Pacific Gas & Electric (PCG+A) 10-Q2023 Q2 Quarterly report

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “commit,” “goal,” “target,” “will,” “may,” “should,” “would,” “could,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors in the 2022 Form 10-K and a detailed discussion of these matters contained in Item 7. MD&A in the 2022 Form 10-K and Item 2. in this Form 10-Q. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors, including regarding dividends, at http://investor.pgecorp.com, under the “Wildfire and Safety Updates,” “News & Events: Events & Presentations,” and “Shareholders: Dividend Information” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident to the CPUC. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the 2022 Form 10-K entitled “Risk Factors” and the section of this quarterly report entitled “Forward-Looking Statements.”

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Item 1. It should also be read in conjunction with the 2022 Form 10-K.

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors in the 2022 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $26.6 billion and a California net operating loss carryforward of approximately $25.2 billion as of December 31, 2022.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding deferred tax asset as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. On each of January 9, 2023, April 11, 2023, and July 12, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the six months ended June 30, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 120,000,000 shares resulted in an aggregate tax benefit of $527 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Cumulatively through June 30, 2023, the Fire Victim Trust has sold 350,000,000 shares resulting in an aggregate tax benefit of approximately $1.4 billion recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,568,984,928 shares outstanding as of July 19, 2023, only 2,023,497,748 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility, and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of July 19, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of July 19, 2023 was 3.74% of the outstanding shares. As of July 19, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 410,000,000 shares of PG&E Corporation common stock in the aggregate and owned 67,743,590 shares.

PG&E Corporation’s net loss primarily consists of interest expense on long-term debt.

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2023 and 2022.  The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base.  Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results.

The following discussion presents the Utility’s operating results for the three and six months ended June 30, 2023 and 2022, focusing on revenues and expenses that impacted earnings for these periods.

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $206 million, or 6%, in the three months ended June 30, 2023, compared to the same period in 2022, primarily due to additional revenues as authorized through the FERC formula rate and other miscellaneous revenues in the three months ended June 30, 2023 as compared to the same period in 2022.

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $424 million, or 6%, in the six months ended June 30, 2023, compared to the same period in 2022, primarily due to the recognition of approximately $585 million in revenues authorized in the final decision of the 2020 WMCE application (see “2020 WMCE Application” below) in the six months ended June 30, 2023, with no comparable revenues in 2022. Additionally, the Utility recognized increased revenues as authorized through the FERC formula rate. These increases were partially offset by the recognition of approximately $310 million in revenues related to the approval of the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in the six months ended June 30, 2022 with no comparable revenues in 2023.

SB 901 securitization charges, net, that impacted earnings increased by $249 million, or 623%, and $522 million, or 1305%, in the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022. In the three and six months ended June 30, 2023, the Utility recorded charges of $289 million and $562 million, respectively, representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock, compared to charges of $40 million in the same periods in 2022. For more information, see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Costs related to wildfires that impacted earnings decreased by $146 million, or 100%, and $147 million, or 100%, in the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022. The Utility recognized pre-tax charges of $150 million related to the 2019 Kincade fire in the second quarter of 2022, with no comparable charges in 2023.

There was no material change to Wildfire Fund expense that impacted earnings for the periods presented.

Interest income that impacted earnings increased by $120 million, or 600%, and $221 million, or 762%, in the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022, primarily due to higher interest rates earned on regulatory balancing accounts.

Interest expense that impacted earnings increased by $200 million, or 57%, and $356 million, or 50%, in the three and six months ended June 30, 2023, respectively, compared to the same period in 2022, primarily due to the issuance of additional long-term debt and an increase in interest rates on variable-rate debt.

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs.  See below for more information.

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred. If the Utility were to spend more than authorized amounts, these expenses could have an impact on earnings.

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

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. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.

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.

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions.

