PCGPG&E Corporation

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.

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.

Rest of the answer

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.

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

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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.

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

Rest of the answer

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.

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.

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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.

Rest of the question

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.

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.

Rest of the answer

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.”

2 Diablo 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.

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.

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

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.

Rest of the answer

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.

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.

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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 sitespecific decommissioning analysis.

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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.

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. Read in the reply ↗

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.

Rest of the question

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.

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.

Rest of the answer

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.

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.

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).

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.

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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.

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).

Rest of the answer

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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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. Exhibit 99.1

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.

Rest of the answer

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.

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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.

Rest of the question

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.

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.

Rest of the answer

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.

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.

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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.

Rest of the question

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.

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.

Rest of the answer

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 have read your response to comment 2 and your statement, "On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon until 2030." Additionally, the 8% revenue requirement associated with Diablo Canyon does not appear insignificant. Revise your disclosure to discuss and analyze the capacity factors of your nuclear power facilities.

In future filings, beginning with the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2022 (the “2022 Third Quarter Form 10-Q”), we will update our disclosure to add a statement discussing and analyzing the capacity factors of Diablo Canyon, substantially in the following form.

Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon’s generation to the

California electricity market.

Rest of the answer

Management analyzes capacity factors by comparing Diablo Canyon’s actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms. Capacity factors do not currently impact PG&E Corporation’s and the Utility’s results of operations, except to the extent requested cost recovery is denied because the costs are found to be imprudently incurred.

Apart from cost-of-service ratemaking and beginning on September 2, 2022, the Utility is entitled to receive a monthly performance-based disbursement. (See “Senate Bill 846”).

The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility’s wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the year ended December 31, 2021, and the nine months ended September 30, 2022, Diablo Canyon achieved an average capacity factor of 84% and 94%, respectively. As previously disclosed, Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibration.

In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to ensure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

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We have read your response to comment 6. FASB ASC 980-340-25-1 requires a rateregulated utility to capitalize as a regulatory asset an incurred cost that would otherwise be charged to expense if future recovery in rates is probable.

Rest of the question

Probable is defined in FASB ASC 450-20-20, as “likely to occur.” A rate-regulated utility has a continuous probability standard to be met at each balance sheet date for a regulatory asset to remain recorded. The Cal Fire report determined in their conclusion that your prolonged response to the initial outage and fault was a direct and negligent factor in the ignition of the Dixie Fire. The Cal Fire report also indicates that the tree that caused the Dixie Fire should have been discovered and removed between the years 2008 and 2021. This report was publicly available prior to your filing the June 30, 2022 Form 10-Q report. Since the Cal Fire report raises “serious doubt” with respect to your conduct, tell us in detail the following: • Why you do not believe that the Cal Fire report identifies sufficient factual information to raise "serious doubt"; • How you concluded it was probable the CPUC would conclude the Utility met the prudency standard; and • Why you believe the $347 million in costs related to this fire are probable of recovery as of June 30, 2022.

We believe the costs are probable of recovery because the Utility acted prudently by following its procedures. Our belief that the Utility followed its procedures is informed by a detailed factual investigation, which rebuts the allegations in the Cal Fire Investigation Report. Based on our disagreement with the report’s allegations, we do not think it identifies facts sufficient to create serious doubt if that issue is later raised in a proceeding to consider the matter.

Accounting Standard

Consistent with ASC 980-340-25-1, the Utility capitalizes as a regulatory asset an incurred cost

Rest of the answer

that would otherwise be charged to expense if future recovery in rates is probable, and the amount of the recovery is reasonably estimable. Consistent with FASB Statement No. 114, paragraph 49, we do not interpret “probable” to mean “virtually certain to occur.” Instead, probability determinations in practice, require significant judgment. PG&E Corporation and the Utility interpret “probable” as at least 80% likely.

In evaluating probability, we consider a range of relevant factors, such as the regulatory principles and precedents established by law, including whether recovery of similar costs has been allowed by the regulator or, in the absence of precedent from the regulator, other similar regulators applying a similar standard, as well as the particular facts of the incurred costs under consideration. Here, based on a detailed analysis of the law and the facts associated with recovery of the $347 million in costs related to the 2021 Dixie fire, we concluded that recovery of those costs is probable.

