comparability:
(2) 2017 Northern California wildfire-related costs $ 1,505 $ 1,476 (3) 2018 Camp fire-related costs 1,613 1,577 (4) Electric asset inspection costs 648 432 (5) Chapter 11-related costs ~338 ~287 Estimated IIC Guidance $ ~4,104 $ ~3,772 All amounts
presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2019, except for certain Chapter 11-related costs. (1) “Items impacting comparability” represent items that management does
not consider part of the normal course of operations and affect comparability of financial results between periods. See Exhibit G: Use of Non-GAAP Financial Measures. (2) “2017 Northern California wildfire-related costs” refers to
estimated third-party claims and legal and other costs associated with the 2017 Northern California wildfires. The total offsetting tax impact for the low and high IIC guidance range is $585 million and $574 million, respectively. 2019 Low IIC
guidance High IIC guidance (in millions, pre-tax) range range Third-party claims $ 2,000 $ 2,000 Legal and other costs 90 50 2017 Northern California wildfire-related costs $ 2,090 $ 2,050 (3) “2018 Camp fire-related costs” refers to
estimated third-party claims, Utility clean-up and repair costs, and legal and other costs associated with the 2018 Camp fire. The total offsetting tax impact for the low and high IIC guidance range is $627 million and $613 million, respectively.
2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range Third-party claims $ 1,900 $ 1,900 Utility clean-up and repair costs 270 250 Legal and other costs 70 40 2018 Camp fire-related costs $ 2,240 $ 2,190 Actual financial results
for 2019 may differ materially from the guidance provided. For a discussion of the factors that may affect future results, see the Forward-Looking Statements. 21
Exhibit E: PG&E Corporation’s 2019 Items Impacting
Comparability (“IIC”) Guidance (4) “Electric asset inspection costs” represents incremental operating expense related to enhanced and accelerated inspections of electric transmission and distribution assets, and certain
resulting repairs that are not probable of recovery. The total offsetting tax impact for the low and high IIC guidance range is $252 million and $168 million, respectively. 2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range
Electric asset inspection costs $ 900 $ 600 (5) “Chapter 11-related costs” consists of external legal, financing, and other fees, net of interest income, directly associated with PG&E Corporation’s and the Utility’s
Chapter 11 Cases, of which ~$100 million of legal and other costs are not tax deductible. The total offsetting tax impact for the low and high IIC guidance range is $92 million and $73 million, respectively. 2019 Low IIC guidance High IIC guidance
(in millions, pre-tax) range range Legal and other costs $ 340 $ 280 DIP financing costs ~120 ~120 Interest income (30) (40) Chapter 11-related costs $ ~430 $ ~360 Actual financial results for 2019 may differ materially from the guidance provided.
For a discussion of the factors that may affect future results, see the Forward-Looking Statements. 22Exhibit E: PG&E Corporation’s 2019 Items Impacting Comparability (“IIC”) Guidance (4) “Electric asset inspection
costs” represents incremental operating expense related to enhanced and accelerated inspections of electric transmission and distribution assets, and certain resulting repairs that are not probable of recovery. The total offsetting tax impact
for the low and high IIC guidance range is $252 million and $168 million, respectively. 2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range Electric asset inspection costs $ 900 $ 600 (5) “Chapter 11-related costs”
consists of external legal, financing, and other fees, net of interest income, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 Cases, of which ~$100 million of legal and other costs are not tax deductible.
