Exhibit 99.2

SECOND QUARTER EARNINGS CALL July 26, 2018

Forward Looking Statements This presentation contains statements regarding management’s expectations and objectives for future periods as well as forecasts and estimates regarding 2018 IIC guidance, 2017 Tax Cuts and Jobs Act expected impact, 2018-2019 capital expenditures, 2018-2019 weighted average ratebase, equity needs and sources, and 2018 general earnings sensitivities. It also includes 2018 assumptions regarding capital expenditures, authorized rate base, authorized cost of capital, and certain other factors. These statements and other statements that are not purely historical constitute forward-looking statements that are necessarily subject to various risks and uncertainties. Actual results may differ materially from those described in forward-looking statements. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Factors that could cause actual results to differ materially include, but are not limited to: • the impact of the Northern California w ildfires, including whether the Utility w ill be able to recover any costs for service restoration and repair to the Utility’s facilities through its Catastrophic Event Memorandum Account (CEMA); the timing and outcome of the remaining wildfire investigations; the extent to which the Utility w ill have liability associated with the fires; • whether the Utility will be able to recover costs in connection with the Northern California wildfires in excess of insurance through regulatory mechanisms and the timing of such recovery; • potential liabilities in connection with fines or penalties that could be imposed on the Utility if the California Public Utilities Commission (CPUC) or any other law enforcement agency brings an enforcement action in connection w ith the Northern California w ildfires and determines that the Utility failed to comply w ith applicable law s and regulations; • the timing and outcome of the Butte fire litigation and of any proceeding to recover costs in excess of insurance through regulatory mechanisms and the timing of such recovery; and w hether additional investigations and proceedings in connection w ith the Butte fire w ill be opened and any additional fines or penalties imposed on the Utility; • w hether PG&E Corporation and the Utility are able to successfully challenge the application of the doctrine of inverse condemnation to investor-owned utilities, and the timing and outcome of pending w ildfire legislation; • the costs of the Utility’s insurance and w hether the Utility w ill be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery; • w hether the Utility can obtain w ildfire insurance at a reasonable cost in the future, or at all, and w hether insurance coverage is adequate for future losses or claims; • the timing and outcome of any CPUC decision related to the Utility’s March 30, 2018 submissions in connection w ith the impact of the Tax Cuts and Jobs Act of 2017 on the Utility’s rate cases, and its implementation plan; • the timing and outcomes of the 2019 Gas Transmission and Storage (GT&S) rate case, Transmission Ow ner (TO) 18 and TO19 rate cases, 2018 CEMA, and other ratemaking and regulatory proceedings; • the ability of PG&E Corporation and the Utility to access capital markets and other sources of financing in a timely manner on acceptable terms; • further credit ratings downgrades that could, among other things, result in higher borrowing costs, fewer financing options, and additional collateral posting, especially if PG&E Corporation’s or the Utility’s credit ratings w ere to fall below investment grade; • the cost of the Utility’s community w ildfire safety program, and the timing and outcome of any proceeding to recover such cost through rates; • the timing and outcomes of phase tw o of the ex parte order instituting investigation (OII) and of the safety culture 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 w hich the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; • the outcome of the probation and the monitorship, the timing and outcomes of the debarment proceeding, the Safety and Enforcement Division’s (SED) unresolved enforcement matters relating to the Utility’s compliance w ith natural gas-related law s and regulations, and other investigations that have been or may be commenced, and the ultimate amount of fines, penalties, and remedial and other costs that the Utility may incur as a result; 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, 2017, their joint quarterly reports on Form 10-Q for the quarters ended March 31, 2018 and June 30, 2018, respectively, and other reports filed with the SEC, w hich are available on PG&E Corporation’s w ebsite at www.pgecorp.com and on the Securities and Exchange Commission w ebsite at www.sec.gove. This presentation is not complete without the accompanying statements made by management during the webcast conference call held on July 26, 2018. The statements in this presentation are made as of July 26, 2018. PG&E Corporation undertakes 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 July 26, 2018 and, along with the replay of the conference call, is also available on PG&E Corporation’s website at www.pgecorp.com. 2

Northern California Wildfires Response Legislative Advocating to address impacts of climate change and the need for comprehensive solutions Legal Challenging the application of inverse condemnation in multiple forums Operations Executing numerous programs as precautionary measures intended to reduce the risk of future wildfires Regulatory Updating compliance requirements in high-risk wildfire zones 3

