VIA EDGAR

September 15, 2022

Securities and Exchange Commission

Division of Corporation Finance

Washington, D.C. 20549

Attention:    Mr. Gus Rodriguez

Mr. Robert Babula

Re:     PG&E Corporation

Pacific Gas and Electric Company

Form 10-K for the Fiscal Year Ended December 31, 2021

Filed February 10, 2022

Form 10-Q for the Quarterly Period Ended June 30, 2022

Filed July 28, 2022

Item 2.02 Form 8-K filed July 28, 2022

File Nos. 1-12609 and 1-2348

Dear Mr. Rodriguez and Mr. Babula:

This letter sets forth the responses of PG&E Corporation and Pacific Gas and Electric Company (the “Utility”) to the comments set forth in the letter of the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission dated August 31, 2022 with respect to PG&E Corporation and the Utility’s joint Annual Report on Form 10-K for the fiscal year ended December 31, 2021 (the “2021 Form 10-K”), Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022 (the “2022 Second Quarter Form 10-Q”), and the Current Report on Form 8-K filed July 28, 2022.

For your convenience, we have set forth the comment from your letter in italics immediately followed by PG&E Corporation’s and the Utility’s response. Unless otherwise indicated, capitalized terms used herein have the meanings set forth in the 2021 Form 10-K and 2022 Second Quarter Form 10-Q.

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Form 10-K for the Fiscal Year Ended December 31, 2021

Item 1A. Risk Factors, page 38

1.Tell us whether management considered a risk factor on inflation and the impact that higher interest rates and increased costs will have on interest expense, fuel cost and power procurement, and other aspects of your business operations that may be materially impacted by inflation.

Response

PG&E Corporation and the Utility closely monitor the impact of inflation and higher interest rates on their business operations and financial condition, including our commitment to affordable gas and electric service for customers. Management determined that this inflation risk was not material for the periods covered by the 2021 Form 10-K and the 2022 Second Quarter Form 10-Q. Based in part on a forecast of costs developed by IHS Markit,1 which forecast was incorporated into an update to our 2023 General Rate Case (“GRC”) proceeding, we recently determined that the impact of inflation may become material for PG&E Corporation’s and the Utility’s financial conditions, results of operations, liquidity, and cash flows, and disclosed a risk factor related to the impacts of inflation on a Current Report on Form 8-K filed September 6, 2022.

Higher interest rates impact our cost of debt for our existing variable-rate debt and future debt financings. The impact of inflation on our debt is mitigated by the cost of debt that the Utility is authorized to recover through customer rates pursuant to its cost of capital proceedings and the cost of capital adjustment mechanism.

As reflected in the aforementioned GRC update, cost escalation is a standard input for the Utility’s cost of service revenue requirements. Increased fuel and power procurement costs do not impact earnings because the Utility is authorized to pass those costs through directly to customers. As a result, the impact of inflation is primarily an issue of customer affordability. Additionally, the CPUC has approved a “Z Factor” account to track costs associated with exogenous and unforeseen events that are not already contained in an approved revenue requirement and that are largely beyond the Utility’s control but have a material impact on costs after base rates have been authorized for a GRC cycle. For more information, please see page 57 of the 2021 Form 10-K for the risk factor entitled “Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE.”

Inflation impacts our ability to manage costs within the amounts approved in our ratemaking proceedings. We analyze trends in the market and our operating and maintenance costs as part of our regular business practice. We performed that analysis in connection with updating our testimony on September 6, 2022 in the 2023 GRC proceeding. In 2021 and the first half of this year, our spending forecasts were in line with historical margins, but more recently, we have begun to forecast cost increases over the next two years. The impact of inflation on PG&E Corporation and the Utility has been delayed by our earlier entry into multi-year contracts for materials and labor as well as implementation of strategic sourcing strategies to compete for suppliers in the marketplace.

PG&E Corporation and the Utility will continue to monitor the effects of inflation and rising interest rates and evaluate our risk factor disclosure as facts and circumstances develop.

1IHS Markit is part of a business division of S&P Global, Inc.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations, page 68

2.Disclose how management analyzes your nuclear fleet performance between periods, including:

•How you analyze capacity factors;

•Assess refueling outage days; and

•Assess how your nuclear plants are performing.