The total offsetting tax impact for the low and high IIC guidance range is $92 million and $73 million, respectively. 2019 Low IIC guidance High IIC guidance (in millions, pre-tax) range range Legal and other costs $ 340 $ 280 DIP financing costs
~120 ~120 Interest income (30) (40) Chapter 11-related costs $ ~430 $ ~360 Actual financial results for 2019 may differ materially from the guidance provided. For a discussion of the factors that may affect future results, see the Forward-Looking
Statements. 22
Exhibit F: General Earnings Sensitivities for 2019 PG&E Corporation
and Pacific Gas and Electric Company Estimated 2019 Earnings Variable Description of Change Impact Rate base +/- $100 million change in allowed rate base +/- $5 million Return on equity (ROE) +/- 0.1% change in allowed ROE +/- $19 million Share
count +/- 1% change in average shares +/- $0.04 per share +/- $7 million change in at-risk revenue (pre-tax), including Revenues Electric Transmission and Gas Transmission and Storage +/- $0.01 per share These general earnings sensitivities with
respect to factors that may affect 2019 earnings are forward-looking statements that are based on various assumptions. Actual results may differ materially. For a discussion of the factors that may affect future results, see the Forward Looking
Statements. 23Exhibit F: General Earnings Sensitivities for 2019 PG&E Corporation and Pacific Gas and Electric Company Estimated 2019 Earnings Variable Description of Change Impact Rate base +/- $100 million change in allowed rate base +/- $5
million Return on equity (ROE) +/- 0.1% change in allowed ROE +/- $19 million Share count +/- 1% change in average shares +/- $0.04 per share +/- $7 million change in at-risk revenue (pre-tax), including Revenues Electric Transmission and Gas
Transmission and Storage +/- $0.01 per share These general earnings sensitivities with respect to factors that may affect 2019 earnings are forward-looking statements that are based on various assumptions. Actual results may differ materially. For a
discussion of the factors that may affect future results, see the Forward Looking Statements. 23
Exhibit G: 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 earnings from operations” and “non-GAAP EPS from
operations” 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 earnings from
operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of
the normal course of operations and affect comparability of financial results between periods, consisting of the items listed in Exhibit A. “Non-GAAP EPS from operations” also referred to as “non-GAAP earnings per share from
operations” is a non-GAAP financial measure and is calculated as non-GAAP earnings from operations divided by common shares outstanding (diluted). PG&E Corporation uses non-GAAP earnings from operations and non-GAAP EPS from operations 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 earnings from operations and non-GAAP EPS from operations 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
earnings from operations and non-GAAP EPS from operations 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. 24Exhibit G: 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 earnings from operations” and “non-GAAP EPS from operations” 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 earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting
comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods, consisting of the items listed in Exhibit A. “Non-GAAP EPS from
operations” also referred to as “non-GAAP earnings per share from operations” is a non-GAAP financial measure and is calculated as non-GAAP earnings from operations divided by common shares outstanding (diluted). PG&E
Corporation uses non-GAAP earnings from operations and non-GAAP EPS from operations 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 earnings from operations and non-GAAP EPS from operations 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 earnings from operations and non-GAAP EPS from operations 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. 24
Exhibit H: GAAP Net Loss to Non-GAAP Adjusted EBITDA Reconciliation