Legal Update Status Update Next Steps • 6/7/2018: Appellate court denied • California Supreme Court response PG&E’s writ to review inverse expected by fall of 2018 condemnation challenge • If granted, appellate process could Butte Fire • 6/18/2018: PG&E filed petition to take ~1 – 2 years Case review with California Supreme Court • ~3,800 individual plaintiffs as of 7/20/2018 • 5/21/2018: Trial court denied PG&E’s • Appellate Court response expected request to dismiss inverse by fall of 2018 Northern condemnation claims • If granted, appellate process could California • 7/20/2018: PG&E filed for Appellate take ~1 – 2 years Wildfires review of trial court decision • ~2,900 individual plaintiffs as of 7/20/2018 PG&E intends to continue to challenge the application of inverse condemnation to investor-owned utilities in multiple forums 4

Q2 2018 Earnings Results Q2 2018 Earnings EPS (millions) (millions) Earnings (Loss) on a GAAP basis $ (984) $ (1.91) $ (542) $ (1.05) Items Impacting Comparability Northern California wildfire-related costs, net of insurance 1,592 3.08 1,608 3.11 Pipeline-related expenses 9 0.02 16 0.03 Butte fire-related costs, net of insurance 7 0.01 11 0.02 2017 insurance premium cost recoveries (23) (0.04) (23) (0.04) Non-GAAP Earnings from Operations $ 601 $ 1.16 $ 1,070 $ 2.07 Items Impacting Comparability (millions, pre-tax) Q2 2018 Northern California wildfire-related costs, net of insurance $ 2,211 $ 2,233 Pipeline-related expenses 12 22 Butte fire-related costs, net of insurance 10 15 2017 insurance premium cost recoveries (32) (32) Non-GAAP Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 2, Exhibit A for a reconciliation 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. 5

Q2 2018: Quarter over Quarter Comparison Non-GAAP Earnings per Share from Operations $1.40 $0.07 ($0.03) ($0.01) $1.20 ($0.01) $0.04 $0.05 $0.05 $1.00 $0.06 $0.08 $0.80 $0.60 $1.16 $0.86 $0.40 $0.20 $0.00 Q2 2017 Timing and Resolution of Insurance Timing of Taxes Growth in Miscellaneous Timing of Decrease in Increase in Q2 2018 Non-GAAP EPS Duration of Regulatory Items Premium Rate Base 2017 GRC Authorized Shares Non-GAAP EPS from Nuclear Refueling Cost Recoveries Earnings Cost Recovery Return on Equity Outstanding from Operations Outages Operations Non-GAAP Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 2, Exhibit A for a reconciliation of Earnings per Share (“EPS”) on a GAAP basis to Non-GAAP Earnings from Operations and Exhibit G for the use of non-GAAP financial measures. 6

2018 Assumptions Capital Expenditures Authorized Ratebase (weighted average) ($ millions) ($ billions) 2018 2018 General Rate Case 3,900 General Rate Case 25.9 Gas Transmission and Storage 1,000 Gas Transmission and Storage 3.8 Transmission Owner 19 1,400 Transmission Owner 7.1 Total Cap Ex $6.3 billion Total Ratebase $36.8 billion Other Factors Affecting Authorized Cost of Capital* Earnings from Operations Return on Equity: 10.25% + Incentive revenues, efficiencies and other benefits - GT&S amounts not requested Equity Ratio: 52%—Ex parte settlement GT&S revenue adjustment - Insurance premiums, net of regulatory cost recovery *CPUC authorized CWIP earnings: offset by below-the-line costs 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. 7

2018 Items Impacting Comparability Guidance ($ millions, pre-tax) Pipeline-related expenses (1) 35 - 60 Butte fire-related costs, net of insurance (2) 30 - 260 Northern California wildfire-related costs, net of insurance (3) 2,225 - 2,240 2017 insurance premium cost recoveries (4) (32) Estimated 2018 Items Impacting Comparability Guidance Total $2,258 - 2,528 (1) Total cost of rights-of-w ay program expected to range from $450 million to $475 million. (2) Butte fire-related costs, net of insurance, reflects legal costs and estimated third-party claims associated w ith the Butte fire, net of contractor insurance recoveries. (3) Northern California w ildfire-related costs, net of insurance, reflects estimated third-party claims, legal and other costs, and Utility clean-up and repair costs associated w ith the Northern California w ildfires, net of probable insurance recoveries. (4) 2017 insurance premium cost recoveries includes insurance premium costs incurred in 2017, above amounts included in authorized revenue requirements, that are probable of recovery as a result of the CPUC’s June 2018 decision authorizing a WEMA. 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 2, Exhibit E for PG&E Corporation’s 2018 Items Impacting Comparability Guidance and Exhibit G for Use of Non-GAAP Financial Measures. 8

Robust Cap Ex Supports Strong Returns Capital Expenditures ($ in B) 2017-2019 $6.3B ~$6B $5.8B 2017 Recorded 2018 2019 General Rate Case Gas Transmission & Storage Electric Transmission Owner Range See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. 9