The Utility’s annual cost of capital adjustment mechanism provides that in any year during the applicable cost of capital period in which the difference between (i) the average Moody’s Baa utility bond rates (as measured in the 12-month period from October of the prior year through September of the year in which the mechanism could trigger (the “Index”)) and (ii) 4.37% (based on the 2023 Cost of Capital decision) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism is triggered, to become effective on January 1 of the next year. As of July 19, 2023, for the period since October 1, 2022, the Index averaged 135 basis points above the Utility’s cost of capital benchmark rate of 4.37%.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

The Utility continues to experience increased arrearages as a result of the COVID-19 pandemic. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, an annual cap set by the CPUC on the number of service disconnections for residential customers, and the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections.” The Utility’s accounts receivable balances over 30 days outstanding as of June 30, 2023 were approximately $923 million, or $199 million lower than the balance as of December 31, 2022 and $691 million higher than the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic.

As of June 30, 2023, PG&E Corporation and the Utility had access to approximately $5.0 billion of total liquidity comprised of approximately $545 million of Utility cash, $260 million of PG&E Corporation cash and $4.2 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

The Utility established the CPPMA for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of June 30, 2023, costs recorded to the CPPMA totaled $18 million and were reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $18 million recorded to the CPPMA, the Utility recorded approximately $228 million of under-collections from residential customers from January 1, 2023 to June 30, 2023 to the RUBA, which is expected to be recovered in 2024 and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets.

The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term and short-term debt. PG&E Corporation and the Utility are also pursuing the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets” below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation of an amount equal to the net proceeds from this offering to finance or refinance eligible projects, the Utility expects to use the net proceeds for the repayment of borrowings outstanding under the Utility Revolving Credit Agreement.

On June 5, 2023, the Utility completed the sale of (i) $850 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.15 billion aggregate principal amount of 6.400% First Mortgage Bonds due 2033, and (iii) $500 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of $375 million aggregate principal amount of 3.25% First Mortgage Bonds due June 15, 2023 and for general purposes, including for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility intends to use the remaining net proceeds to repay the $500 million aggregate principal amount of 4.25% First Mortgage Bonds due August 1, 2023.

As of June 30, 2023, PG&E Corporation and the Utility had $500 million and $3.7 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

On April 18, 2023, the Utility amended its existing term loan agreement to extend the maturity of the $125 million 364-day tranche loan thereunder from April 19, 2023 to April 16, 2024. The 364-day tranche loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375%, or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 9, 2023, the Utility entered into an amendment to the Utility Receivables Securitization Program to, among other things, extend the scheduled termination date from September 30, 2024 to June 9, 2025 and increase the low end of the facility limit from $1.0 billion to $1.25 billion.

On June 22, 2023, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date to June 22, 2028 (subject to two one-year extensions at the option of the Utility), (ii) increase the maximum letter of credit sublimit to $2.0 billion, and (iii) increase the uncommitted incremental facility to up to $1.0 billion.

On June 22, 2023, PG&E Corporation amended its existing revolving credit agreement to, among other things, extend the maturity date to June 22, 2026 (subject to two one-year extensions at the option of PG&E Corporation).

For more information, see “Credit Facilities” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023. On February 16, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on May 15, 2023, to holders of record on April 28, 2023. On May 18, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on August 15, 2023, to holders of record on July 31, 2023.

On February 16, 2023, the Board of Directors of the Utility declared a common stock dividend of $425 million, which was paid to PG&E Corporation on February 28, 2023. On May 18, 2023, the Board of Directors of the Utility declared a common stock dividend of $450 million, which was paid to PG&E Corporation on June 21, 2023.

On December 20, 2017, the Boards of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation common stock, beginning the fourth quarter of 2017. Subject to the dividend restrictions described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K, any decision to declare and pay dividends on PG&E Corporation’s common stock in the future will be made at the discretion of the Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions of PG&E Corporation, and other factors that the Board of Directors of PG&E Corporation may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

PG&E Corporation’s condensed consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the six months ended June 30, 2023 and 2022.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the six months ended June 30, 2023, net cash provided by operating activities increased by $924 million compared to the same period in 2022. The increase was primarily due to a payment made to the Fire Victim Trust of $592 million during the six months ended June 30, 2022, with no similar activity during the same period in 2023.

