Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this Form 10-Q. It also should be read in conjunction with the 2020 Form 10-K.

Summary of Changes in Net Income (Loss) and Earnings per Share

PG&E Corporation’s net losses were $1,091 million and $574 million for the three and nine months ended September 30, 2021, respectively, compared to net income of $83 million and a net loss of $1,518 million in the same periods in 2020. In the three and nine months ended September 30, 2021, PG&E Corporation recorded a $1.3 billion charge, net of tax as a result of the grantor trust election, with no similar amounts in the same periods in 2020. This amount is partially offset by increases in base revenues authorized in the 2020 GRC in the three and nine months ended September 30, 2021. In the nine months ended September 30, 2020, PG&E Corporation recognized $1.1 billion of expense related to the shares issued to Backstop Parties pursuant to the Backstop Commitment Letters (the “Backstop Commitment Premium Shares”) and $452 million of expense related to the additional shares issued to the Backstop Parties pursuant to the prepaid forward contracts between PG&E Corporation and the Backstop Parties dated as of June 19, 2020 (the “Additional Backstop Commitment Premium Shares”), with no similar amounts for the same period in 2021.

Key Factors Affecting Financial Results

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:

• The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. To the extent that future wildfires occur in the Utility’s service territory, the Utility may incur costs associated with the investigations of the causes and origins of such fires, even if it is subsequently determined that such fires were not caused by the Utility’s facilities. The financial impact of future wildfires could be mitigated through insurance, the Wildfire Fund or other forms of cost recovery. However, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from future wildfires and serves as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. (See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility’s emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims would be capped at 40% of the allowed amount of such claims. (See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

• The Uncertainties Regarding the Impact of Public Safety Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility’s wildfire risk mitigation initiatives included in the 2020-2022 WMP, has been the subject of significant scrutiny and criticism by various stakeholders, including the California governor, the CPUC and the court overseeing the Utility’s probation. The PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers, and future PSPS events may increase these negative perceptions. In addition to the 2019 PSPS events, the Utility initiated several PSPS events in 2020 and 2021 and expects that additional PSPS events will be necessary in the future. (See “OII to Examine the Late 2019 Public Safety Power Shutoff Events” and “OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions” in “Regulatory Matters” below.)

• The Costs and Execution of Other Wildfire Mitigation Efforts. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events. PG&E Corporation and the Utility incurred approximately $2.6 billion in connection with the 2019 WMP and incurred approximately $2.9 billion in 2020 and $1.8 billion in 2021 in connection with the 2020-2022 WMP. Although the Utility may seek cost recovery for certain of these expenses and capital expenditures, the Utility has agreed in the Wildfires OII not to seek rate recovery of certain wildfire-related expenses and capital expenditures that it has incurred or will incur in the amount of $1.823 billion in future applications.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it is undertaking a review and has identified instances of noncompliance. The Utility intends to update the CPUC upon the completion of its review. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for the late inspections or other noncompliance related to wildfire mitigation efforts.

While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. For example, the court overseeing the Utility’s probation in connection with the Utility’s federal criminal proceeding has imposed numerous obligations on the Utility related to its business and operations. The success of the Utility’s wildfire mitigation efforts depends on many factors, including on whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions. (See “U.S. District Court Matters and Probation” and “Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

• The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its FERC TO18 and its impact on the TO19 and TO20 rate cases, 2023 GRC, WMCE applications, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, WMPMA, FRMMA, CPPMA, VMBA, WMBA, and RTBA. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors. The Utility’s ability to seek cost recovery will also be limited as a result of the outcome of the Wildfires OII. (See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.)

• The Impact of Wildfires. PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2020 Zogg fire, or the 2021 Dixie fire, could be significant and could exceed or be excluded from any potential amounts recoverable under applicable insurance policies, the WEMA or the Wildfire Fund under AB 1054, which could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

As of September 30, 2021, PG&E Corporation and the Utility had recorded an aggregate liability of $800 million, $375 million, and $1.15 billion for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, respectively, and in each case before available insurance and other probable cost recoveries in the case of the 2021 Dixie fire, which amounts corresponds to the lower end of the range of reasonably estimable probable losses, but do not include all categories of potential damages and losses. Claims related to the 2019 Kincade fire that were not satisfied in full as of the Effective Date were not discharged in connection with emerging from Chapter 11.

On April 6, 2021, the Sonoma County District Attorney’s Office charged the Utility with five felonies and 28 misdemeanors in connection with the 2019 Kincade fire, and on September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors in connection with the 2020 Zogg fire and three other fires. If the Utility were to be convicted of certain charges in the Kincade Complaint or the Zogg Complaint, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements, and accordingly the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire or the 2020 Zogg fire would materially exceed the $800 million or $375 million, respectively, of aggregate liability that PG&E Corporation and the Utility have recorded.

If the liability for a fire were to exceed $1.0 billion, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, except that recoveries for the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy, and recoveries for each of these fires would also be subject to the other limitations and requirements under AB 1054. As of September 30, 2021, the Utility had recorded insurance receivables of $430 million for the 2019 Kincade fire, $331 million for the 2020 Zogg fire, and $569 million for the 2021 Dixie fire. The Utility had recorded regulatory recovery and Wildfire Fund receivables of $437 million and $150 million, respectively, for the 2021 Dixie fire. However, there can be no assurance that such amounts will ultimately be recovered, and the Utility does not expect that any of its liability insurance would cover restitution payments ordered by the courts presiding over the criminal proceedings. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.)

There have been numerous other wildfires in the Utility’s service territory during 2020 and since the beginning of the 2021 wildfire season. If the Utility were alleged or determined to be a cause of one or more of these wildfires, this allegation or determination could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. (For more information see “2019 Kincade Fire,” “2020 Zogg Fire,” and “2021 Dixie Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

• The Impact of the COVID-19 Pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of COVID-19. 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, the moratorium on service disconnections for residential and small business customers and for eligible medium and large commercial and industrial customers that expired on September 30, 2021, the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” and an observed reduction in non-residential electrical load. The Utility continues to monitor the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. On July 16, 2021, the Governor approved AB 135, which established the CAPP (California Arrearage Payment Program). CAPP enables the IOUs to apply for a statewide total of approximately $695 million to offset customer arrearages incurred during the COVID-19 pandemic. The Utility intends to apply for arrearage relief through the CAPP program. As of September 30, 2021, PG&E Corporation and the Utility had access to approximately $3.3 billion of total liquidity comprised of approximately $269 million of Utility cash, $151 million of PG&E Corporation cash and $2.9 billion of availability under the Utility and PG&E Corporation credit facilities. Other impacts of COVID-19 on PG&E Corporation and the Utility have included operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations, higher credit spreads and borrowing costs and could potentially also include a reduction in revenue due to the cost of capital adjustment mechanism and incremental financing needs. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. (See “2022 Cost of Capital Proceeding” below for more information.)