Ratebase Supports Strong Returns 2017-2019 Weighted Average Ratebase ($ in B) (1) ~7.5—8% CAGR $36.8B ~$40B $34.4B 2017 2018 2019 General Rate Case Gas Transmission & Storage Electric Transmission Owner Range Base Case Assumptions Potential Future Updates 2018 2019 • 2019 Gas Transmission & Storage rate case GRC L 2017 GRC Decision • 2018 and 2019 Transmission Owner rate cases H 2017 GRC Decision • Future transportation electrification GT&S (2) L 2015 GT&S Phase 2 Decision • State infrastructure modernization (e.g., rail and water H 2015 GT&S Phase 2 Decision 2019 GT&S Filing projects) TO L TO19 Filing TO17 Settlement • Future storage opportunities H TO19 Filing Other Light-Duty Electric Vehicle Infrastructure and SB350 Programs Approved Pending and future filings (1) Weighted average ratebase in 2018 and 2019 reflect the estimated impacts from the 2017 Tax Cuts and Jobs Act. (2) Includes $400M for 2011-2014 spend subject to audit added in 2019. 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. 10

Equity Needs and Sources Needs Sources Previous Guidance (Internal Programs) Internal Programs (Excluding DRSPP (1)) + Tax Reform + Cash from Dividend Suspension + Non-Cash Northern California Wildfire-related third-party claims, net of insurance + Other Items Impacting Comparability June 30, 2018 shares outstanding: ~517 million Changes from prior quarter noted in blue (1) Dividend Reinvestment and Stock Purchase Plan. See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. 11

Appendix

Appendix 1 – Incremental Equity Factors Incremental Equity Factors for Unrecovered Costs Equity Impacting Event Multiplier Non-deductible cash charges 100% Cash expenses 72% Non-cash charges (1) 36% (1) Multiplier applies at time of accrual; additional 36% applies at time of cash charge. 13

Appendix 1 – Tax Cuts and Jobs Act Expected Impact Annual reduction in customer revenue driven ~$450M Lower Customer Bills by lower corporate tax rate annual revenue reduction 2021 Faster net operating loss amortization and (1) Cash Tax Payments or later ~1 year acceleration of federal tax payments estimated year federal tax payments begin Higher ratebase growth and increased earnings primarily driven by elimination of ~$800M Ratebase Growth bonus depreciation; $300M in 2018 and an incremental ratebase additional $500M in 2019 in 2019 Higher financing needs driven by incremental ~$400M Financing Needs ratebase growth; additional equity needs of ~$400M through 2019 incremental equity needs through 2019 Tax Cuts and Jobs Act results in lower customer bills and higher ratebase growth Changes from prior quarter noted in blue Tax reform implementation is subject to CPUC and FERC approval. (1) Timing will be dependent on claims payments associated with the Northern California wildfires. See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. 14

Appendix 2 – Supplemental Earnings Materials Exhibit A: Reconciliation of PG&E Corporation’s Consolidated Income Available Slides 16-17 for Common 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 Slide 18 Common Share (“EPS”) from Operations Exhibit C: Operational Performance Metrics Slides 19-20 Exhibit D: Sales and Sources Summary Slide 21 Exhibit E: PG&E Corporation’s 2018 Items Impacting Comparability Guidance Slides 22-23 Exhibit F: 2018 General Earnings Sensitivities Slide 24 Exhibit G: Use of Non-GAAP Financial Measures Slide 25 Exhibit H: Expected Timelines of Selected Regulatory Cases Slides 26-28 15