PG&E Corporation and Pacific Gas and Electric Company Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended June June 30, 30, (in millions) 2019 2018 2019 2018 PG&E Corporation’s Net Loss on a GAAP basis $ (2,549) $ (980) $
(2,413) $ (535) Income tax benefit (1,119) (593) (1,203) (542) Other income, net (66) (106) (137) (214) Interest expense 60 226 163 446 Interest income (22) (12) (44) (21) Reorganization items, net 56 — 183 — Operating loss $ (3,640) $
(1,465) $ (3,451) $ (866) Depreciation, amortization, and decommissioning 796 746 1,593 1,498 Electric asset inspection costs 275 — 485 — 2018 Camp fire-related costs 1,990 — 2,181 — 2017 Northern California wildfire-related
costs 2,007 2,211 2,041 2,233 2015 Butte fire-related costs — 10 — 15 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 1,428 $ 1,501 $ 2,849 $ 2,880 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 electric asset inspection, 2018 Camp fire-, 2017 Northern California wildfire-, and 2015 Butte fire-related 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 income to non-GAAP Adjusted EBITDA. 25Exhibit H: GAAP Net Loss to Non-GAAP
Adjusted EBITDA Reconciliation PG&E Corporation and Pacific Gas and Electric Company Second Quarter, 2019 vs. 2018 Three Months Ended Six Months Ended June June 30, 30, (in millions) 2019 2018 2019 2018 PG&E Corporation’s Net Loss on a
GAAP basis $ (2,549) $ (980) $ (2,413) $ (535) Income tax benefit (1,119) (593) (1,203) (542) Other income, net (66) (106) (137) (214) Interest expense 60 226 163 446 Interest income (22) (12) (44) (21) Reorganization items, net 56 — 183
— Operating loss $ (3,640) $ (1,465) $ (3,451) $ (866) Depreciation, amortization, and decommissioning 796 746 1,593 1,498 Electric asset inspection costs 275 — 485 — 2018 Camp fire-related costs 1,990 — 2,181 — 2017
Northern California wildfire-related costs 2,007 2,211 2,041 2,233 2015 Butte fire-related costs — 10 — 15 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 1,428 $ 1,501 $ 2,849 $ 2,880 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 electric asset inspection, 2018 Camp fire-, 2017 Northern California wildfire-, and 2015 Butte fire-related
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 income to non-GAAP Adjusted
EBITDA. 25
Exhibit I: Pacific Gas and Electric Company Expected Timelines of
Selected Regulatory Cases Regulatory Case Docket # Key Dates 2019 Gas Transmission and Storage Rate Case A.17-11-009 Nov 17, 2017 – Application filed Jan 4, 2018 – Prehearing Conference (PHC) Mar 30, 2018 – Update testimony filed
to reflect 2017 Tax Act reductions in forecasted revenue requirement Apr 24, 2018 – CPUC to issue ruling on proceeding scope and schedule Jun 29, 2018 – PAO testimony Jul 20, 2018 – Intervenor testimony Jun-Jul 2018 – Public
participation hearings Jun-Aug 2018 – Settlement discussions Aug 20, 2018 – Concurrent rebuttal testimony Sep 17-Oct 12, 2018 – Evidentiary hearings Nov 14, 2018 – Opening Briefs Dec 14, 2018 – Reply Briefs Jul 16, 2019
– Proposed Decision issued Aug 5, 2019 – Comments on the proposed decision Aug 12, 2019 – Reply comments on the proposed decision 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 – Comparison exhibit and update testimony (if necessary) Nov 6, 2019 – Evidentiary hearing on update testimony (if necessary) Nov 15, 2019
– Opening Briefs Dec 6, 2019 – Reply Briefs Q1 2020 – Proposed Decision per Scoping Memo 2020 Cost of Capital A.19-04-015 Apr 22, 2019 – Application filed May 22, 2019 – Protests filed Jun 17, 2019 – Prehearing
Conference Jul 2, 2019 – Scoping Memo Aug 1, 2019 – Intervenor testimony and Applicants' supplemental testimony on AB 1054 Aug 16, 2019 – Rebuttal testimony on Intervenor testimony and testimony on supplemental testimony Aug 21,
2019 – Rebuttal testimony on supplemental testimony Sept 2019 – Evidentiary Hearings Sept 20, 2019 – Opening briefs Sept 27, 2019 – Reply briefs Nov 15, 2019 – Proposed decision TBD – Final decision no sooner than
30 days after proposed decision 26Exhibit I: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates 2019 Gas Transmission and Storage Rate Case A.17-11-009 Nov 17, 2017 – Application