Refer to Item 303 of Regulation S-K.

Response

As set forth below, we respectfully submit that the requested information is not material. Given that Diablo Canyon represents a small portion of our overall revenues and that Diablo Canyon’s performance has been within historical operating margins, we believe that PG&E Corporation’s and the Utility’s existing disclosures in their annual reports on Form 10-K, quarterly reports on Form 10-Q, and joint proxy statement provide investors with sufficient information as to the performance of Diablo Canyon and risks associated with its operations and decommissioning.

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.

Management analyzes capacity factors by comparing Diablo Canyon’s actual generation to forecasted annual capacity factors, including planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms. Management believes this methodology is within standard nuclear industry practice. The Utility uses this comparison to understand its performance and identify opportunities for improvement.

Management assesses refueling outage days by comparing Diablo Canyon’s actual outage days to the number of planned outage days, which are included in the GRC. The Utility performs an analysis of each outage, which it uses to continually improve its operational performance.

Management’s assessment of Diablo Canyon’s performance includes a daily review of Diablo Canyon’s safety and reliability indicator, which is a composite of 10 performance indicators for nuclear power generation, which were developed by the nuclear industry and apply to all nuclear power plants in the United States, as well as regular review against Nuclear Regulatory Commission regulations and other industry benchmarks. The Utility’s performance against this composite metric is disclosed in the registrants’ joint proxy statement as one of the performance metrics used to determine performance-based compensation. For example, in 2021, the Utility achieved the maximum score on the Diablo Canyon power plant reliability and safety indicator, as disclosed on page 50 of the joint proxy statement. Diablo Canyon’s performance in recent years on these metrics has been within historical margins.

Management analyzes Diablo Canyon’s financial performance primarily through industry group benchmarking in terms of costs and amount of energy generated (i.e., dollars per megawatt-hour generated). This metric also combines costs that are subject to different ratemaking methodologies, which makes it less meaningful for investors. While fuel costs are passed through directly to customers, replacement power costs in connection with outages are subject to CPUC reasonableness review, and base operating and capital costs, including costs to otherwise operate Diablo Canyon, are subject to cost-of-service ratemaking.

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We do not regard performance on these metrics as material, particularly when Diablo Canyon’s performance is within historical margins. As proposed in the 2023 GRC application, Diablo Canyon represents approximately 8% of the Utility’s revenue requirements and 4% of its rate base for 2023, with rate base decreasing to 0% by 2026.2 To the extent there are material costs associated with Diablo Canyon, or the plant’s performance is outside of historical margins, we disclose those changes in the Results of Operations section of our periodic reporting.

3.You recorded $5.4 billion in costs not otherwise being recovered in existing revenue requirements, if any, for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Because rate recovery may require CPUC authorization for these accounts, there is a delay between when the Utility incurs costs and when it may recover those costs. If the amount of the costs recorded in these accounts continues to increase as it has in recent years, the delay between incurring and recovering costs lengthens, or the Utility does not recover the full amount of its costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Please disclose the impact on your financial condition, results of operations, liquidity and cash flows of the $5.4 billion costs not being recovered in existing revenue requirements.

Response

A memorandum account, after approval by the CPUC or upon statutory notice, may be used by a utility to record various expenses it incurs. The utility may later seek authorization from the CPUC to recover the recorded amounts through rates. A balancing account is a deferred debit account carried on the utility’s books.

The balancing account receivables disclosed in Note 4 of the 2021 Form 10-K and Second Quarter 2022 Form 10-Q as current have been authorized for recovery in rates. As of December 31, 2021, of the $5.4 billion in costs not otherwise being recovered in existing revenue requirements, approximately $1.4 billion were current, and $4.0 billion were long term. We record costs to these accounts when we believe they are probable of recovery.

In addition to Note 4, we respectfully refer the Staff to page 73 of the 2021 Form 10-K for the “Liquidity and Financial Resources” section of the Management’s Discussion and Analysis, where we disclose, “The Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets.” In that same section, we also disclose that “PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets.”

2Diablo Canyon Unit 1 and Unit 2 are currently scheduled to be retired in 2024 and 2025 respectively. On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon until 2030. We will include disclosure about extending operations at Diablo Canyon in our 2022 Third Quarter Form 10-Q.