Revised Prudency Standard

As discussed in our prior letter, 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. AB

1054 adopted a revised prudency standard intended to increase certainty of cost recovery for wildfires.1 AB 1054 states that a utility with a safety certification “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire, so any analysis of cost recovery must start with this presumption.

1 Cal. Assemb. Util. and Energy Bill Analysis, Cal. A.B. 1054, at 12 (July 9, 2019) (available for download at https://leginfo.legislature.ca.gov/faces/billAnalysisClient.xhtml?bill_id=201920200AB1054).

As a point of clarification, the Cal Fire Investigation Report has not, by its issuance, created serious doubt. Procedurally, AB 1054 requires “serious doubt” to be raised by a party to the proceeding in which the

Utility seeks recovery for 2021 Dixie fire costs. The Utility has not yet submitted such an application, and no such proceeding exists. In any event, Cal Fire has not participated as a party in any of the Utility’s cost recovery proceedings in the past and is not expected to do so.

The are no decisions at the CPUC implementing the AB 1054 cost recovery standard. In the absence of direct precedent, it is instructive to review the FERC’s implementation of the “serious doubt” standard, which, according to legislative history, was the basis of and model for the AB 1054.

The most relevant precedent is San Diego Gas & Electric Company’s (“SDG&E”) requests for cost recovery in connection with the Witch, Guejito, and Rice fires. Where the CPUC denied SDG&E’s request for cost recovery under the standard in place before AB 1054, the FERC approved the request. In that decision, the FERC said that its “presumption of prudence is not easily refuted.”2 The FERC stated: “one violation by a utility does not necessarily constitute imprudence, as utilities are not expected to be infallible. Instead, the Commission looks to things like standard utility practice to determine whether the utility’s conduct was that of a reasonable, prudent utility.”3

In another case, the FERC found no “serious doubt” had been raised in the CPUC’s challenge to the prudence of costs associated with the Utility’s Embarcadero-Potrero Project. The FERC noted CPUC concerns about the cost overruns as compared to the initial forecast in the CPUC’s proceeding, but stated “any mistakes made by PG&E in developing this significant transmission project do not constitute the kind of mismanagement that should raise serious doubts about the prudency of their expenditures.”4 One finding of a mistake is generally not sufficient to create serious doubt.

Factual Investigation

We similarly do not believe that the facts alleged by the Cal Fire Investigation Report would create serious doubt if raised by a party to the proceeding because, as described below, our investigation of the facts indicates that the Utility’s personnel followed approved processes and procedures at each relevant point, and its equipment worked as designed. The Utility’s personnel followed approved processes and procedures before ignition by inspecting the distribution line according to vegetation management standards and on the day of the event by responding appropriately based on the facts and circumstances known at each relevant time. By following approved processes and procedures, the Utility acted reasonably.

Records show that the Utility’s contractors inspected the Bucks Creek 1101 distribution line prior to the Dixie Fire according to applicable vegetation management standards. The line was inspected at least eight times between 2016 and 2021, and trees were identified for work. The contractor who inspected the area in the most recent inspection before the fire has stated in a federal court filing that his inspection met industry standards.

2 El Paso Nat. Gas Co., 146 FERC ¶ 63,017, ¶ 57 at 15 (2014).

3 Id. ¶ 56 at 14.

4 Pac. Gas and Elec. Co., 173 FERC ¶ 61,045, ¶ 180 at 86 (2020).

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PG&E Corporation and the Utility have requested confidential treatment for the redacted portion under Rule 83 of the SEC’s Rules of Practice and have delivered a complete unredacted copy of the letter to its examiner at the Division of Corporation Finance.

As to the Utility’s day-of-event response to the Cresta Dam outage that preceded the fire, the Utility’s personnel followed the procedures and priorities that were in place for response time to an outage based on the facts and circumstances known to the Utility at the time. In particular:

The outage recorded on the morning of July 14, 2021 was categorized as a “priority 1” response, which required a same-day response under company policy. The Utility required faster response times for emergency situations, but a power outage by itself is a not uncommon occurrence. Here, there was no reported emergency.