The Utility has established a memorandum account for tracking costs related to the CPUC’s emergency authorization and order, which, as of September 30, 2021, was $47 million. In addition to the amounts recorded to CPPMA, the Utility has recorded approximately $250 million of under collections from residential customers from June 11, 2020 to September 30, 2021 to RUBA. The Utility intends to seek recovery of this balance in a future application, subject to CPUC reasonableness review. For more information on the impact of COVID-19 on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.” in Item 1A Risk Factors in Part I of the 2020 Form 10-K.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. PG&E Corporation and the Utility continue to evaluate the overall impact of COVID-19 and their analysis is subject to change.

• The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the OII into PG&E Corporation’s and the Utility’s Safety Culture, the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, including the oversight of the Utility’s probation and the potential recommendations by the Monitor, and potential penalties in connection with the Utility’s wildfire mitigation plan and safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California. Further, certain parties filed notices of appeal with respect to the Confirmation Order, including provisions related to the injunction contained in the Plan that channels certain pre-petition fire-related claims to trusts to be satisfied from the trusts’ assets. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.

• The Uncertainties in Connection with the Enhanced Oversight and Enforcement Process. On April 15, 2021, the CPUC placed the Utility in step 1 of the EOEP. As a result, the Utility will be subject to additional reporting requirements, monitoring, and oversight by the CPUC. (See “Enhanced Oversight and Enforcement Process” in “Enforcement and Litigation Matters” below.)

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 this Form 10-Q and the 2020 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 the section entitled “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.

Tax Matters

PG&E Corporation expects to have a U.S. federal net operating loss carryforward of approximately $19.2 billion and California net operating loss carryforward of $18.4 billion at the end of 2021.

Under section 382 of the Internal Revenue Code, 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 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 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 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 Internal Revenue Code.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a grantor trust election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust.

As a result of the grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion which will be offset by payments made by the Fire Victim Trust to the fire victims and the net activities of the Fire Victim Trust. Additionally, there was a $1.3 billion charge, net of tax, decreasing net deferred tax assets for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Condensed Consolidated Financial Statements for activity through December 31, 2020. 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. As of October 27, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact to PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements for the quarter ended September 30, 2021.

Update on Ownership Restrictions in PG&E Corporation’s Amended Articles

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust agreed to elect to treat the Fire Victim Trust as a grantor trust for income tax purposes (which treatment is effective retroactively to the inception of the Fire Victim Trust) and the election has since been filed. 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 stock owned by the Fire Victim Trust are effectively excluded from the total number of outstanding equity securities when calculating a person’s percentage ownership for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because it is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,463,112,791 shares outstanding as of October 27, 2021, only 1,507,625,611 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust 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 assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective percentage ownership limitation for purposes of the Amended Articles as of October 27, 2021 was 2.9% of outstanding shares. As of October 27, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and nine months ended September 30, 2021 and 2020. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of net income (loss) attributable to common shareholders for the three and nine months ended September 30, 2021 and 2020:

			Three Months Ended September 30,												Nine Months Ended September 30,
(in millions)			2021						2020						2021						2020
Consolidated Total			$	(1,091)					$	83					$	(574)					$	(1,518)
PG&E Corporation			(46)						(84)						(139)						(1,656)
Utility			$	(1,045)					$	167					$	(435)					$	138

PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt. PG&E Corporation’s net loss for the nine months ended September 30, 2020 also included reorganization items, net, including approximately $1.5 billion in expense related to the Backstop Commitment Premium Shares and the Additional Backstop Commitment Premium Shares.

Utility

The tables below show certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2021 and 2020. The tables separately identify 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. In addition, expenses that have been specifically authorized (such as energy procurement costs) and the corresponding revenues the Utility is authorized to collect to recover such 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.

			Three Months Ended September 30, 2021																		Three Months Ended September 30, 2020
			Revenues/Costs:																		Revenues/Costs:
(in millions)			That Impacted Earnings						That Did Not Impact Earnings						Total Utility						That Impacted Earnings						That Did Not Impact Earnings						Total Utility
Electric operating revenues			$	2,659					$	1,522					$	4,181					$	2,392					$	1,418					$	3,810
Natural gas operating revenues			998						286						1,284						896						176						1,072
Total operating revenues			3,657						1,808						5,465						3,288						1,594						4,882
Cost of electricity			—						1,133						1,133						—						1,114						1,114
Cost of natural gas			—						176						176						—						90						90
Operating and maintenance			2,250						543						2,793						1,877						434						2,311
Wildfire-related claims, net of recoveries			94						—						94						25						—						25
Wildfire Fund expense			162						—						162						120						—						120
Depreciation, amortization, and decommissioning			801						—						801						845						—						845
Total operating expenses			3,307						1,852						5,159						2,867						1,638						4,505
Operating income (loss)			350						(44)						306						421						(44)						377
Interest income			—						—						—						5						—						5
Interest expense			(342)						—						(342)						(323)						—						(323)
Other income, net			89						44						133						57						44						101
Reorganization items, net			—						—						—						(82)						—						(82)
Income before income taxes			$	97					$	—					$	97					$	78					$	—					$	78
Income tax provision (benefit) (1)															1,139																		(92)
Net income (loss)															(1,042)																		170
Preferred stock dividend requirement (1)															3																		3
Income (Loss) Attributable to Common Stock															$	(1,045)																	$	167

(1) These items impacted earnings for the three months ended September 30, 2021 and 2020.