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Costs that are not recovered in revenue requirements impact our liquidity and cash flows. PG&E Corporation and the Utility use our financial resources to finance costs associated with this delay between when we incur costs and when we recover those costs. Increased costs not being recovered through rates could cause us to need to issue additional equity, take on additional debt, or reduce planned dividend payments. If the Utility were unable to recover the costs it has recorded as long-term regulatory assets to a materially greater degree than expected, we would write off the difference between the recorded and recovered amounts as a non-cash disallowance, and such losses would be borne by shareholders. Such a disallowance could cause us to default on our debt obligations or be unable to service our debt. See page 50 of the 2021 Form 10-K for the risk factor entitled “PG&E Corporation’s and the Utility’s substantial indebtedness may adversely affect their financial health and operating flexibility.”

To the extent there are material unrecoverable costs, we disclose those changes in the Regulatory Matters section of our periodic reporting. In future filings, beginning with the 2022 Third Quarter Form 10-Q, we will enhance this disclosure to add the value of the long-term regulatory assets recorded in these accounts and a statement that if the amount of the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. Additionally, we will add a statement that if we were unable to recover our recorded costs, we would write off the difference between the recorded and recovered amounts as a non-cash disallowance.

Operating Revenues, page 69

4.Revise to quantify what effect changes in sales volumes had on your revenues.

Response

CPUC and FERC rates decouple authorized revenue from the volume of electricity and gas sales, so the Utility receives revenue equal to amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and gas sold does not have a material impact on PG&E Corporation’s and the Utility’s financial results. Changes in sales volumes generally change our electric and gas procurement revenues proportionately. However, because changes in sales volumes also increase our procurement costs by a corresponding amount, changes in sales volumes do not materially impact our earnings.

We respectfully refer the Staff to our disclosure on page 17 of the 2021 Form 10-K, where we disclosed the following:

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

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In future filings, beginning with the 2022 Third Quarter Form 10-Q, we will update our disclosure to add a statement that “CPUC and FERC rates decouple authorized revenue from the volume of electricity sales, so the Utility receives revenue equal to amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results.” Other references to sales volumes will be similarly revised or cross-referenced to this revised disclosure.

Note 3: Summary of Significant Accounting Policies

Asset Retirement Obligations, page 119

5.You disclose that you submitted your updated decommissioning cost estimate to the CPUC and correspondingly decreased your ARO liabilities by $1.4 billion. The adjustment was a result of a decrease in estimated costs based on refinements to the site specific decommissioning analysis. Please disclose the estimates and assumptions that led to the revision in estimated cash flows of almost $1.4 billion to your ARO liabilities in 2021. Please also disclose the estimates and assumptions that led to the increase in your ARO liabilities from $5.3 billion at December 31, 2021 to $6.2 billion at June 30, 2022.

Response

Adjustments to the ARO liabilities are generally a result of revisions to cost estimates, including those driven by changes to the scope or methods of planned decommissioning activities, or changes to the anticipated timing of decommissioning work. In the future, beginning with the 2022 Third Quarter Form 10-Q, we will disclose additional information regarding the estimates and assumptions that led to changes in the ARO liabilities at December 31, 2021 and June 30, 2022, as well as in future periods to the extent they are material.

Note 4: Regulatory Assets, Liabilities, and Balancing Accounts, page 127

6.Tell us how you concluded the Wildfire expense memorandum account is probable of recovery. The balance in this account of $440 million as of December 31, 2021 represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Your response should address your consideration of disallowed costs associated with other historical wildfires in which you or other utilities based in California were deemed responsible by a Federal or State agency for causing the wildfire(s) and the doctrine of inverse condemnation that imposes strict liability for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines.

Response

California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking and based on the assumption that utilities have the ability to recover these costs through rates. Under our regulatory construct, the California state legislature and the CPUC has established vehicles for recovery of wildfire-related costs, including costs imposed under the doctrine of inverse condemnation, and the Utility has determined that certain wildfire-related costs related to the 2021 Dixie fire are probable of recovery, as outlined in our Exchange Act reports and as further explained below.

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In June 2018, the CPUC approved the establishment of the Wildfire Expense Memorandum Account (“WEMA”), which provides for tracking for cost-recovery purposes of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered through rates.