The two Utility employees who responded to the Cresta Dam location that day both looked up the line from the vantage point of Cresta Dam, and neither reported any immediate hazard or indication of fire. There is no evidence on the multiple recorded calls during the day discussing the response to this outage that any employee saw or suspected that a tree had fallen on the line until the troubleman was able to arrive to the site.

The troubleman worked to proceed from Cresta Dam towards the site of the fuse consistent with policy. When the troubleman arrived on the scene and observed the tree on the line and a fire, he immediately de-energized the conductor that was still energized, called the matter in on his radio, and stayed on the site to fight the fire on his own.

The company believes that employees also acted reasonably in not de-energizing the lines in the absence of facts and circumstances suggesting that the outage was the result of or created a hazard. Distribution Systems

Operators (“DSOs”) have authority to de-energize lines if appropriate for safety reasons. Here, the DSO considered de-energizing but decided not to do so, given the data recorded and facts known at the time. Here, as soon as the troubleman saw a safety issue, when he arrived at the pole, he immediately de-energized the line.

Finally, the evidence indicates that the protective equipment on the Bucks Creek 1101 line operated as designed. The fuses on the pole immediately adjacent to where the tree touched the line operated by opening in response to a phase-to-phase fault, and the thresholds for triggering the recloser, located at the substation, were not met here.

As an additional consideration, AB 1054 states that the CPUC may allocate costs and expenses in the application for cost 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. We evaluated whether, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. In this case, we believe a number of factors beyond the Utility’s control may have contributed to the 2021 Dixie fire’s ignition and spread, including climate change and extreme drought; forest management practices by third parties such as the United States Forest

Service and timber companies; Cal Fire’s response; a drone that halted Cal Fire’s initial air response, for which the operator’s identity is under investigation but for which we are aware of no evidence that the drone was operated by or on behalf of the Utility; and an individual arsonist arrested for starting small fires in the 2021 Dixie fire’s footprint, apparently seeking to trap firefighters.

Probability Determination

For these reasons, we believe that the Utility’s personnel followed its processes and procedures, and its equipment worked as designed. These processes and procedures were discussed in the Utility’s Wildfire

Mitigation Plan, which was approved by the Office of Energy Infrastructure Safety (“OEIS”). The CPUC then ratified OEIS’s approval. Because OEIS approved the WMP, and the CPUC ratified the approval, we concluded that the CPUC will probably find that the Utility acted prudently under applicable standards, including if the burden is shifted. The allegations in the Cal Fire Investigation Report do not change this conclusion.

This conclusion was further supported by law enforcement authorities’ decision not to pursue criminal charges. Cal Fire’s primary responsibility is the prevention of wildfires, and it is not a law enforcement agency.

After Cal Fire provided its report to the district attorneys of the five impacted counties, the district attorneys decided not to pursue criminal charges and settled the matter without PG&E Corporation or the Utility admitting liability, suggesting that the district attorneys similarly did not view the Cal Fire Investigation Report as evidence of criminal conduct. Because we disagree with the Cal Fire Investigation Report’s allegations, and the district attorneys who reviewed the report did not find it compelling for criminal charges, we believe that even if an intervenor in a future cost recovery proceeding were to argue that the report identifies sufficient facts to create serious doubt, the CPUC would not find that serious doubt had been created.

Probability determinations are a matter of management’s judgment. Here, we believe that our determination that these costs were probable of recovery was made thoughtfully and carefully. Our review included extensive discussions with PG&E Corporation’s internal legal counsel, external legal counsel, outside auditors, as well as a special meeting of the Audit Committees of the Board of Directors. Based on this analysis of the law and the facts, PG&E

Corporation and the Utility continue to believe it is probable that the Utility will recover its costs in connection with the 2021 Dixie fire.

In future filings, beginning with the 2022 Third Quarter Form 10-Q, we will enhance this disclosure with more detailed discussion of the factors that could cause the Utility to be unable to recover these costs.