			Nine Months Ended September 30, 2021																		Nine Months Ended September 30, 2020
			Revenues/Costs:																		Revenues/Costs:
(in millions)			That Impacted Earnings						That Did Not Impact Earnings						Total Utility						That Impacted Earnings						That Did Not Impact Earnings						Total Utility
Electric operating revenues			$	7,544					$	3,983					$	11,527					$	6,851					$	3,434					$	10,285
Natural gas operating revenues			2,821						1,048						3,869						2,592						844						3,436
Total operating revenues			10,365						5,031						15,396						9,443						4,278						13,721
Cost of electricity			—						2,570						2,570						—						2,418						2,418
Cost of natural gas			—						670						670						—						508						508
Operating and maintenance			5,782						1,923						7,705						4,937						1,484						6,421
Wildfire-related claims, net of recoveries			261						—						261						195						—						195
Wildfire Fund expense			399						—						399						293						—						293
Depreciation, amortization, and decommissioning			2,540						—						2,540						2,574						—						2,574
Total operating expenses			8,982						5,163						14,145						7,999						4,410						12,409
Operating income (loss)			1,383						(132)						1,251						1,444						(132)						1,312
Interest income			17						—						17						33						—						33
Interest expense			(1,032)						—						(1,032)						(764)						—						(764)
Other income, net			258						132						390						155						132						287
Reorganization items, net			(12)						—						(12)						(286)						—						(286)
Income before income taxes			$	614					$	—					$	614					$	582					$	—					$	582
Income tax provision (benefit) (1)															1,039																		434
Net income (loss)															(425)																		148
Preferred stock dividend requirement (1)															10																		10
Income (Loss) Attributable to Common Stock															$	(435)																	$	138

(1) These items impacted earnings for the nine months ended September 30, 2021 and 2020.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and nine months ended September 30, 2021 and 2020, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $369 million, or 11%, in the three months ended September 30, 2021, compared to the same period in 2020, primarily due to an increase in base revenues authorized in the 2020 GRC and the impact of formula rates approved in the Transmission Owner Rate Case for 2019 (the “TO20” rate case).

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $922 million, or 10%, in the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to an increase in base revenues authorized in the 2020 GRC.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $373 million, or 20%, in the three months ended September 30, 2021, compared to the same period in 2020, primarily due to $204 million in insurance costs that were recognized in 2021 as a result of the 2020 GRC approval in the fourth quarter of 2020. In the three months ended September 30, 2020, prior to approval of the 2020 GRC, insurance costs were recorded as deferred expense. In addition, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2020. These increases were partially offset by $75 million in previously deferred CEMA costs recorded in conjunction with interim rate relief in the three months ended September 30, 2020, with no comparable costs during the same period in 2021.

The Utility’s operating and maintenance expenses that impacted earnings increased by $845 million, or 17%, in the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to $508 million in insurance costs and $366 million in vegetation management costs that were recognized in 2021 as a result of the 2020 GRC approval in the fourth quarter of 2020. In the nine months ended September 30, 2020, prior to approval of the 2020 GRC, these amounts were recorded as deferred expense. In addition, the Utility recorded approximately $240 million of costs recorded in conjunction with interim rate relief associated with the WMCE application (see “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” below) and a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable costs in the same period in 2020. These increases were partially offset by $225 million in previously deferred CEMA costs recorded in conjunction with interim rate relief, with no comparable costs in the same period in 2021.

Wildfire-related claims, net of recoveries

Costs related to wildfires that impacted earnings increased by $69 million, or 276%, in the three months ended September 30, 2021, compared to the same period in 2020. The Utility recognized pre-tax charges of $1.15 billion related to the 2021 Dixie fire, offset by $569 million of probable insurance recoveries, $339 million of probable recoveries through the WEMA, and $150 million of probable recoveries from the Wildfire Fund in the three months ended September 30, 2021, with no comparable charges and recoveries in the same period in 2020. The Utility also recorded $25 million in pre-tax charges related to the 2019 Kincade fire in the three months ended September 30, 2020, with no comparable charges in the same period in 2021.

Costs related to wildfires that impacted earnings increased by $66 million, or 34%, in the nine months ended September 30, 2021, compared to the same period in 2020. The Utility recognized pre-tax charges of $1.15 billion related to the 2021 Dixie fire, offset by $569 million of probable insurance recoveries, $339 million of probable recoveries through the WEMA, and $150 million of probable recoveries from the Wildfire Fund in the nine months ended September 30, 2021, with no comparable charges and recoveries in the same period in 2020. Additionally, the Utility recognized pre-tax charges of $175 million related to the 2019 Kincade fire and $100 million related to the 2020 Zogg fire, offset by $108 million of probable insurance recoveries, in the nine months ended September 30, 2021, as compared to $625 million in pre-tax charges related to the 2019 Kincade fire, partially offset by $430 million in insurance recoveries in the nine months ended September 30, 2020.

In addition to the probable wildfire-related recoveries noted above, in the three and nine months ended September 30, 2021,the Utility recorded $98 million of probable recoveries of 2021 Dixie fire costs through FERC TO formula rates, which are reflected in Electric Operating Revenues and, along with the items noted above, fully offset the $1.15 billion charge related to the 2021 Dixie fire.

Wildfire Fund expense

Wildfire Fund expense that impacted earnings increased by $42 million, or 35%, in the three months ended September 30, 2021, compared to the same period in 2020, primarily due to accelerated amortization of the Wildfire Fund asset as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire.

Wildfire Fund expense that impacted earnings increased by $106 million, or 36%, in the nine months ended September 30, 2021, compared to the same period in 2020. Due to the Chapter 11 Cases, the Utility’s participation in the Wildfire Fund was limited to 40% for the period from July 12, 2019 to June 30, 2020. Additionally, the Utility recorded accelerated amortization of the Wildfire Fund asset as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire.

Depreciation, Amortization, and Decommissioning

There were no material changes in depreciation, amortization, and decommissioning expenses that impacted earnings for the periods presented.

Interest Income

There was no material change to interest income that impacted earnings for the periods presented.

Interest Expense

Interest expense that impacted earnings increased by $19 million, or 6%, and increased by $268 million, or 35%, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, primarily due to the issuance of new debt in connection with or subsequent to emergence from Chapter 11.

Other Income, Net

Other income, net increased by $32 million, or 56%, and increased by $103 million, or 66%, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, due to the decrease in the discount rate resulting in lower expenses on non-service pension costs.

Reorganization items, net

Reorganization items, net decreased by $82 million, or 100%, and $274 million, or 96%, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, primarily due to the Utility’s emergence from Chapter 11 on July 1, 2020.

Income Tax Provision (Benefit)

Income tax provision increased by $1,231 million and $605 million, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, primarily as a result of the grantor trust election. In the third quarter of 2021, the Utility recorded a $1.3 billion charge, net of tax, decreasing net deferred tax assets for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Condensed Consolidated Financial Statements for activity through December 31, 2020.