There were two WEMA balances at December 31, 2021. The $440 million referenced in the Staff’s comment relates to wildfire insurance premium costs and does not include incremental wildfire claims costs and outside legal expenses (see page 129 of the 2021 Form 10-K). These amounts have been authorized by the CPUC and are currently being collected in rates.

As discussed on page 127 of the 2021 Form 10-K, at December 31, 2021, the other WEMA balance was $347 million, which was classified as a long-term regulatory asset. This balance reflects incremental wildfire claims and outside legal expense costs related to the 2021 Dixie fire. Our response below addresses this balance.

As further disclosed on pages 164 and 166 of the 2021 Form 10-K, for the year ended December 31, 2021, based on information available to PG&E Corporation and the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery through the WEMA, and PG&E Corporation and the Utility recorded a $347 million regulatory asset.

CPUC jurisdictional third-party claims below $1 billion and litigation costs in excess of insurance coverage are eligible for recovery through the WEMA. Costs exceeding $1 billion may be reimbursable from the Wildfire Fund, as described on page 166 of the 2021 Form 10-K. For the quarter ended December 31, 2021, we evaluated whether it was “probable” the CPUC would conclude that the Utility met the prudency standard as adopted in Public Utilities Code § 451.1, effective July 2019, and therefore whether the costs were “probable” of recovery from the CPUC in accordance with ASC 980-340-25-1. As further discussed below, based on our review of applicable law and facts, we determined that the $347 million recorded to the WEMA was probable of recovery when we filed the 2021 Form 10-K and when we filed the 2022 Second Quarter Form 10-Q.

Prior to the enactment of AB 1054, the CPUC had ruled that utilities bore the burden of proving that their conduct was reasonable in order to obtain recovery of costs through rates. The CPUC applied that standard in a 2017 decision regarding the Witch, Guejito, and Rice fires, each of which ignited in 2007. In that ruling, the CPUC denied San Diego Gas & Electric Company’s (“SDG&E”) request for cost recovery, finding that SDG&E had failed to carry its burden of proving that its conduct that led to the ignition of the three wildfires was reasonable.3

3 Press Release, California Public Utilities Commission, CPUC Denies SDG&E’s Request To Recover Wildfire Expenses (Nov. 30, 2017), available at https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M199/K994/199994592.PDF.

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AB 1054 changed the now-applicable standard from the standard in the 2017 SDG&E proceeding in several respects. The law’s legislative history notes that the new standard was intended “to address the calls for more certainty in the cost recovery process in order to restore the regulatory compact.”4 First, under Public Utilities Code §451.1 as amended by AB 1054, the conduct of a utility that has a valid state safety certification for the time period in which a wildfire was ignited is deemed reasonable unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [utility’s] conduct” (emphasis added). Public Utilities Code §451.1(b) defines reasonable conduct as “actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time and based on the information available to the [utility] at the relevant point in time. Reasonable conduct is not limited to the optimum practice, method, or act to the exclusion of others…” The CPUC has not previously applied the “serious doubt” test related to burden shifting in cases involving cost recovery of wildfire liabilities. Second, Public Utilities Code section 451.1, as amended by AB 1054, also states that the CPUC may “allocate” wildfire claims costs for rate recovery “in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The “serious doubt” standard comes from the FERC’s cost recovery standard. The FERC has found serious doubt and that the presumption of reasonableness shifted only where there was evidence, not speculation, of unreasonable or negligent conduct. Under the FERC standard, “one violation by a utility does not necessarily constitute imprudence, as utilities are not expected to be infallible. Instead, the [FERC] looks to things like standard utility practice to determine whether a utility’s conduct was that of a reasonable, prudent utility.”5 In February 2012, the FERC applied the serious doubt standard to claims for recovery made by SDG&E in connection with the Witch, Guejito, and Rice fires. Unlike the CPUC, the FERC approved SDG&E’s application for cost recovery, finding that no serious doubt had been raised regarding the reasonableness of SDG&E’s conduct. The FERC’s decision states that “even if SDG&E had been found to have violated GO-95 [a CPUC rule regarding the design, construction and maintenance of overhead facilities], that alone is insufficient to cast serious doubt on the prudence of the Wildfire Costs.”6 We are not aware of any other instances where the FERC has applied the serious doubt standard to wildfire-related claims and legal costs.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. As of the 2021 Form 10-K filing date, although Cal Fire had stated that it had forwarded a copy of its investigation report on the 2021 Dixie fire to a local District Attorney’s office, PG&E Corporation and the Utility did not have access to the report, nor were we aware of any allegations of code violations in the Cal Fire report. PG&E Corporation and the Utility also did not have access to all of the evidence in the possession of Cal Fire or other third parties.