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We have read your response to comment 10. The remaining annual contributions the Company is required to make to the Wildfire fund appear to represent normal, recurring, cash operating expenses necessary to operate your business.

Rest of the question

Given the nature of these costs and the periods for which they are expected to continue in the future, explain to us why you believe the adjustment to remove these costs is consistent with Compliance and Disclosure Interpretation 100.01.

We believe the adjustment to remove the expense to amortize the Wildfire Fund asset is consistent with Compliance and Disclosure Interpretation 100.01 (“Non-GAAP C&DI 100.01”) because the amortization expenses are not expected to be normal and recurring, are not cash expenses, are not operating expenses, and are not necessary to operate our business.

Rest of the answer

And consistent with Rule 100(b) of Regulation G, we believe the adjustment is not misleading – and is in fact helpful to investors – because it improves comparability and is presented clearly.

The Wildfire Fund Asset

The expense we adjust for as a Non-core Item in computing Non-GAAP Core Earnings is the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability, not the payment of the annual contributions, including any remaining contributions. We respectfully refer the Staff to page 94 of the 2021 Form 10-K, where we disclosed:

As of December 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in current assets – Wildfire fund asset, and $5.3 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2021 and 2020, the Utility recorded amortization and accretion expense of $517 million and $413 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund.

The Wildfire Fund asset reflects the initial value of the asset, which was the present value of all expected contributions at the time the asset was recorded (including the future annual contributions of $193 million), net of amortization. As a result, the Wildfire Fund asset bears only an indirect relationship to the annual contributions, insofar as the then-present value of each year’s contribution affected the initial value of the asset. As described in the disclosure, PG&E Corporation and the Utility also have recorded a payable to the Wildfire Fund, in Other current and Other non-current liabilities, related to the future annual contributions. As PG&E Corporation and the Utility make those future contributions, the payable is reduced with no impact to net income.

This accounting treatment is consistent with the treatment proposed in our letter seeking the Staff’s pre-clearance dated September 6, 2019.

The Adjustment Complies with Non-GAAP C&DI 100.01

Taking into account our accounting of Wildfire Fund arrangements, we analyze each of the elements of Non-GAAP C&DI 100.01, and then the principles underlying it, in turn.

First, the amortization expenses in respect of the Wildfire Fund asset are not expected to be normal and recurring because acceleration will result in anomalous charges. As explained in our prior response and the preclearance letter, while the amortization of the Wildfire Fund asset has primarily been on a straight-line basis to date, it is not expected to remain that way because of the likelihood of a participating utility’s catastrophic wildfire and subsequent claim on the Wildfire Fund at some point over the life of the fund. Although the Wildfire Fund asset is initially amortized on a straight-line basis based on the estimated useful life of the fund, the amortization is accelerated based on the application of the with-and-without method. Under the with-and-without method, amortization of an asset is accelerated when a decrease in the assets available in the Wildfire Fund causes the fund’s expected coverage to decline. This acceleration will occur when the Utility or another participating utility records a probable recovery from the Wildfire Fund. A Participating utility may recover from the Wildfire Fund only to the extent the amount of its incurred losses exceeds $1.0 billion in any coverage year. The Wildfire Fund was created based on the expectation that a catastrophic wildfire is likely to occur in the near future, but it is not predictable when or where. These catastrophic wildfires – causing more than $1 billion in damages but unpredictable – are always anomalous events. If the equipment of the Utility or another participating utility is the substantial cause of a catastrophic wildfire, and the utility recognizes a liability for a claim eligible for recovery from the Wildfire Fund, amortization of the asset would be accelerated. The amount of amortization expense that PG&E Corporation and the Utility would incur is determined based on the Utility’s contribution to the Wildfire Fund and the percentage change in the amount of available funds in Wildfire Fund. Because the Utility’s contribution was so large, even a small change in the percentage of amount of available funds could result in a material amortization expense. In this way, an anomalous event could cause us to incur a material amortization expense. We do not interpret “normal and recurring” to include amortization with a material, unpredictable amount of acceleration based on anomalous events.