filed Jan 4, 2018 – Prehearing Conference (PHC) Mar 30, 2018 – Update testimony filed to reflect 2017 Tax Act reductions in forecasted revenue requirement Apr 24, 2018 – CPUC to issue ruling on proceeding scope and schedule Jun 29,
2018 – PAO testimony Jul 20, 2018 – Intervenor testimony Jun-Jul 2018 – Public participation hearings Jun-Aug 2018 – Settlement discussions Aug 20, 2018 – Concurrent rebuttal testimony Sep 17-Oct 12, 2018 –
Evidentiary hearings Nov 14, 2018 – Opening Briefs Dec 14, 2018 – Reply Briefs Jul 16, 2019 – Proposed Decision issued Aug 5, 2019 – Comments on the proposed decision Aug 12, 2019 – Reply comments on the proposed
decision 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 – Comparison exhibit and update testimony (if
necessary) Nov 6, 2019 – Evidentiary hearing on update testimony (if necessary) Nov 15, 2019 – Opening Briefs Dec 6, 2019 – Reply Briefs Q1 2020 – Proposed Decision per Scoping Memo 2020 Cost of Capital A.19-04-015 Apr 22,
2019 – Application filed May 22, 2019 – Protests filed Jun 17, 2019 – Prehearing Conference Jul 2, 2019 – Scoping Memo Aug 1, 2019 – Intervenor testimony and Applicants' supplemental testimony on AB 1054 Aug 16, 2019
– Rebuttal testimony on Intervenor testimony and testimony on supplemental testimony Aug 21, 2019 – Rebuttal testimony on supplemental testimony Sept 2019 – Evidentiary Hearings Sept 20, 2019 – Opening briefs Sept 27, 2019
– Reply briefs Nov 15, 2019 – Proposed decision TBD – Final decision no sooner than 30 days after proposed decision 26
Exhibit I: Pacific Gas and Electric Company Expected Timelines of
Selected Regulatory Cases Regulatory Case Docket # Key Dates Locate and Mark OII Dec 13, 2018 – OII issued I.18-12-007 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 May 2, 2019 – Settlement conference May 29, 2019 – Second settlement conference Jul 24,
2019 – SED opening testimony Jul 30, 2019 – Status conference Aug 16, 2019 – Intervenor opening testimony Sept 18, 2019 – PG&E reply testimony Oct 4, 2019 – SED rebuttal testimony Oct 21-25, 2019 – Hearings
Safety Culture and Governance Order Instituting I.15-08-019 Dec 21, 2018 – President Picker issued ruling on next phase of the Safety Culture OII 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, 2019 – Workshop on Corporate Governance Apr 26, 2019 – Workshop on Corporate Structure May 7, 2019 – Proposed decision issued May 27, 2019 –
PG&E opening comments filed June 13, 2019 – Final decision issued June 18, 2019 – President Picker issued ruling requesting comment on safety culture proposals July 19, 2019 – Opening comments filed August 2, 2019 – Reply
comments due 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 Q3-Q4 2019 – Final decision expected
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, 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. Dec 20, 2018 – FERC approved the all-party settlement 27Exhibit I: Pacific Gas and Electric Company Expected
Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates Locate and Mark OII Dec 13, 2018 – OII issued I.18-12-007 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 May 2, 2019 – Settlement conference May 29, 2019 – Second settlement
conference Jul 24, 2019 – SED opening testimony Jul 30, 2019 – Status conference Aug 16, 2019 – Intervenor opening testimony Sept 18, 2019 – PG&E reply testimony Oct 4, 2019 – SED rebuttal testimony Oct 21-25, 2019
– Hearings Safety Culture and Governance Order Instituting I.15-08-019 Dec 21, 2018 – President Picker issued ruling on next phase of the Safety Culture OII 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, 2019 – Workshop on Corporate Governance Apr 26, 2019 – Workshop on Corporate Structure May 7, 2019 – Proposed decision issued
May 27, 2019 – PG&E opening comments filed June 13, 2019 – Final decision issued June 18, 2019 – President Picker issued ruling requesting comment on safety culture proposals July 19, 2019 – Opening comments filed August
2, 2019 – Reply comments due 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 Q3-Q4 2019 –