Exhibit A: Reconciliation of PG&E Corporation’s Consolidated Income Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations Second Quarter, 2018 vs. 2017 Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share amounts) Earnings per Earnings per Earnings Common Share Earnings Common Share (Diluted) (Diluted) 2018 2017 2018 2017 2018 2017 2018 2017 PG&E Corporation’s Earnings (Loss) on a GAAP basis $ (984) $ 406 $ (1.91) $ 0.79 $ (542) $ 982 $ (1.05) $ 1.92 Items Impacting Comparability: (1) Northern California wildfire-related costs, net of insurance (2) 1,592—3.08— 1,608—3.11 -Pipeline-related expenses (3) 9 17 0.02 0.03 16 33 0.03 0.06 Butte fire-related costs, net of insurance (4) 7 (17) 0.01 (0.03) 11 (15) 0.02 (0.03) 2017 insurance premium cost recoveries (5) (23)— (0.04)— (23)— (0.04) -Diablo Canyon settlement-related disallowance (6)— 32—0.06— 32—0.06 Legal and regulatory-related expenses (7)—2—0.01—4—0.01 Fines and penalties (8) — —— 36— 0.07 GT&S revenue timing impact (9) — — — (88)— (0.17) PG&E Corporation’s Non-GAAP Earnings from Operations (10) $ 601 $ 440 $ 1.16 $ 0.86 $ 1,070 $ 984 $ 2.07 $ 1.92 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98 percent for 2018 and40.75 percent for 2017, except for certain fines and penalties in 2017. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations andaffect comparability of financial results between periods. See Exhibit G: Use of Non-GAAP Financial Measures. (2) The Utility incurred costs, net of insurance, of $2.2 billion (before the tax impact of $619 million) and $2.2 billion (before the tax impact of $625 million) during the three and six months ended June 30, 2018, respectively, associated with the Northern California wildfires. This includes accrued charges of $2.5 billion (before the tax impact of $700 million) during the three and six months ended June 30, 2018, related to estimated third-party claims in connection with 14 of the Northern California wildfires. The Utility also recorded $46 million (before the tax impact of $13 million) and $68 million (before the tax impact of $19 million) during the three and six months ended June 30, 2018, respectively for legal and other costs. In addition, the Utility incurred costs of $40 million (before the tax impact of $11 million) during the three and six months ended June 30, 2018 for Utility clean-up and repair costs. These costs were partially offset by $375 million (before the tax impact of $105 million) recorded during the three and six months ended June 30, 2018 for probable insurance recoveries. Three Months Ended Six Months Ended (in millions, pre-tax) June 30, 2018 June 30, 2018 Third-party claims $ 2,500 $ 2,500 Legal and other costs 46 68 Utility clean-up and repair costs 40 40 Insurance recoveries (375) (375) Northern California wildfire- related costs, net of insurance $ 2,211 $ 2,233 (3) 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. 16

Exhibit A: Reconciliation of PG&E Corporation’s Consolidated Income Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) to Non-GAAP Earnings from Operations (4) 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 Butte fire. The Utility incurred charges of $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) Butte fire-related costs, net of insurance $ 10 $ 15 (5) 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. (6) The Utility recorded a disallowance of $47 million (before the tax impact of $15 million) during the three and six months ended June 30, 2017, comprised of cancelled projects of $24 million (before the tax impact of $6 million) and disallowed license renewal costs of $23 million (before the tax impact of $9 million), as a result of the settlement agreement submitted to the CPUC in connection with the Utility’s joint proposal to retire the Diablo Canyon Power Plant. (7) The Utility incurred costs of $3 million (before the tax impact of $1 million) and $7 million (before the tax impact of $3 million) during the three and six months ended June 30, 2017, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications. (8) The Utility incurred costs of $60 million (before the tax impact of $24 million) during the six months ended June 30, 2017, for fines and penalties. This included costs of $32 million (before the tax impact of $13 million) during the six months ended June 30, 2017, associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision (“San Bruno Penalty Decision”) in the gas transmission pipeline investigations. The Utility also recorded $15 million (before the tax impact of $6 million) during the six months ended June 30, 2017, for disallowances imposed by the CPUC in its final phase two decision of the 2015 Gas Transmission and Storage (“GT&S”) rate case for prohibited ex parte communications. In addition, the Utility recorded $12 million (before the tax impact of $5 million) and $1 million (which was not tax deductible) during the six months ended June 30, 2017, for financial remedies in connection with the settlement filed with the CPUC on March 28, 2017, related to the order instituting investigation into compliance with ex parte communication rules. (9) The Utility recorded revenues of $150 million (before the tax impact of $62 million) during the six months ended June 30, 2017 in excess of the 2017 authorized revenue requirement, which included the final component of under-collected revenues retroactive to January 1, 2015, as a result of the CPUC’s final phase two decision in the 2015 GT&S rate case. (10) “Non-GAAP earnings from operations” is a non-GAAP financial measure. See Exhibit G: Use of Non-GAAP Financial Measures. 17