Second, as discussed above, the expense we adjust for as a Non-core Item in computing Non-GAAP Core Earnings is the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability.

Amortization and accretion are not cash expenses.

Third, amortization of the Wildfire Fund asset is not an operating expense because part of its benefit for PG&E Corporation and the Utility is as a financial risk management product. As long as the Wildfire Fund has available funds, we can draw from the Wildfire Fund for incurred losses above $1.0 billion. But if we draw from the Wildfire Fund and our costs are determined by the CPUC not to be just and reasonable, we will be required to reimburse the

Wildfire Fund, subject to a disallowance cap of $3.0 billion based on the Utility’s 2022 equity base. The Wildfire Fund, then, would be available to address liquidity and cash flow challenges resulting from a catastrophic wildfire, even if the public markets were not. If we were required to reimburse the Wildfire Fund, the cost recovery proceedings would give the companies time to stabilize and raise funds from the public markets. Because we could be required to reimburse the Wildfire

Fund, much of the Wildfire Fund’s benefit is to give us time to raise funds from the public markets. A product that helps address a liquidity and cash flow problem in this way is managing financial risk more than operational risk, and so the costs to use that tool are not operating expenses.

Fourth, amortization of the Wildfire Fund asset is not necessary to operate our business because the Wildfire Fund was created to fulfill a State policy goal. It is not necessary to operate our business because its primary beneficiary is California residents, not PG&E Corporation and the Utility. The Wildfire Fund is not necessary to operate our business because it is essentially for customers and fire victims. The

California legislature created the fund to ensure that residents impacted by catastrophic wildfires would receive compensation.5

Condemnation, also called eminent domain, is the right of a government or its agent to take private property for public use, with compensation. In California, inverse condemnation imposes strict liability on a utility whose electrical equipment is found to be the substantial cause of a catastrophic wildfire. It is intended to spread losses from a public-use undertaking across the community that benefited from the undertaking based on the assumption that utilities have the ability to recover these costs through rates. But when the CPUC denied cost recovery for catastrophic wildfires, inverse condemnation had the unintended effect of making the investor-owned utilities (“IOUs”) solely responsible for the financial costs of catastrophic wildfires. In this way, the application of inverse condemnation to catastrophic wildfires interfered with the financial stability of the IOUs and jeopardized their ability to make the payments required under inverse condemnation without substantial rate increases. Recognizing this risk, the California legislature authorized the Wildfire Fund as part of a set of actions to preserve the financial stability of utilities and ensure the affordability of electric services for customers.6 These actions sought to maintain inverse condemnation’s loss-spreading feature without threatening the IOUs’ ability to compensate customers for wildfire-related losses or imposing significantly higher rates on customers.7 The contributions to the Wildfire Fund made by the IOUs, including the Utility support that loss-spreading process by enabling payments for catastrophic wildfires. Therefore, in making those payments, the IOUs carry out public policy on behalf of the government. In fact, half of the Wildfire Fund’s assets are funded by surcharges on the IOUs’ customers, which operate like taxes. Because the IOUs’ contributions to the Wildfire Fund enable their quasi-governmental, public benefit function as a financial backstop for California residents impacted by catastrophic wildfires, the Utility’s expenses from participating in the fund are not necessary to operate the Utility’s business.

5 See Cal. S. Energy, Util. and Comm. Bill Analysis, Cal. A.B. 1054, at 12-15 (July 8, 2019) (available for download at https://leginfo.legislature.ca.gov/faces/billAnalysisClient.xhtml?bill_id=201920200AB1054).

6 Id. at 10.

7 Cal. Assemb. Util. and Energy Bill Analysis, Cal. A.B. 1054, at 15 (July 9, 2019) (available for download at https://leginfo.legislature.ca.gov/faces/billAnalysisClient.xhtml?bill_id=201920200AB1054).

Additionally, the IOUs each opted in to participating in the Wildfire Fund. An expense is not necessary to operate our business if participation is voluntary.