Final decision expected 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, 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. Dec 20, 2018 – FERC approved the all-party settlement 27
Exhibit I: Pacific Gas and Electric Company Expected Timelines of
Selected Regulatory Cases Regulatory Case Docket # Key Dates Transmission Owner Rate Case (TO20) Oct 1, 2018 – Application filed ER19-13 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 Wildfire Cost Recovery Criteria Order Instituting R.19-01-006
Jan 10, 2019 – CPUC opened an Order Instituting Rulemaking on the Customer Harm Threshold Rulemaking Feb 11, 2019 – Opening comments filed Feb 20, 2019 – Prehearing Conference Feb 25, 2019 – Reply Comments filed Mar 29, 2019
– Scoping Memo Apr 5, 2019 – CPUC Staff Report Apr 10, 2019 – Workshop Apr 24, 2019 – Comments on staff proposal May 1, 2019 – Reply comments on staff proposal May 24, 2019 – Proposed decision issued Jun 13, 2019
– Opening comments filed Jun 18, 2019 – Reply comments filed Jun 27, 2019 – Final decision issued Wildfire Mitigation Plan Order Instituting R.18-10-007 Feb 6, 2019 – Wildfire Mitigation Plan filed Rulemaking Feb 13, 2019
– Wildfire Mitigation Plans presentation workshop Week of Feb 25 – Technical workshops Feb 26, 2019 – Prehearing Conference Mar 13, 2019 – Intervenor comments Mar 22, 2019 – Utility reply comments Apr 29, 2019 –
Proposed decisions issued Jun 4, 2019 – Final decisions issued 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 17-19 – SED Workshops 2017 Northern California Wildfires Order I.19-06-015 Jun 27, 2019 – OII issued Instituting Investigation Jul 29, 2019 – PG&E to submit its initial response
Jul 29, 2019 – Immediate corrective actions response due Aug 13, 2019 – Prehearing Conference AB 1054 Order Instituting Rulemaking R.19-01-017 Jul 26, 2019 – OIR issued Aug 7, 2019 – Prehearing Conference Statements Served
and Filed Aug 8, 2019 – Prehearing Conference Aug 12, 2019 – Scoping Memo and Ruling Aug 22, 2019 – Opening Comments on Scoped Issues Aug 29, 2019 – Reply Comments on Scoped Issues Sept 2019 – Proposed Decision Oct 2019
– Final Decision 28 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.Exhibit I: Pacific Gas and Electric
Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates Transmission Owner Rate Case (TO20) Oct 1, 2018 – Application filed ER19-13 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 Wildfire Cost Recovery
Criteria Order Instituting R.19-01-006 Jan 10, 2019 – CPUC opened an Order Instituting Rulemaking on the Customer Harm Threshold Rulemaking Feb 11, 2019 – Opening comments filed Feb 20, 2019 – Prehearing Conference Feb 25, 2019
– Reply Comments filed Mar 29, 2019 – Scoping Memo Apr 5, 2019 – CPUC Staff Report Apr 10, 2019 – Workshop Apr 24, 2019 – Comments on staff proposal May 1, 2019 – Reply comments on staff proposal May 24, 2019
– Proposed decision issued Jun 13, 2019 – Opening comments filed Jun 18, 2019 – Reply comments filed Jun 27, 2019 – Final decision issued Wildfire Mitigation Plan Order Instituting R.18-10-007 Feb 6, 2019 – Wildfire
Mitigation Plan filed Rulemaking Feb 13, 2019 – Wildfire Mitigation Plans presentation workshop Week of Feb 25 – Technical workshops Feb 26, 2019 – Prehearing Conference Mar 13, 2019 – Intervenor comments Mar 22, 2019 –
Utility reply comments Apr 29, 2019 – Proposed decisions issued Jun 4, 2019 – Final decisions issued 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 17-19 – SED Workshops 2017 Northern California Wildfires Order I.19-06-015 Jun 27, 2019 – OII issued Instituting Investigation Jul 29, 2019
– PG&E to submit its initial response Jul 29, 2019 – Immediate corrective actions response due Aug 13, 2019 – Prehearing Conference AB 1054 Order Instituting Rulemaking R.19-01-017 Jul 26, 2019 – OIR issued Aug 7, 2019
– Prehearing Conference Statements Served and Filed Aug 8, 2019 – Prehearing Conference Aug 12, 2019 – Scoping Memo and Ruling Aug 22, 2019 – Opening Comments on Scoped Issues Aug 29, 2019 – Reply Comments on Scoped
Issues Sept 2019 – Proposed Decision Oct 2019 – Final Decision 28 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.