Exhibit B: Key Drivers of PG&E Corporation’s Non-GAAP Earnings per Common Share (“EPS”) from Operations Second Quarter, 2018 vs. 2017 Second Quarter 2018 vs. 2017 Year to Date 2018 vs. 2017 (in millions, except per share amounts) Earnings per Earnings per Common Common Share Share Earnings (Diluted) Earnings (Diluted) 2017 Non-GAAP earnings from operations (1) $ 440 $ 0.86 $ 984 $ 1.92 Timing and duration of nuclear refueling 43 0.08 12 0.02 outages Resolution of regulatory items (2) 29 0.06 29 0.06 Insurance premium cost recoveries (3) 27 0.05 27 0.05 Timing of taxes (4) 26 0.05 1 —Growth in rate base earnings (5) 23 0.04 65 0.12 Miscellaneous 38 0.07 10 0.02 Timing of 2017 GRC cost recovery (6) (18) (0.03) — Decrease in authorized return on equity (7) (7) (0.01) (14) (0.02) Increase in shares outstanding— (0.01) — (0.02) Tax impact of stock compensation (8)—— (44) (0.08) 2018 Non-GAAP earnings from operations (1) $ 601 $ 1.16 $ 1,070 $ 2.07 (1) See Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP EPS from Operations. All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98 percent for 2018 and 40.75 percent for 2017, except for the tax impact of stock compensation. See Footnote 8 below. (2) Represents the impact of various regulatory outcomes during the three and six months ended June 30, 2018. (3) Represents insurance premium costs incurred during the three and six months ended June 30, 2018, above amounts included in authorized revenue requirements, that are probable of recovery as a result of the CPUC’s June 2018 decision authorizing a WEMA. (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 the impact of the increase in rate base authorized in various rate cases, including the 2017 General Rate Case (“GRC”), during the three and six months ended June 30, 2018, as compared to the same period in 2017. The CPUC’s May 2017 final decision in the 2017 GRC delayed recognition of the 2017 revenue increase until the second quarter of 2017, resulting in a smaller revenue increase in the second quarter of 2018 as compared to the first quarter of 2018. (6) Represents incremental revenue recorded in the second quarter of 2017 to recover GRC-related capital costs (depreciation and interest) incurred in the first quarter of 2017. The CPUC approved a final decision in the 2017 GRC on May 11, 2017, delaying recognition of the 2017 revenue increase until the second quarter of 2017. (7) Represents the decrease in return on equity from 10.40 percent in 2017 to 10.25 percent in 2018 as a result of the 2017 CPUC final decision approving an additional extension to the original 2013 Cost of Capital decision. (8) Represents the impact of income taxes related to share-based compensation awards under the Long-Term Incentive Plan that vested during the six months ended June 30, 2018, as compared to the same period in 2017. 18

Exhibit C: Operational Performance Metrics Meets YTD 2018 Performance Results YTD Actual 2018 Target Target (1) Safety Nuclear Operations Diablo Canyon Power Plant (DCPP) Reliability and Safety DCPP Unit 1 Score 96.8 96.4ï DCPP Unit 2 Score 89.9 87.6ï Electric Operations Public Safety Index 1.9 1.0ï Gas and Electric Operations Asset Records Duration Index 1.8 1.0ï Gas Operations Gas In-Line Inspection and Upgrade Index 1.5 1.0ï Gas Dig-ins Reduction 1.55 1.84ï Employee Safety Serious Injuries and Fatalities Corrective Actions Index 1.7 1.0ï Safe Driving Rate See note (2) 6.5 Customer Customer Satisfaction Score 77.5 75.2ï Customer Connection Cycle Time 4 10ï Financial Non-GAAP Earnings from Operations $1,070 See note (1) See note (1) See following page for definitions of the operational performance metrics. The operational performance goals set under the PG&E Corporation 2018 Short-Term Incentive Plan (“STIP”) are based on the same operational metrics and targets. (1) The 2018 target for non-GAAP earnings from operations is not publicly reported. (2) Safe Driving Rate results will be reported on an annual basis. 19

Definitions of 2018 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 three electric programs that evaluate the effectiveness of compliance activities in the Fire Index Areas: (1) Vegetation Non-Exempt Pole Clearing (25%), (2) Routine Line Vegetation Management (50%), and (3) Tree Mortality Mitigation Program (25%). • Gas and Electric Asset Records Duration Indices (equally weighed) – Measure consisting of a weighted index 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: (1) Gas: Transmission (30%), (2) Gas: Station (5%), (3) Gas: Distribution (15%), (4) Electric: Transmission Line (12.5%), (5) Electric: Substation (12.5%) and (6) Electric: Distribution (25%). • Gas In-Line Inspections and Upgrades Index – Index measuring the Utility’s ability to complete planned in-line inspections and pipeline retrofit projects. • Gas Dig-Ins Reduction – Number of third-party dig-ins to the Utility’s gas assets per 1,000 Underground Service Alert tickets. A dig-in refers to any damage (impact or exposure) that result in a repair or replacement of an underground facility as a result of an excavation. 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. • Safe Driving Rate – Measure tracking the total number of alerts for hard braking and hard acceleration per thousand miles driven in company vehicles equipped with in-vehicle performance monitors. Customer Customer satisfaction and service cycle time are measured by: • Customer Satisfaction Score – Overall satisfaction of customers with the products and services offered by the Utility, as measured through an ongoing survey. • Customer Connection Cycle Time – Measure tracking the 12-month average design and construction cycle time for electric residential disconnect/reconnect work requested by the Utility’s customers and performed through Express Connections (the Utility’s new customer gateway), measured in business days. Financial Non-GAAP Earnings from Operations (shown in millions of dollars) represents the non-GAAP financial measure 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. 20