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2021						2020						2021						2020
Federal statutory income tax rate			21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)			303.4		%				(17.8)		%				45.3		%				30.9		%
Effect of regulatory treatment of fixed asset differences (2)			(156.8)		%				(113.5)		%				(57.4)		%				(48.1)		%
Fire Victim Trust (3)			994.5		%				—		%				155.4		%				—		%
Bankruptcy and Emergence			0.5		%				1.4		%				0.3		%				75.2		%
Other, net			25.8		%				(8.0)		%				4.8		%				(4.5)		%
Effective tax rate			1,188.4		%				(116.9)		%				169.4		%				74.5		%

(1) Includes the effect of state flow-through ratemaking treatment.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. The Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2021 and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) Includes the effect of the grantor trust election. For more information, see Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Utility Revenues and Costs that Did Not Impact Earnings

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

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

			Three Months Ended September 30,												Nine Months Ended September 30,
(in millions)			2021						2020						2021						2020
Cost of purchased power, net			$	1,017					$	1,043					$	2,344					$	2,228
Fuel used in generation facilities			116						71						226						190
Total cost of electricity			$	1,133					$	1,114					$	2,570					$	2,418

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.

			Three Months Ended September 30,												Nine Months Ended September 30,
(in millions)			2021						2020						2021						2020
Cost of natural gas sold			$	144					$	56					$	567					$	411
Transportation cost of natural gas sold			32						34						103						97
Total cost of natural gas			$	176					$	90					$	670					$	508

Operating and Maintenance Expenses

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.

Other Income, Net

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.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

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% equity and 48% debt and preferred stock 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 distributions 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 credit ratings fell below investment grade in January 2019, at which time the Utility was required to post additional collateral under its commodity purchase agreements. A further downgrade would not materially impact the collateral postings for procurement activity. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.).

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of COVID-19. The Utility continues to evaluate the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. The outbreak of COVID-19 and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have and will continue to impact the Utility for an indeterminate period of time. The Utility’s accounts receivable balances over 30 days outstanding as of September 30, 2021, were approximately $935 million, or $666 million higher as compared to the balance as of September 30, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections for as long as current COVID-19 circumstances persist.

Although the Utility is seeking further regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance as to the amount or timing of such relief. On April 16, 2020, the CPUC approved a resolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the customer protections described within the resolution. Although the moratorium on service disconnections ended on September 30, 2021, the Utility does not anticipate resuming service disconnections until 2022. (See “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” below for more information.) On July 16, 2021, the California governor signed into law AB 135, which provides financing assistance to customer accounts in arrears. (See “Assembly Bill 135” below for more information.). In addition to the amounts recorded to CPPMA, the Utility has recorded approximately $250 million of under collections from residential customers from June 11, 2020 to September 30, 2021 to RUBA. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

Cash and Cash Equivalents

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.

Financial Resources

Equity Financings

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers, establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements with the Forward Purchasers.

As of September 30, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings. During the nine months ended September 30, 2021, PG&E Corporation has not sold any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement.

Debt Financings

In March 2021, the Utility issued $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s term loan credit agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement, and (iii) general corporate purposes.

In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

Credit Facilities

At September 30, 2021, PG&E Corporation and the Utility had $500 million and $2.4 billion available under their respective $500 million and $6.5 billion credit facilities, including the Utility’s term loan credit facility and Receivables Securitization Programs. The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 from time to time.

For more information, see “Credit Facilities” in Note 5 to the Condensed Consolidated Financial Statements in Item 1.

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The rate of interest on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of September 30, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Condensed Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Condensed Consolidated Balance Sheet.

Dividends

On December 20, 2017, the boards of directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the boards of directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the boards of directors may deem relevant. On April 9, 2020, the Bankruptcy Court entered an order that restricts PG&E Corporation from paying common dividends until it has recognized $6.2 billion in Non-GAAP Core earnings following the Effective Date of the Plan (Non-GAAP Core Earnings means GAAP earnings adjusted for certain non-core items). It is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

Utility Cash Flows

The Utility’s cash flows were as follows:

			Nine Months Ended September 30,
(in millions)			2021						2020
Net cash provided by (used in) operating activities			$	2,220					$	(19,170)
Net cash used in investing activities			(4,823)						(5,524)
Net cash provided by financing activities			2,479						23,982
Net change in cash, cash equivalents and restricted cash			$	(124)					$	(712)

Operating Activities

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 nine months ended September 30, 2021, net cash provided by operating activities increased by $21.4 billion compared to the same period in 2020. This increase was primarily due to the payment of $16.8 billion in satisfaction of pre-petition wildfire-related claims in 2020 as compared to the payment of $758 million to the Fire Victim Trust in 2021. Additionally, the Utility made initial and first annual contributions to the Wildfire Fund of $5.0 billion and paid approximately $260 million more in interest during the nine months ended September 30, 2020 as compared to the same period in September 30, 2021.

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

• the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

• the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Enforcement Matters” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below for more information);

• the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover from customers any losses incurred in connection with COVID-19, as well as the impact of COVID-19 on the availability or cost of financing;

• the timing and amounts of annual contributions to the Wildfire Fund and if necessary, the availability of funds to pay eligible claims for liabilities arising from future wildfires;

• the timing and amount of substantially increasing costs in connection with 2020-2022 WMPs and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered in rates (see “Regulatory Matters” below for more information);

• the timing and amount of premium payments related to wildfire insurance (see “Insurance Coverage” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information);

• the timing of the final payment to be made to the Fire Victim Trust, pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility (see “Restructuring Support Agreement with the TCC” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information);

• the timing of and amount of the gain to be returned to customers from the sale of the SFGO and the amounts incurred related to the move to and the leasing of the Lakeside Building; and

• the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested.

Investing Activities

Net cash used in investing activities decreased by $701 million during the nine months ended September 30, 2021 as compared to the same period in 2020. This decrease was primarily due to the sale of SFGO, which resulted in net proceeds received of $749 million in September 2021, with no similar receipts in 2020. (See “Oakland Headquarters Lease and Sale of SFGO” in Note 11 to the Condensed Consolidated Financial Statements in Item 1.) 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 investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning 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.

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 $7.5 billion and $8.5 billion in capital expenditures in 2021 and between $7.8 billion and $8.9 billion in 2022. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building.

Financing Activities

Net cash provided by financing activities decreased by $21.5 billion during the nine months ended September 30, 2021 as compared to the same period in 2020. This decrease was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13.0 billion in 2020, with no similar activity in 2021. Additionally, during the nine months ended September 30, 2021, the Utility issued approximately $6.4 billion less of first mortgage bonds and borrowed approximately $2.0 billion less under the available credit facilities, net of repayments, as compared to the same period in 2020. Lastly, the Utility received $370 million of proceeds in 2021 in connection with the Transaction Agreement between the Utility and SBA, with no similar receipts in 2020. For more information, see “Sale of Transmission Tower Wireless Licenses” in Note 3 to the Condensed Consolidated Financial Statements in Item 1.