Moreover, amortization of the Wildfire Fund asset is not an operating expense necessary to operate our business because the amortization may be accelerated if another participating utility records a probable recovery from the Wildfire Fund. Expenses resulting from other utilities’ operations are unrelated to our operations and not necessary to operate our business. For instance, if as of September 30, 2022, Southern California Edison or SDG&E incurred losses of $3 billion arising out of a catastrophic wildfire for which its electrical equipment was the substantial cause, PG&E Corporation and the Utility would incur approximately $534 million of amortization acceleration. In this way, PG&E

Corporation and the Utility could incur a material loss on a GAAP basis without being the utility involved in a wildfire’s ignition.

The Adjustment is not Misleading

More broadly, this adjustment follows the principles behind Non-GAAP C&DI 100.01 because it is not misleading. Non-GAAP C&DI 100.01 refers to Rule 100(b) of Regulation G, which prohibits making “public a non-GAAP financial measure that, taken together with the information accompanying that measure and other accompanying discussion of that measure … omits to state a material fact necessary in order to make the presentation of the non-GAAP financial measure, in light of the circumstances under which it is presented, not misleading.”

Here, the adjustment is not misleading because it helps investors evaluate our core operating performance, and amortization of the Wildfire Fund asset is presented clearly.

We believe the adjustment helps investors evaluate our core operating performance because it improves comparability across the industry, against the other California IOUs, and relative to PG&E Corporation’s and the

Utility’s past and future performance. The adjustment helps investors assess our core operating performance across the industry because investors can compare our earnings results to those of our industry peers whose GAAP earnings are not impacted by the Wildfire Fund innovation.

Adjusting for the amortization of the Wildfire Fund asset also improves comparability with the other California IOUs. As discussed above, if one of the other participating utilities experienced a catastrophic wildfire,

PG&E Corporation and the Utility would incur accelerated amortization expense without receiving any funds from the Wildfire Fund. And if the Utility’s equipment is the substantial cause of a catastrophic wildfire, the amount of amortization acceleration would be less than the Utility’s probable recovery from the Wildfire Fund. For instance, when the Utility recorded a probable recovery from the Wildfire Fund of $150 million, it recorded $43 million of accelerated amortization. In either case, the amount of the Utility’s amortization expense would not match its recovery from the Wildfire Fund. This dynamic distorts the California IOUs’ performance relative to one another. By adjusting for this amortization, we enable investors to understand this dynamic.

Additionally, the adjustment improves comparability against PG&E Corporation’s and the Utility’s past and future performance because the Wildfire Fund has a limited lifespan. The adjustment enables investors to compare our core operating performance from before the Wildfire Fund, during the life of the Wildfire Fund, and after the Wildfire Fund is exhausted. During the life of the Wildfire Fund, the adjustment facilitates comparisons by adjusting for expenses that may be recorded in a different period from when they were incurred (for instance, due to the time necessary to resolve litigation). In our experience, several years can pass between a wildfire’s ignition and when probable losses become reasonably estimable. Because the amortization expense would be recorded when the losses become reasonably estimable, the amortization expense does not reflect our core operating performance for the period in which it is recorded. Adjusting for losses recorded after they are incurred improves investors’ ability to compare our core operating performance from one period to another. In each of these ways, because adjusting for these costs is helpful for investors, we do not believe the adjustment is misleading.

Lastly, we submit that the adjustment is not misleading because it is presented clearly. The Wildfire Fund asset is disclosed in detail in our filed reports, and the adjustment is separately disclosed and described in our furnished materials. In PG&E Corporation’s and the Utility’s periodic reports, we disclose the structure, potential benefits, and associated costs and risks of the Wildfire Fund comprehensively and prominently. In our furnished earnings materials, several slides further explain the Wildfire Fund and its impact on PG&E Corporation and the Utility for investors. In particular, each time the amortization of the Wildfire Fund asset is disclosed, it is separately identified as its own line item and described each time core earnings or guidance is presented. In the earnings presentation for each quarter, amortization of the Wildfire Fund asset is a separate line item in the non-GAAP reconciliation for both earnings (Exhibit A) and guidance (Exhibit C). Separately presenting this adjustment enables investors to perform their own calculations if they do not find the adjustment to be helpful.

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