A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y
C A S E S 2020 CPUC General Rate Case Ÿ On December 13, 2018, PG&E filed its application for its 2020 General Rate Case requesting a ~$1.1B increase in revenue requirement over 2019 authorized. ($ billions) 2020 2021 2022 Revenue
Requirement ~$9.6 ~$10.0 ~$10.5 Ÿ On March 8, 2019, the CPUC issued a Scoping Memo and Ruling setting the category, need for hearings, issues to be addressed, and schedule outlining steps towards a proposed decision by Q1 2020 Ÿ In July
2019, the Public Advocates Office, proposed a 2020 revenue requirement increase of $503M, followed by increases of $298M in 2021, and $329M in 2022. Ÿ Assigned Commissioner: Randolph Administrative Law Judges: Lirag, Lau Changes from prior
quarter noted in blue 29A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y C A S E S 2020 CPUC General Rate Case Ÿ On December 13, 2018, PG&E filed its application for its 2020 General Rate Case requesting a ~$1.1B
increase in revenue requirement over 2019 authorized. ($ billions) 2020 2021 2022 Revenue Requirement ~$9.6 ~$10.0 ~$10.5 Ÿ On March 8, 2019, the CPUC issued a Scoping Memo and Ruling setting the category, need for hearings, issues to be
addressed, and schedule outlining steps towards a proposed decision by Q1 2020 Ÿ In July 2019, the Public Advocates Office, proposed a 2020 revenue requirement increase of $503M, followed by increases of $298M in 2021, and $329M in 2022. Ÿ
Assigned Commissioner: Randolph Administrative Law Judges: Lirag, Lau Changes from prior quarter noted in blue 29
A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y
C A S E S 2019 CPUC Gas Transmission and Storage Rate Case Ÿ On November 17, 2017, PG&E filed its 2019 Gas Transmission and Storage rate case. PG&E subsequently revised its request to reflect impacts from the Tax Cuts and Jobs Act as
well as other forecast updates to a $184M increase over the 2018 authorized revenue requirement. ($ billions) 2019 2020 2021 2022 Revenue ~$1.48 ~$1.59 ~$1.69 ~$1.68 Requirement Ÿ In June 2018, the Public Advocates Office, proposed a 2019
revenue requirement increase of $85M, followed by increases of $94M in 2020, $121M in 2021, and $28M in 2022. On October 1, 2018, PG&E entered into a stipulation with the Public Advocates Office that, if approved, would extend the rate case
cycle through 2022. Ÿ In July 2019, the CPUC issued a Proposed Decision proposing a 2019 revenue requirement increase of $26M, followed by increases of $100M in 2020, $84M in 2021, and $64M in 2022. It adopts a third attrition year (i.e., 2022)
to allow for potential combination with the 2023 General Rate Case. Ÿ Assigned Commissioner: Rechtschaffen Administrative Law Judge: Powell Changes from prior quarter noted in blue 30A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L
A T O R Y C A S E S 2019 CPUC Gas Transmission and Storage Rate Case Ÿ On November 17, 2017, PG&E filed its 2019 Gas Transmission and Storage rate case. PG&E subsequently revised its request to reflect impacts from the Tax Cuts and Jobs
Act as well as other forecast updates to a $184M increase over the 2018 authorized revenue requirement. ($ billions) 2019 2020 2021 2022 Revenue ~$1.48 ~$1.59 ~$1.69 ~$1.68 Requirement Ÿ In June 2018, the Public Advocates Office, proposed a
2019 revenue requirement increase of $85M, followed by increases of $94M in 2020, $121M in 2021, and $28M in 2022. On October 1, 2018, PG&E entered into a stipulation with the Public Advocates Office that, if approved, would extend the rate case
cycle through 2022. Ÿ In July 2019, the CPUC issued a Proposed Decision proposing a 2019 revenue requirement increase of $26M, followed by increases of $100M in 2020, $84M in 2021, and $64M in 2022. It adopts a third attrition year (i.e., 2022)
to allow for potential combination with the 2023 General Rate Case. Ÿ Assigned Commissioner: Rechtschaffen Administrative Law Judge: Powell Changes from prior quarter noted in blue 30
A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y
C A S E S FERC Transmission Owner Rate Cases TO18 (2017 Revenues) • July 29, 2016 – Filed TO18 with FERC requesting $1.7 billion revenue requirement, an ROE (inclusive of 50 basis point adder) of 10.90% • We cannot predict when a