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, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s applications for a post-emergence securitization transaction and for an AB 1054 securitization transaction. (See “Application for Post-Emergence Securitization Transaction” and “Application for AB 1054 Securitization Transaction” below for more information.)

ENFORCEMENT AND LITIGATION MATTERS

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. 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. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2020 Form 10-K.

U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On August 7, 2020, after a number of filings involving different parties, the court entered an order adopting the new conditions jointly proposed by the Utility, the Monitor, and the Department of Justice on June 24, 2020. Among other things, these conditions require the Utility to staff an in-house vegetation inspection manager and approximately 30 additional field inspectors to oversee vegetation management work. Further, the Utility is required to implement a program to assess the age and expected useful life of certain electrical components in high fire-threat areas, incorporate this information into its risk-based asset management programs and provide monthly progress reports to the Monitor. The Utility must also hire additional inspectors to oversee inspections of its transmission assets and implement a 90-day replacement requirement for cold end hardware in high fire-threat areas with an observed material loss approaching 50%.

On December 29, 2020, the court entered an order requiring the Utility to show cause as to why additional proposed conditions of probation should not be added. The proposed conditions would require the Utility to, when determining which distribution lines to de-energize during a PSPS event: (i) take into account the extent to which vegetation bordering those lines is not in compliance with certain requirements, and (ii) to the extent that information shows that such vegetation presents a safety hazard in the event of a windstorm, make a specific determination with respect to that distribution line and de-energize it unless the Utility finds in writing that there are specific reasons to believe that no safety issues exist. The Utility filed its response on January 20, 2021, proposing supplemental language to clarify and specify how the Utility will implement the new conditions proposed by the court. On March 24, 2021, the court issued an order requiring the Utility to provide, among other information, a revision of the proposed conditions of probation that incorporates consideration of the potential for a tree to fall into an overhead electric line based on its height and distance from the line. On April 29, 2021, the court entered an order declining to impose these proposed conditions, but recommending that the Utility, when determining which distribution lines to de-energize during a PSPS event: (i) take into account the extent to which vegetation bordering those lines is not in compliance with certain requirements, and (ii) to the extent that information shows that such vegetation presents a safety hazard in the event of a windstorm, make a specific determination with respect to that distribution line and de-energize it unless the Utility finds in writing that there are specific overriding public safety needs to leave the lines energized. The court also ordered the Utility to file a statement by July 1, 2021 setting forth its PSPS criteria for 2021 and stating the extent to which it has adopted the court’s recommendations. The Utility submitted its response on July 1, 2021.

On February 4, 2021, the court entered an order requiring the Utility to show cause as to why the additional proposed conditions of probation suggested by amici in a January 27, 2021 filing should not be added. The proposed conditions would require the Utility to: (i) hire a chief data operations officer with the responsibility to review the Utility’s information management and record-keeping systems and manage the relationship to operations, including vegetation management work and PSPS; (ii) initiate steps to prevent data falsification or omission; (iii) propose a plan to mark trees in tier 2 and tier 3 high wildfire danger zones for removal and track the status of the tree removal process for vegetation management; and (iv) propose steps to improve its information management and records-keeping process to improve information integrity, inform analysis, and inform and enhance daily operations including PSPS. The Utility’s and the United States’ responses were submitted on March 3, 2021, and reply by amici was submitted on March 10, 2021.

On February 18, 2021, the court issued an order requiring the Utility to show cause as to why an additional proposed condition of probation, which would require the Utility to “identify and remove any tree or portion thereof leaning toward any distribution line if it may contact the line from the side or fall on the line and must do so regardless of the health of the tree[,]” should not be added. On April 29, 2021, the court modified the Utility’s conditions of probation to require the Utility to comply with the scope of section 4293 of the California Public Resources Code as articulated by the CPUC and Cal Fire.

On April 20, 2021, the court issued an order requiring the Utility to appear in connection with a potential probation violation based on the charges filed by the Sonoma County District Attorney’s office related to the 2019 Kincade fire. The court held hearings on May 4, 2021, June 2, 2021 and September 13, 2021.

In the course of 2021, the court entered numerous other orders, including in connection with the Utility’s vegetation management, the Utility’s PSPS program, the 2018 Camp fire, the 2019 Kincade fire, the 2020 Zogg fire and the 2021 Dixie fire.

The Utility may receive additional orders from the court for the duration of the probation period in the future.

Enhanced Oversight and Enforcement Process

In the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics (some of which will be determined in an ongoing regulatory proceeding). The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and Orders Instituting Investigations and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

The Utility is unable to predict whether additional fines or penalties may be imposed, or other regulatory actions may be taken.

On August 18, 2021, the President of the CPUC informed the Utility that the CPUC staff intends to conduct a fact-finding review regarding a pattern of self-reported missed inspections and other self-reported safety incidents to determine whether a recommendation to advance the Utility further within the EOEP is warranted.

Vegetation Management

The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC’s resolution states that a step 1 triggering event has occurred because the Utility “has made insufficient progress toward approved safety or risk-driven investments related to its electric business.” The resolution finds that, based on the CPUC’s evaluation of the Utility’s enhanced vegetation management work in 2020, the Utility “is not sufficiently prioritizing its Enhanced Vegetation Management (EVM) based on risk” and “is not making risk-driven investments.” The resolution also finds that “less than five percent of the EVM work” the Utility completed in 2020 “was on the 20 highest risk power lines according to [its] own risk rankings.”

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s executive director on May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addresses the EVM situation that occurred in 2020 and provides a risk-informed EVM workplan for 2021. The Utility is required to update the information contained in the corrective action plan every 90 days. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

The Utility is unable to predict the outcome of this regulatory process.

REGULATORY MATTERS

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. Discussed below are significant regulatory developments that have occurred since filing the 2020 Form 10-K.

During the third quarter of 2021, the Utility continued to make progress on regulatory matters.

• In September, OEIS issued a final action statement approving the Utility’s 2021 WMP and in October, the CPUC ratified the OEIS’ approval.

• In September, the Utility filed a motion seeking CPUC approval of a settlement agreement for its 2020 WMCE application. Under the settlement agreement, the Utility would recover a revenue requirement of $1.04 billion, or 81% of the requested $1.28 billion.

• In September, the Utility filed its 2021 WMCE application, requesting cost recovery of approximately $1.6 billion of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities, resulting in a proposed revenue requirement of approximately $1.47 billion.