On June 7, 2022, PG&E Corporation and the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay.

4 Assem. Comm. on Util. and Energy CA A.B. 1054 (NS), CA 2019-2020 Reg. Sess., at 15 (2019).

5 Pacific Gas and Electric Company, 173 F.E.R.C ¶ 61,045 at P 180 (2020).

6 Pacific Gas and Electric Company, 146 F.E.R.C ¶ 63,017 at P 55 (2014).

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The Utility had a safety certification for the time period in which the 2021 Dixie fire ignited, entitling it to the presumption of reasonableness. If serious doubt is raised, the Utility would then have the burden of dispelling that doubt and proving its conduct to have been reasonable. While an intervenor may argue the Cal Fire Investigation Report itself raises serious doubt, we do not believe that the report identifies sufficient factual information to raise serious doubt. If the CPUC were to determine that serious doubt has been raised, then the burden of proof would shift back to the Utility to demonstrate, based on a preponderance of evidence, that its conduct was reasonable.

As we disclosed in the 2022 Second Quarter Form 10-Q, “[b]ased on the information available to the Utility, including its inspection records, operating and inspection protocols, implementation of those protocols, and day-of-event response, the Utility disagrees with the allegations of the Cal Fire Investigation Report and plans to vigorously contest them.” For instance, the subject line was inspected by vegetation management specialists at least eight times in the five years preceding the 2021 Dixie Fire, and the subject tree was not identified as requiring remedial or preventive work (such as trimming or removal). The Utility’s day-of-event response was also in line with its procedures in effect at the time. We continue to believe that the Utility’s conduct was that of a reasonable utility under the applicable recovery standard.

Based on an assessment of facts and the reasonableness standard established by AB 1054, PG&E Corporation and the Utility continue to believe cost recovery of amounts recorded to the WEMA is probable and is therefore properly reflected as a regulatory asset as of December 31, 2021 and June 30, 2022.

Note 15: Other Contingencies and Commitments

Nuclear Fuel Agreements, page 180

7.You rely on a number of international producers of nuclear fuel to diversify sources and provide security of supply. Disclose whether any of your uranium concentrate requirements are supplied by companies located in or affiliated with Russia.

Response

The Utility did not receive any nuclear fuel7 or related services from companies located in or affiliated with Russia in 2021 or 2022 and does not plan to do so prospectively. As a result, we do not regard this information as material.

7 This letter uses the term “nuclear fuel” to refer broadly to all forms of uranium, including uranium concentrates (U3O8), UF6 natural, UF6 enriched, and fabricated fuel assemblies (UO2). It is possible that fabricated fuel assemblies delivered to the Utility contain uranium from a company located in or affiliated with Russia that was supplied by a company other than the Utility to the fuel fabricator because the fuel fabricator treats uranium as fungible.

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Form 10-Q for the Quarterly Period Ended June 30, 2022

Liquidity and Capital Resources, page 20

8.You lowered your new equity capital range for 2022 during your second quarter earnings presentation. Revise your disclosure to describe any known material trends, favorable or unfavorable, in the registrant's capital resources. Refer to Item 303 of Regulation S-K.

Response

We respectfully acknowledge the Staff’s comment and have considered Item 303 of Regulation S-K.

The primary drivers of the lowered new equity capital range for 2022 were: (1) the timing of the SB 901 securitization; and (2) the timing and outcome of settlements or settlements in principle in wildfire and securities litigation matters. Both such drivers were discussed in the registrants’ Second Quarter 2022 Form 10-Q.

In the future, beginning with the 2022 Third Quarter Form 10-Q, we will disclose a range representing the registrants’ projected capital needs. We will also disclose factors that could affect such capital needs, including liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings.