final decision will be issued TO19 (2018 Revenues) • On August 24, 2018, the Parties reached a settlement-in-principle on all issues tying the TO19 settlement RRQ to the final FERC decision in TO18 by applying a settlement factor of 98.85% to
the final TO18 authorized RRQ • On December 20, 2019, the FERC issued a letter approving the settlement, but rates will be subject to refund until resolution of TO18 TO20 (2019 Revenues) • On October 1, 2018, PG&E filed its TO20 rate
case, requesting both 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, the FERC accepted the filing and established interim rates
effective May 1, 2019, and directed the parties to settlement procedures while holding hearings in abeyance 31 Changes from prior quarter noted in blueA P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y C A S E S FERC
Transmission Owner Rate Cases TO18 (2017 Revenues) • July 29, 2016 – Filed TO18 with FERC requesting $1.7 billion revenue requirement, an ROE (inclusive of 50 basis point adder) of 10.90% • We cannot predict when a final decision
will be issued TO19 (2018 Revenues) • On August 24, 2018, the Parties reached a settlement-in-principle on all issues tying the TO19 settlement RRQ to the final FERC decision in TO18 by applying a settlement factor of 98.85% to the final TO18
authorized RRQ • On December 20, 2019, the FERC issued a letter approving the settlement, but rates will be subject to refund until resolution of TO18 TO20 (2019 Revenues) • On October 1, 2018, PG&E filed its TO20 rate case,
requesting both 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, the FERC accepted the filing and established interim rates effective May
1, 2019, and directed the parties to settlement procedures while holding hearings in abeyance 31 Changes from prior quarter noted in blue
A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y
C A S E S 2020 Cost of Capital Filing Ÿ On April 22, 2018, PG&E filed its application for its 2020 Cost of Capital, including a request for a 16% rate of return on equity, which would result in a $1.2 billion increase in its revenue
requirement based on currently authorized rate base. Ÿ A prehearing conference was held on June 17, 2019 and a Scoping Memo and Ruling was issued on July 2, 2019 setting the category, issues to be addressed, and schedule outlining steps toward
a proposed decision in November 2019. Ÿ On August 1, 2019, PG&E filed supplemental testimony to reflect the expected effects of AB 1054 on the Utility’s wildfire-related risk profile. PG&E proposed to revise its rate of return on
equity to 12%, which would result in a $400 million increase in its revenue requirement based on currently authorized rate base. 2019 Currently Authorized 2020 Requested (as revised) Capital Weighted Capital Weighted Cost Cost Structure Cost
Structure Cost Return on Common Equity 10.25% 52.0% 5.33% 12.0% 52.0% 6.24% Preferred Stock 5.60% 1.0% 0.06% 5.52% 0.5% 0.03% Long-Term Debt 4.89% 47.0% 2.30% 5.16% 47.5% 2.45% Weighted Average Cost of Capital 7.69% 8.72% Changes from prior quarter
noted in blue 32A P P E N D I X 2 – O V E R V I E W O F K E Y R E G U L A T O R Y C A S E S 2020 Cost of Capital Filing Ÿ On April 22, 2018, PG&E filed its application for its 2020 Cost of Capital, including a request for a 16% rate
of return on equity, which would result in a $1.2 billion increase in its revenue requirement based on currently authorized rate base. Ÿ A prehearing conference was held on June 17, 2019 and a Scoping Memo and Ruling was issued on July 2, 2019
setting the category, issues to be addressed, and schedule outlining steps toward a proposed decision in November 2019. Ÿ On August 1, 2019, PG&E filed supplemental testimony to reflect the expected effects of AB 1054 on the Utility’s
wildfire-related risk profile. PG&E proposed to revise its rate of return on equity to 12%, which would result in a $400 million increase in its revenue requirement based on currently authorized rate base. 2019 Currently Authorized 2020
Requested (as revised) Capital Weighted Capital Weighted Cost Cost Structure Cost Structure Cost Return on Common Equity 10.25% 52.0% 5.33% 12.0% 52.0% 6.24% Preferred Stock 5.60% 1.0% 0.06% 5.52% 0.5% 0.03% Long-Term Debt 4.89% 47.0% 2.30% 5.16%
47.5% 2.45% Weighted Average Cost of Capital 7.69% 8.72% Changes from prior quarter noted in blue 32