Periodically, costs arise that could not have been anticipated by the Utility during GRC applications or that have been deliberately excluded therefrom. 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 has also authorized 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, and certain third-party wildfire claims. While the Utility 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, or the Utility may enter into a settlement for an amount that is less than the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. As of September 30, 2021, the Utility had recorded an aggregate amount of approximately $4.4 billion in the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA. Because rate recovery requires CPUC authorization in separate proceedings for these accounts, there is a delay between when the Utility incurs costs and when it may recover those costs.

If the amount of the costs recorded in these accounts continues to increase, 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.

(For more information, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1., “Regulatory Matters - Wildfire Mitigation and Catastrophic Events Costs Recovery Applications,” “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account,” “Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications,” and “Regulatory Matters - Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” below.)

Wildfire Mitigation and Catastrophic Events Costs Recovery Applications

2020 WMCE Application

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities (the “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist 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 are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflect work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million. The requested revenue for CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events.

Given the CPUC’s prior approval of $447 million in interim rate relief (which includes interest), the Utility proposed to recover the remaining $868 million revenue requirement, including interest, over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that resolves all of the issues raised by the settling parties in the Utility’s application for recovery of costs requested in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this matter to April 1, 2022.

The Utility is unable to predict the outcome of this application. 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 this application.

For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and in Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.

2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”).

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application cover activities during the years 2015 to 2020 and are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The Utility’s proposed revenue requirement would be collected over a two-year period starting in January 2023, except for the Microgrids Memorandum Account capital revenue requirement, which would continue through 2026. The costs addressed in this application reflect costs to: (1) complete wildfire risk mitigation activities in accordance with the Utility’s annual WMPs; (2) respond to government-declared catastrophic events to repair damaged facilities, restore utility services, and protect the Utility’s employees and customers; and (3) implement various customer-focused initiatives. The majority of such costs were incurred in 2020.

The Utility’s requested revenue requirement primarily includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, and the WMBA of $149 million. The requested revenue requirement for CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events. These costs were incurred during the years 2015 to 2020 but primarily in 2020.

The Utility has proposed a schedule that would call for a final decision by the CPUC in September 2022. The Utility is unable to predict the timing and outcome of the application.

Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account

On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA.

On June 30, 2021, the Utility and other parties filed a joint motion for approval of a settlement agreement, which, if adopted, would authorize recovery of a $445.4 million revenue requirement. On October 21, 2021, the CPUC adopted the settlement agreement.

For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Catastrophic Event Memorandum Accounts and Applications

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. In the 2020 GRC Decision, the CPUC required the Utility to track these costs in the VMBA beginning January 1, 2020. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a revised application, revised testimony and revised workpapers, reflecting a new revenue requirement request of $669 million, pursuant to a CPUC ruling allowing these changes.

The 2018 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.

On March 9, 2020, the CPUC issued a modified scoping memo and ruling. On May 4, 2020, the Utility filed a revised application, which included 2019 tree mortality costs, reflecting a new revenue requirement request of $757 million.

On January 8, 2021, the Utility filed a revised application updating the revenue requirement to include an additional $5.6 million of tree mortality costs and the cost of hiring an independent auditor.

On July 2, 2021, the independent audit report of the tree mortality costs was submitted to the CPUC, recommending a $2.4 million reduction.

The Utility expects to file a settlement agreement with certain parties in early November 2021 and for the CPUC to issue a final decision in the first or second quarter of 2022.

Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections

In response to the COVID-19 pandemic, on April 16, 2020, the CPUC adopted a resolution ordering utilities to implement a number of emergency customer protections for one year beginning on March 4, 2020 through April 16, 2021. On February 12, 2021, the CPUC adopted a subsequent resolution that extended the emergency customer protections through June 30, 2021.

The resolutions authorize utilities to establish memorandum accounts to track incremental costs associated with complying with the resolution.

On June 11, 2020, the CPUC issued a final decision as part of the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs that permanently eliminated deposit requirements for residential customers. On April 19, 2021, the CPUC issued a final decision to implement a temporary moratorium on service disconnection for medium and large commercial and industrial customers. Although the moratorium on service disconnections ended on September 30, 2021, the Utility does not anticipate resuming service disconnections until 2022.

PG&E Corporation and the Utility are unable to predict whether the moratorium on service disconnections will be reinstated, which could have a material impact on results of operations, financial condition, and cash flows of PG&E Corporation and the Utility.

For more information, see “Regulatory Matters - Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” in Item 7 of the 2020 Form 10-K.

Other Regulatory Proceedings

Application to Sell General Office Complex

On September 30, 2020, the Utility filed an application with the CPUC to sell its SFGO located at 25 Beale Street, 45 Beale Street, 77 Beale Street, 50 Main Street, 215 Market Street and 245 Market Street in downtown San Francisco, and to recover costs to relocate its staff at SFGO to a new headquarters to the Lakeside Building, and for appropriate ratemaking treatment of those transactions.

The Utility proposed that the SFGO sale and headquarters transition would proceed in several interrelated steps: the Utility would enter into a lease for the Lakeside Building with an option to purchase the Lakeside Building; the Utility would market and sell the SFGO, subject to CPUC approval; and the Utility would enter into an agreement with the buyer of the SFGO to lease back space during the multi-year relocation period (collectively, the “Transactions”). As space in the Lakeside Building becomes available following the expiration of existing tenants’ leases and completion of the redevelopment of the property to the Utility’s specifications, the Utility will relocate employees and operations from the SFGO and certain East Bay office locations to the Lakeside Building in phases over several years, beginning in 2022.

In this application, the Utility requested that the CPUC: (i) authorize the Utility to sell the SFGO pursuant to Public Utilities Code section 851, (ii) approve the Utility’s ratemaking proposal to distribute all of the gain on sale of the SFGO to customers over five years, beginning in 2022, (iii) approve the recovery of costs to lease back the SFGO after the buildings are sold, costs to lease the Lakeside Building, and other transition costs, and (iv) authorize the Utility to forecast the intended purchase of the Lakeside Building and include it in the Utility’s 2023 GRC. The Utility also proposed to establish a balancing account to record lease payments, net savings or costs on operating expense and capital expense, gain on sale, moving costs and related costs for inclusion in electric and gas rates.

On May 21, 2021, the Utility entered into a purchase agreement with HNG Atlas US LP, to sell the SFGO for $800 million.

On May 26, 2021, the Utility filed an amended settlement agreement with the CPUC. Under the amended settlement, the parties agree that (1) the Utility’s headquarters strategy, including the move to the Lakeside Building, the sale of SFGO, and the terms of the agreement to lease and the option to purchase the Lakeside Building, is reasonable, (2) all of the gain on sale of SFGO will be returned to customers over five years, beginning in 2022, and (3) the costs associated with the Utility’s move to the Lakeside Building and development will be considered at later stages of the proceeding and through a petition for modification of the final decision in the proceeding.