Future cash flow from operating activities will be affected by various factors, including:

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.9 billion and $11.2 billion of capital expenditures in 2023. Additionally, future cash flows used in investing activities will be impacted by the payments related to the purchase of the Lakeside Building, and could be impacted by the timing and amount of contributions to the customer credit trust, including certain shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments.  Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and in “Regulatory Matters” below that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

During the three months ended June 30, 2023 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of June 30, 2023, the Utility had recorded an aggregate amount of approximately $6.1 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and Microgrids Memorandum Account. Of these costs, approximately $1.7 billion was authorized for recovery and accounted for as current, and $4.4 billion was accounted for as long term as of June 30, 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to timely recover costs included in these applications.

For more information, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the three months ended June 30, 2023 are summarized in the following table:

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which excluded amounts disallowed as a result of the CPUC’s decision in the OII into the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”), and the 2018 Camp fire, consisted of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and were incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflected work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue included amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings.

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery request of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of costs, such as employee business travel expenses and in-person training costs, that the Utility was able to avoid due to the pandemic.

On January 18, 2023, the Utility, The Utility Reform Network, and the Public Advocates Office of the CPUC filed a joint motion for approval of a settlement agreement, pursuant to which the Utility would receive a revenue requirement of $720.7 million. The settlement agreement does not address $591.9 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

Upon approval, the majority of the Utility’s proposed revenue requirement would be collected over a two-year period.

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the 2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision. On June 8, 2023, the CPUC adopted a final decision granting the Utility’s request for interim rate relief, which went into effect July 1, 2023.

On April 7, 2023, the assigned commissioner issued a scoping memo pursuant to which a proposed decision would be issued by the first quarter of 2024. On June 23, 2023, the ALJ revised the procedural schedule so that a proposed decision will be issued by the second quarter of 2024.

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $749 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

In connection with the WGSC application, the Utility also requested interim rate relief of $631 million, to be recovered over 12 months beginning November 1, 2023. The remaining $105 million would be recovered after the CPUC issues a final decision.

The Utility has proposed a schedule that would call for a final decision by the CPUC prior to June 15, 2024.

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the three months ended June 30, 2023 are summarized in the following table:

On July 22, 2022, the Utility submitted a request for the second track of the GRC proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $206 million in expenses and $129 million in capital expenditures, resulting in a proposed revenue requirement of approximately $241 million, most of which is proposed to be collected over a two-year period beginning August 1, 2023. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. The self-insurance will be funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected in rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. As a result, the Utility could collect the self-insurance amounts over a longer period than it makes wildfire-related payments. The settlement agreement includes a five percent deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

The CPUC’s schedule indicated a final decision on both tracks of this proceeding would be issued in the third quarter of 2023.

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital including ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision. See the 2022 Form 10-K.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding. The second phase has not yet commenced.

On July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility’s continuing participation in the CAISO. 

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (1) impact of the TCJA on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the TCJA. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the second quarter of 2023 by approximately $449 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of June 30, 2023, the Utility had recorded approximately $280 million to Regulatory assets.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in the first quarter of 2022. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds based on the FERC’s TO18 orders, including the orders on common plant, depreciation, the TCJA, and ROE. On May 18, 2023, the FERC issued an order rejecting a revised compliance filing regarding the TCJA. On June 20, 2023, the Utility filed a further compliance filing and a request for rehearing of the FERC’s order. On July 21, 2023, the FERC issued an order denying rehearing by operation of law. For the TCJA issue, the Utility plans to submit a request for private letter ruling with the Internal Revenue Service to obtain clarification regarding the appropriate disposition of the matter. The outcome of the private letter ruling may impact the outcome of the Utility’s request for rehearing. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

Aside from the ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation, and so the Utility was not obligated to make a refund to customers based on this matter. See “Transmission Owner Rate Cases for 2015 and 2016” above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

As disclosed in the 2022 Form 10-K, the Utility uses a formula rate for the costs associated with the Utility’s FERC-jurisdictional electric transmission facilities, which the FERC accepted, with May 1, 2019 as the effective date for rate changes. Pursuant to a settlement agreement, which the FERC has approved, the Utility has an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023, and the Utility will be required to file a replacement rate filing by October 18, 2023 to be effective on January 1, 2024.

Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO20 rate case.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

On February 25, 2022, the Utility submitted the 2022 WMP. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and reducing the impact of PSPS events. On November 10, 2022, OEIS approved the Utility’s 2022 WMP. On December 15, 2022, the CPUC ratified OEIS’s approval.

On February 26, 2023, OEIS issued its final Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the final ARC, OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets but found that the Utility did not substantially comply with the WMP during the 2020 compliance period. On March 24, 2023, the Utility filed a writ in California superior court seeking judicial review of the OEIS ARC on the grounds that OEIS failed to utilize the compliance evaluation criteria adopted by the CPUC. If the court sustains the ARC’s finding that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate whether they will incur a loss in connection with the ARC or the amount of any such loss, as the writ is pending in state court and because any penalty issued by CPUC depends upon various factors.

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers.

On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On June 30, 2023, the CPUC denied the application.

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On January 20, 2023, the CPUC issued a scoping memo. On March 30, 2023, the ALJ modified the procedural schedule, pursuant to which a proposed decision would be issued by January 2024.

On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving transfer from the Utility to Pacific Generation of FERC-jurisdictional assets.

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. For more information about the EOEP, see “PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process” in Item 1A. Risk Factors in the 2022 Form 10-K. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. In addition to its plan to complete the intrusive tests by September 30, 2023, the Utility is performing an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues.

The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents.

On April 13, 2023, the ALJ issued a proposed decision that would close this proceeding but allow for the continued monitoring of the Utility’s safety culture through an advice letter process. On May 19, 2023, the CPUC issued a final order closing the proceeding and implementing the proposed advice letter process to allow for further monitoring.

On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility would continue to operate Diablo Canyon on behalf of all CPUC-jurisdictional load serving entities, and all customers of those load serving entities would be responsible for the cost of extended operations.

The key remaining steps to continued operations include NRC license renewal and approvals from California state agencies. If either is not received, the Utility would retire Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC.

The Utility expects to submit a new application for license renewal with the NRC by the end of 2023. On March 2, 2023, the NRC approved the Utility’s exemption request to allow continued operations at Diablo Canyon past the plant’s current licenses. This exemption will allow the Utility, similar to exemptions granted to other utilities, to continue operating both units at Diablo Canyon while the Utility’s license renewal application is under review.

Consistent with SB 846, the CPUC, the California Energy Resources Conservation and Development Commission, California State Lands Commission, California Coastal Commission, and other state agencies will need to determine that extended operations represent an appropriate path to meet California’s reliability, affordability, and environmental goals.

On February 28, 2023, and in consultation with the CAISO and CPUC, the California Energy Resources Conservation and Development Commission determined that it is prudent to extend the operation of Diablo Canyon to support electric system reliability through 2030.

The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with Diablo Canyon. On June 7, 2023, the California State Lands Commission approved an extension of the Utility’s lease at Diablo Canyon through October 31, 2030.

In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the Internal Revenue Service have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility continue to evaluate the totality of the law, including its impact, its potential implications, and the regulations issued in connection with it.

The Inflation Reduction Act also added a new Energy Infrastructure Reinvestment (“EIR”) category to the DOE’s Clean Energy Financing Program. The Utility is seeking financing through the EIR to help fund California’s clean energy transition.

On April 14, 2023, the Internal Revenue Service issued Revenue Procedure 2023-15, which provides a safe harbor method for determining natural gas repairs deductions for income tax purposes. PG&E Corporation and the Utility are currently evaluating the impact of the law.

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this quarterly report on Form 10-Q, as well as “Item 1A. Risk Factors” and Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.  The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes.  The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments.  Some contracts are accounted for as leases.  The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate.  Credit limits and credit quality are monitored periodically.  These activities are discussed in detail in the 2022 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the six months ended June 30, 2023.