Exhibit D: Pacific Gas and Electric Company Sales and Sources Summary Second Quarter, 2018 vs. 2017 Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Sales from Energy Deliveries (in millions kWh) 18,705 19,216 37,525 38,754 Total Electric Customers at June 30 5,420,082 5,376,949 Total Gas Sales (in Bcf) 169 150 401 377 Total Gas Customers at June 30 4,491,527 4,464,296 Sources of Electric Energy (in millions kWh) Total Utility Generation 7,414 7,205 14,737 15,829 Total Purchased Power 7,333 9,425 13,443 16,716 Total Electric Energy Delivered (1) 18,705 19,216 37,525 38,754 Diablo Canyon Performance Overall Capacity Factor (including refuelings) 99% 66% 88% 82% Refueling Outage Period None 4/23-6/23 2/11 – 3/22 4/23-6/23 Refueling Outage Duration during the Period (days) None 61 39 61 (1) Includes other sources of electric energy totaling 3,958 million kWh and 2,586 million kWh for the three months ended June 30, 2018 and 2017, respectively, and 9,345 million kWh and 6,209 million kWh for the six months ended June 30, 2018 and 2017, respectively. Please see the 2017 Annual Report on Form 10-K for additional information about operating statistics. 21

Exhibit E: PG&E Corporation’s 2018 Items Impacting Comparability (“IIC”) Guidance 2018 IIC Guidance (in millions, after-tax) Low High Estimated Items Impacting Comparability: (1) Pipeline-related expenses (2) $ 43 $ 25 Butte fire-related costs, net of insurance (3) 187 22 Northern California wildfire-related costs, (4) net of insurance 1,613 1,602 2017 insurance premium cost recoveries (5) (23) (23) Estimated IIC Guidance $ 1,820 $ 1,626 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98 percent. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations andaffect comparability of financial results between periods. See Exhibit G: Use of Non-GAAP Financial Measures. (2) “Pipeline-related expenses” includes costs to identify and remove encroachments from transmission pipeline rights-of-way. The pre-tax range of estimated costs is shown below. The offsetting tax impact for the low and high IIC guidance range is $17 million and $10 million, respectively. 2018 (in millions, pre-tax) guidance Low IIC range guidance High IIC range Pipeline-related expenses $ 60 $ 35 (3) “Butte fire-related costs, net of insurance” refers to legal costs and estimated third-party claims associated with the Butte fire, net of contractor insurance recoveries. The pre-tax range of estimated costs shown below includes $7 million of contractor insurance recoveries. Based on the cumulative charges recorded through 2017 of $1.1 billion, the cumulative range for third-party claims is $1.1 billion to $1.3 billion. The total offsetting tax impact for the low and high IIC guidance range is $73 million and $8 million, respectively. 2018 (in millions, pre-tax) guidance Low IIC range guidance High IIC range Legal costs, net of insurance $ 60 $ 30 Third-party claims 200—Butte fire-related costs, net of insurance $ 260 $ 30 (4) “Northern California wildfire-related costs, net of insurance” refers to estimated third-party claims, Utility clean-up and repair costs, and legal and other costs associated with the Northern California wildfires, net of probable insurance recoveries. The pre-tax range of estimated costs shown below includes accrued charges through June 30, 2018 for estimated third-party claims in connection with 14 of the Northern California wildfires. Guidance is consistent with the low end of the estimated range of costs related to such third-party claims. The Utility is currently unable to estimate the high end of the range of costs related to third-party claims. The insurance recoveries estimate is based on an accounting assessment, but the actual timing and amount of insurance recoveries may vary. The total offsetting tax impact for the low and high IIC guidance range is $627 million and $623 million, respectively. 2018 (in millions, pre-tax) guidance Low IIC range guidance High IIC range Third-party claims $ 2,500 $ 2,500 Legal and other costs 160 110 Utility clean up and repair costs 40 40 Insurance recoveries (460) (425) Northern California wildfire-related costs, net of insurance $ 2,240 $ 2,225 22

Exhibit E: PG&E Corporation’s 2018 Items Impacting Comparability (“IIC”) Guidance (5) “2017 insurance premium cost recoveries” includes insurance premium costs incurred in 2017, above amounts included in authorized revenue requirements, that are probable of recovery as a result of the CPUC’s June 2018 decision authorizing a WEMA. The total offsetting tax impact for the low and high IIC guidance range is $9 million. 2018 (in millions, pre-tax) guidance Low IIC range guidance High IIC range 2017 insurance premium cost recoveries $ (32) $ (32) Actual financial results for 2018 may differ materially from the guidance provided. For a discussion of the factors that may affect future results, see the Forward-Looking Statements. 23