Item 2.02 Form 8-K filed July 28, 2022

Exhibit 99.1

9.You highlight in bold Adjusted GAAP earnings guidance and Non-GAAP Core Earnings guidance per Diluted Share without a corresponding presentation of GAAP amounts. Similarly, your provide a discussion of factors impacting Non-GAAP core earnings without providing a corresponding discussion of factors impacting GAAP earnings. To avoid giving undue prominence to your non-GAAP results, please revise your presentation to present GAAP guidance, results and discussion with equal or greater prominence.

Response

The title of our earnings press release for the second quarter of 2022 was “PG&E Corporation Reports Second-Quarter 2022 Financial Results, on Track for Adjusted GAAP Earnings Guidance of $0.74 to $1.02 per Diluted Share and Reaffirmed Non-GAAP Core Earnings Guidance of $1.07 to $1.13 per Diluted Share” (emphasis added). “GAAP earnings guidance” is a forecast of a GAAP measure. Our intent was to communicate that our earnings guidance, on a GAAP basis, had been updated (that is, “adjusted”), and that we were on track for the guidance as updated. If we use a similar headline in the future, we will refer instead to “updated” GAAP earnings guidance to avoid confusion with non-GAAP terminology.

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Regarding our discussion of factors impacting GAAP and non-GAAP earnings guidance, we respectfully refer the Staff to the discussion of 2022 GAAP earnings guidance in the press release, which appeared before the discussion of non-GAAP earnings guidance and said “costs related to the amortization of Wildfire Fund contributions under AB 1054, PG&E Corporation’s and the Utility’s reorganization cases under Chapter 11, wildfire-related costs, investigation remedies, and strategic repositioning costs, partially offset by rate neutral (SB 901) securitization and Fire Victim Trust tax benefits and prior period net regulatory impact.” In the future, beginning with the earnings press release for the third quarter of 2022, we will revise this language to give equal or greater prominence to our GAAP guidance.

10.The Wildfire Fund is available to the Company to pay eligible claims for liabilities arising from wildfires and serves as an alternative to traditional insurance products. In addition, you disclose that the impact of wildfires is a key factor affecting financial results in your MD&A and you recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. Tell us why adjusting for the amortization of the Wildfire Fund contribution as a Non-core Item in computing Non-GAAP Core Earnings is meaningful to investors in light of your MD&A disclosures and the probable recoveries under the Wildfire Fund.

Response

PG&E Corporation and the Utility have classified the Wildfire Fund contribution as a Non-core Item to enable investors to better evaluate our core operating results.

As disclosed on pages 122 and 123 of the 2021 Form 10-K, the accounting treatment of the Wildfire Fund contribution is that the asset will be amortized on a straight-line basis over the estimated useful life of the Wildfire Fund. When we determine it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire, the amortization will be accelerated, driven by the expectation that the funds available for coverage will be reduced. Each such determination would result in a reduction to the Wildfire Fund asset and be recognized as incremental amortization. For instance, as disclosed on page 70 of the 2021 Form 10-K, when the Utility recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire, the Utility also recorded $43 million of accelerated amortization of the Wildfire Fund contribution. The amortization of contributions to the Wildfire Fund has otherwise been on a straight-line basis to date.

Because other California utilities also participate in the Wildfire Fund, there could be material accelerations of amortization of the Utility’s asset that are unrelated to the Utility’s operations. As a result, there could be material amortization of the Wildfire Fund asset that is independent of our core operating results and so classifying the Wildfire Fund contribution as a Non-core Item improves the comparability of Non-GAAP Core Earnings between periods. Additionally, as disclosed on page 94 of the 2021 Form 10-K, the Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. PG&E Corporation and the Utility have made three of the 10 annual contributions. Because only seven annual contributions remain, we do not regard the Wildfire Fund contributions as normal, recurring, cash operating expenses.

* * *

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We appreciate the Staff’s thoughtful review and are committed to transparent, quality disclosure. We hope that the foregoing has been responsive to the Staff’s comments. If you have any questions or desire further information, please do not hesitate to contact me.

Sincerely,

/s/ Christopher A. Foster

Christopher A. Foster

Executive Vice President and Chief Financial Officer

PG&E Corporation

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