The CPUC issued a final decision approving the purchase agreement and the ratemaking treatment proposed under the parties’ settlement on August 19, 2021, and the sale closed on September 17, 2021. The Utility will submit an advice letter by December 1, 2021, detailing the final costs of the sale.

Application for Post-Emergence Securitization Transaction

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. and approving a structure for the transaction. As requested, the decision authorizes the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC’s existing jurisdiction, the decision adopts a transaction structure comprised of four elements (1) an initial shareholder contribution of $2.0 billion, with $1.0 billion to be contributed in 2021, or, if a pending request for an extension is granted, in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. Three parties filed applications for rehearing of the decision on May 3, 2021, and the Utility filed a response to those applications on May 14, 2021. On August 12, 2021, the CPUC issued a decision denying the applications for rehearing.

Separately, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to securitize the $7.5 billion of claims associated with the 2017 Northern California wildfires. On May 11, 2021, the CPUC issued a decision granting the Utility’s January 2021 application for a financing order authorizing the issuance of $7.5 billion of recovery bonds in connection with the rate neutral securitization proceeding. Two parties filed applications for rehearing of the financing order, and the Utility filed a response to those applications for rehearing on June 4, 2021. On August 12, 2021, the CPUC issued a decision denying the applications for rehearing.

On September 10, 2021, TURN filed a petition for writ of review of the decision and financing order in state court. Responses to the petition were filed on October 15, 2021.

Application for AB 1054 Securitization Transaction

On February 24, 2021 the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to $1.19 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility in 2020 and 2021.  The $1.19 billion reflects capital expenditures related to the Utility’s Community Wildfire Safety Program that were approved by the CPUC in the 2020 GRC, and includes $655 million in recorded 2020 capital expenditures and an additional $535 million in forecast capital expenditures in 2021.  The final amount to be securitized would be based on recorded 2020 and 2021 Community Wildfire Safety Program capital expenditures incurred by the Utility prior to the securitization transaction.

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest and would reduce rates on a present value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a NBC sufficient to pay debt service on the recovery bonds.  The application also requested to exclude the securitized debt from the Utility’s ratemaking capital structure and to adjust its 2020 GRC revenue requirement following the issuance of the recovery bonds.  The application indicated that the issuance of the bonds is anticipated to occur before the end of 2021, but timing is subject to change.

On June 24, 2021, the CPUC issued a decision granting the Utility’s application and authorizing the Utility to issue up to approximately $1.2 billion of recovery bonds. On July 6, 2021, the financing order became final and non-appealable.

2020-2022 Wildfire Mitigation Plan

As previously disclosed, on February 7, 2020, the Utility submitted its 2020 WMP and utility survey. The Utility’s 2020 WMP describes the Utility’s wildfire safety programs, which are focused on three key areas: reducing the potential for fires to be started by electrical equipment, reducing the potential for fires to spread, and minimizing the frequency, scope and duration of PSPS events, as well as providing historical data requested by the guidelines. The Utility’s 2020 WMP covers a three-year period from 2020 to 2022 but is updated annually.

On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved the Utility’s 2020 WMP. The resolutions indicate that while the Utility’s 2020 WMP met the minimum requirements for its submission, the deficiencies found, classified as severity level A, B, or C Conditions, require significant follow-up from the Utility and oversight to ensure appropriate remedies for the deficiencies. The Utility received 41 Conditions in total with the first set, classified as Class A Conditions, submitted on July 27, 2020. The second set, Class B Conditions, were completed on September 9, 2020 and the third, Class C Conditions, were submitted as part of the 2021 WMP update on February 5, 2021. On December 30, 2020, the OEIS issued a notice of non-compliance finding that the Utility’s responses to the Class A Conditions were insufficient. The OEIS has required the Utility to include 39 action items in its 2021 WMP to address the insufficient responses. On January 8, 2021, the OEIS issued a Notice of Non-Compliance finding that the Utility’s quarterly report addressing the Class B Conditions was insufficient. The OEIS directed the Utility to respond to 84 action items in its 2021 WMP or via a supplemental filing. On February 26, 2021, the Utility submitted its supplemental filing addressing the remaining action items regarding the Class A and Class B conditions that OEIS determined were insufficient.

The Utility’s 2021 WMP was submitted on February 5, 2021. The 2021 WMP updated the 2020 WMP and addressed the Utility’s wildfire safety programs 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 April 27, 2021, the OEIS extended its deadline to issue a determination on the Utility’s 2021 WMP. On May 4, 2021, the OEIS issued a revision notice requiring the Utility to address six issues. The Utility submitted its response to the revision notice on June 3, 2021, and parties filed comments on June 10, 2021 and reply comments on June 16, 2021.

On September 22, 2021, OEIS issued a final action statement approving the Utility’s 2021 WMP and on October 21, 2021, the CPUC ratified OEIS’ approval.

In 2021, the Utility notified the CPUC that it had missed inspections and other targets subject to the 2020 WMP. The Utility is undertaking a review of its electric asset inspections. For more information, see “Electric Asset Inspections” below.

On July 1, 2021, the Utility received a copy of the independent evaluator’s report concerning compliance with the 2020 WMP. The independent evaluator generally found that the work conducted by the Utility in 2020 aligned with the 2020 WMP targets but did find exceptions and areas of non-compliance. The independent evaluator also reviewed the Utility’s funding of 2020 WMP initiatives and determined that while most initiatives were fully funded when compared to budget, there were some initiatives where the Utility underspent in comparison to budget.

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 in connection with the 2019 WMP, 2020 WMP, and 2021 WMP recorded in the FRMMA and WMPMA, which the Utility expects will be substantial. (See “2020 WMCE Application” and “2021 WMCE Application” above for more information.)

OIR Regarding Microgrids

As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC sought to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by spring or summer 2020, if not sooner. At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal contained three components for which it sought scope and cost recovery authorization of up to approximately $379 million in both expense and capital.

The CPUC adopted a decision in the first track of the proceeding on June 11, 2020, which approved with conditions the Utility’s proposal and requires the Utility to track costs in a new memorandum account for subsequent regulatory review and recovery in rates.