Exhibit F: General Earnings Sensitivities for 2018 PG&E Corporation and Pacific Gas and Electric Company Variable Description of Change Estimated 2018 Earnings 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 +/- $0.01 per share Electric Transmission and Gas Transmission and Storage These general earnings sensitivities with respect to factors that may affect 2018 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. 24

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” 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, including Northern California wildfire-related costs, net of insurance, pipeline-related expenses, Butte fire-related costs, net of insurance, 2017 insurance premium cost recovery, Diablo Canyon settlement-related disallowance, legal and regulatory-related expenses, fines and penalties, and 2015 GT&S rate case revenue timing impact. PG&E Corporation uses non-GAAP earnings 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 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 are not a substitute or alternative for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies. 25

Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates 2017 General Rate Case (Phase I) A. 15-09-001 Sep 1, 2015 – Application/Testimony Filed Aug 3, 2016 – Settlement with all parties that filed testimony submitted May, 2017 – Final decision issued Mar 30, 2018 – Petition for Modification filed to reflect 2017 Tax Act reductions in 2018 and 2019 revenue requirements May 8, 2018 – ALJ Ruling ordering advice letter filing to reduce 2017 revenue requirement by $43M Jun 7, 2018 – Compliance advice filing submitted including alternative reduction of $21M 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 2018 – Initial 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 Sep 28, 2017 – FERC accepted TO19 making rates effective Mar 1, 2018, and establishing settlement process Oct 23, 2017 – FERC settlement conference May 2018 – Additional FERC settlement conference Jul 12-13, 2018 – FERC Settlement Conference 2015 Gas Transmission and Storage A.13-12-012 March 30, 2018 – Petition for Modification filed to reflect 2017 Tax Act reductions in 2018 revenue requirement Rate Case 2019 Gas Transmission and Storage A.17-11-009 Nov 17, 2017 – Application filed Rate Case Jan 4, 2018—Prehearing Conference (PHC) Mar 30, 2018—Update testimony filed to reflect 2017 Tax Act reductions in forecasted revenue requirement April 24, 2018 – CPUC to issue ruling on proceeding scope and schedule Jun 29, 2018 – ORA 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 9, 2018 – Evidentiary hearings Nov 2, 2018 – Opening Briefs Dec 7, 2018 – Reply Briefs Safety Culture and Governance Order Instituting I.15-08-019 Sep 2, 2015 – OII issued Investigation Apr 2016 – CPUC hires NorthStar as consultant for investigation May 8, 2017 – President Picker Phase II Scoping Memo and NorthStar Assessment Report Issued Jan 8, 2018 – PG&E Prepared Testimony submitted Feb 16 2018 – Parties Prepared Testimony filed Feb 23, 2018 – PG&E Rebuttal Testimony filed Apr 11, 2018 – Evidentiary Hearings held May 2018 – Opening and Reply Briefs filed 26

Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates 2015 Electric Distribution Resources Plan (DRP) A.15-07-006, Aug 13, 2014 – Commission issues OIR directing utilities to file Electric Distribution Resources Plans R.14-08-013 Jul 1, 2015 – PG&E files Electric Distribution Resources Plan Sep 30, 2015 – Prehearing Conference Aug 2016 – Final Decision on Field Demos C-F Feb 9, 2017 – Decision on Field Demos C and D Feb 27, 2017 – Decision on DER Growth Scenario and Distribution Load Forecasting schedule Apr 19, 2017 – Decision on scope of long–term refinements to ICA and LNBA Jun 15, 2017 – Decision on PG&E’s revised Field Demo D Jun 22, 2017 – Decision requiring IOUs to file assumptions and framework details on DER growth forecasting and disaggregation Late Jul 2017 – Decision on IOU DER Growth Scenarios for distribution planning Oct 6, 2017 – Decision on ICA and LNBA use cases Jan 24, 2018 — amended scoping memo issued Feb 8, 2018 – Decision on Track 3, Sub-track 1 (DER Growth Scenarios) and Sub-track 3 (Distribution Deferral Investment Framework) issues Mar 22, 2018 – Decision adopting requirements for Grid Modernization Plans and process for inclusion within each IOUs GRC Mar 26, 2018 – PG&E submits advice letter 5259-E to close out Demo C Jun 1, 2018 – PG&E filed 2018 Grid Needs Assessment Report Jun 15, 2018 – PG&E submited AL 5314-E to close out Demo D Jun 25, 2018 – PG&E hosted Grid Mod Workshop Catastrophic Event Memorandum Account A. 16-10-019 Oct 31, 2016 – Application filed and testimony served (CEMA) 2016 Dec 5, 2016 – Protests or responses Dec 12, 2016 – Reply to protests or responses Dec 19, 2016 – Prehearing conference Oct 3, 2017 – Intervenor testimony Oct 24, 2017 – Rebuttal testimony Dec 5, 2017 – Opening Briefs Dec 22, 2017 – Reply Briefs Jan 4, 2018 – All Party Settlement Agreement filed May 9, 2018 – Proposed Decision Jun 26, 2018 – Final Decision Catastrophic Event Memorandum Account A. 18-03-015 Mar 30, 2018 – Application filed and testimony served (CEMA) 2018 May 4, 2018 – Protests or Responses May 14, 2018 – Reply to Protests or Responses July 10, 2018 – Prehearing Conference Nov 2018 – Intervenor Testimony Dec 2018 – Rebuttal Testimony Jan 2019 – Settlement Discussions and Hearings Feb 2019 – Opening Briefs Mar 2019 – Reply Briefs Jun 2019 – Final Decision Issued (Proposed timing from Intervenors at PHC—subject to change) 27

Exhibit H: Pacific Gas and Electric Company Expected Timelines of Selected Regulatory Cases Regulatory Case Docket # Key Dates 2017 Integrated Resource Plan / Long Term Procurement R.16-02-007 Feb 11, 2016 – CPUC opens Order Instituting Rulemaking Plan May 26, 2016 – Scoping Memo Issued Aug 11, 2016 – Staff Preliminary Proposal for an Integrated Resource Plan (IRP) Process Issued Sep 19, 2017 – Draft Reference System Plan issued Dec 28, 2017 – Proposed Decision issued Feb 13, 2018 – Decision issued adopting CPUC’s process for IRP Aug 1, 2018 – Load Serving Entities file individual Integrated Resource Plans Aug 7, 2018 – CPUC Workshop where load serving entities (LSE) present key elements of their IRP to stakeholders Aug 2018 – Proposed decision addressing DCPP Joint Parties Petition for Modification of D.18-02-018 Dec 2018 – Ruling and staff proposal issued with proposed Preferred System Plan Jan 2019 – Proposed Decision addressing individual IRPs and PSP Q1 2019 – Decision expected on individual LSE IRPs Integration of Distributed Energy Resources R.14-10-003 Oct 2, 2014 – CPUC opens Order Instituting Rulemaking Apr 4, 2016 – Assigned Commissioner Ruling (ACR) introducing a regulatory incentive proposal for DER deployment Dec 22, 2016 – Final Decision on competitive solicitation framework and regulatory incentive Jul 2017 – filed Advice Letter for DER Incentive Pilot Aug 24, 2017 – Decision adopting an interim Greenhouse Gas (GHG) Adder for use in the avoided cost calculator Dec 19, 2017 – Resolution approving PG&E’s cancellation of IDER incentive pilot due to North Bay location Feb 16, 2018 – Amended Scoping Memo and Ruling to investigate sourcing mechanisms beyond the existing competitive solicitations May 1, 2018 – PG&E filed AL-5096-E-A proposing new location for IDER incentive pilot Jun 22, 2018 – Decision granting in part ORA’s petition for modification of D.16-12-036, for the purpose of preventing double recovery of pilot project costs. Ex Parte Order Instituting Investigation and Order to I.15-11-015 Nov 23, 2015 – OII issued Show Cause Mar 28, 2017 – PG&E, Cities of San Bruno and San Carlos, ORA, SED, and TURN submit joint settlement agreement Sep 1, 2017 – Proposed decision issued adopting settlement agreement with modification Sep 21, 2017 – PG&E files motion accepting modification to settlement and disclosing additional possible ex parte communications Apr 26, 2018 – Revised Decision issued adopting settlement and establishing additonal phase to address remaining issues Jun 21, 2018 – Statutory deadline extended to allow parties to reach settlement on remaining issues Jul 31, 2018 – Next status report to ALJ on settlement discussions Power Charge Indifference Adjustment (PCIA) R.17-06-026 Jul 10, 2017 – OIR issued Apr 2, 2018 – Prepared Testimony Apr 23, 2018 – Reply Testimony May 2018 – Hearings Jun 2018 – Opening and Reply Briefs filed Jul 12, 2018 – Proposed Decision issued Aug 2, 2018 – Oral Argument FERC’s Tax Order to Show Cause EL18-108-000 Mar 15, 2018 – FERC issued the Order to Show Cause ordering PG&E (and other utilities) to respond within 60 days May 14, 2018 – PG&E responded Q3 2018 – FERC in receipt of Comments. Pending further action or decision by FERC Net Energy Metering OIR TBD Jan 2019 – Commission is to issue an OIR 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, 2017. 28