The CPUC initiated the second track of the proceeding on July 3, 2020, which focused on the transition from diesel mobile generation to alternative, cleaner backup power generation. On January 14, 2021, the CPUC adopted a final decision in the second track of the proceeding (the “Track 2 Decision”). The Track 2 Decision requires the Utility to justify the amount of temporary generation necessary for use at substations during the 2021 wildfire season; to propose a longer-term framework for substation generation solutions to mitigate PSPS outage events by June 30, 2021; and to file an application by September 30, 2021 to recover the costs incurred in 2020 associated with the use of temporary generation to mitigate PSPS outages. The Track 2 Decision also authorizes the Utility to record the future costs of temporary generation for substations in a memorandum account and to recover the costs for any clean substation project(s) through a one-way balancing account, up to a $350 million cap and subject to other eligibility requirements.

On March 5, 2021, the Utility submitted an advice letter seeking authorization to track and record costs for the reservation and operation of up to 168 MW of temporary generation to support substation-level microgrids during 2021 PSPS events. On April 14, 2021, the CPUC approved the Utility’s request. On June 4, 2021, the Utility notified the CPUC that it did not identify any generation-based clean substation projects within the cost-effectiveness parameters established by the Track 2 Decision, and proposed a demand response-based clean substation pilot project. On September 9, 2021, the CPUC approved the Utility’s proposed demand-response based pilot project, ordered the Utility to issue a new solicitation by November 2021 to procure at least one clean substation project, and ordered the Utility to submit the results of that solicitation to the CPUC by April 2022.

On July 15, 2021, the CPUC adopted a decision in the third track of this proceeding that would suspend the capacity reservation component of utility standby rates for eligible microgrids that meet California Air Resource Board air pollution standards for generation. The decision requires the IOUs to establish two-way balancing accounts to track costs associated with the suspension of the capacity reservation component of the standby charge, and to also track the revenue received from a new demand assurance charge mechanism, to true-up costs for future recovery from customers. According to the decision, in 2026, the CPUC will evaluate the effectiveness of the reservation capacity rate suspension and the adequacy of the demand assurance charge.

On June 30, 2021, the Utility filed a new application at the CPUC regarding the selection and procurement of substation-level microgrid projects for PSPS mitigation going forward. The application also proposes a framework for seeking cost recovery of selected projects. The CPUC’s schedule for the proceeding anticipates a final decision in summer 2022.

As described above, on September 16, 2021, the Utility filed its 2021 WMCE application. That application seeks, in part, to recover the costs that the Utility incurred in 2020 related to the microgrid-related programs approved in the OIR regarding microgrids. For more information, see “2021 WMCE Application” above.

Failure to obtain a substantial or full recovery of costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

Regionalization Proposal

On June 30, 2020, the Utility filed its application for approval of its regionalization proposal with the CPUC. The Utility’s proposal would divide its service area into five new regions to further improve safety and reliability, core operations, and be more responsive to the needs of its customers. The Utility’s regionalization proposal describes the development of these regions, plans to hire new regional leadership, and a new regional organization structure. The Utility’s application requested the CPUC to approve a memorandum account to record any incremental costs the Utility incurs in connection with the development and implementation of regionalization. The memorandum account proposal was approved on October 2, 2020. On June 1, 2021, the Utility announced the hiring of five regional vice presidents and five regional safety directors.

On August 31, 2021, the Utility and a majority of active parties in the proceeding reached settlement on all issues in the proceeding and filed a joint motion with the CPUC seeking approval of the settlement agreement. Opening comments on the settlement were filed by the non-settling parties on September 10, 2021. On September 17, 2021, the Utility filed joint reply comments with some settling parties, while other individual settling parties filed separate reply comments with the CPUC. A decision is expected by the first quarter of 2022.

Wildfire Fund Non-Bypassable Charge

On March 4, 2021, the CPUC issued a final decision which created a new rulemaking regarding the amount of the Wildfire Fund NBC in 2022 and 2023. The Utility expects a final decision on the 2022 Wildfire Fund NBC in December 2021 and a final decision on the 2023 Wildfire Fund NBC in December 2022.

Transportation Electrification

As previously disclosed, on February 3, 2020, in a rulemaking to consider further utility-sponsored programs to support electric vehicles and transportation electrification, the CPUC issued a draft Transportation Electrification Framework (“TEF”) for review and comment. On July 21, 2021, the CPUC issued a decision providing guidelines for the IOUs to apply for transportation electrification investments for near-term priority areas to meet 2025 state goals, while the CPUC further considers the overall TEF in a future decision.

On October 26, 2021, the Utility filed an application with the CPUC requesting that the CPUC authorize a revenue requirement of $224 million from 2023 through 2030 to support behind-the-meter electric vehicle charging infrastructure, installation of charging ports for multifamily housing residents and related programs.

The Utility is unable to predict the timing and outcome of these proceedings.

OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas Planning

As previously disclosed, on January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the greenhouse gas reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding examines whether recent industry-related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders.

On February 26, 2021, the ALJ issued a ruling seeking comments regarding penalties and financial incentives and potential mechanisms for implementation. Other questions included whether the CPUC should establish new rules to attempt to decrease the risk of electricity price volatility caused by potential gas supply issues and if certain pipeline operating procedures should be uniform across the state. On March 30, 2021, several parties filed a joint motion to suspend the procedural schedule for tracks 1A and 1B due to inadequate time to prepare testimony if determined by the CPUC to be necessary. In accordance with the amended procedural schedule, on April 2, 2021, parties filed motions regarding the need to serve testimony, file briefs or request evidentiary hearings in track 1. On April 15, 2021, the ALJ issued a ruling suspending the amended procedural schedule. On June 25, 2021, the ALJ issued a ruling requesting comments on a CPUC staff proposal to impose daily financial penalties on a gas utility for failing to meet an annual backbone capacity standard for more than nine months. The Utility filed comments on July 30, 2021. Reply comments were filed August 16, 2021. Opening briefs on track 1 issues were filed on October 15, 2021, and reply briefs were filed on October 29, 2021. A proposed decision on track 1 issues is expected in December 2021.

On October 14, 2021, the assigned commissioner issued an amended scoping memo and ruling setting forth an expanded scope and schedule for track 2 of the proceeding, which will develop and implement a long-term gas planning strategy for California. Opening comments on the amended scoping memo will be filed by November 2, 2021, and reply comments will be filed by November 12, 2021.

OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California.

On May 30, 2019, the CPUC approved a decision for phase 1 of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs.

On May 28, 2020, the CPUC adopted PSPS phase 2 guidelines, which require utilities to restore energy within 24 hours after the end of a PSPS event where possible; to consult with critical facilities on back-up power for PSPS events; and to support access and functional needs populations during PSPS events, including powering medical equipment at customer resource centers.

On December 2, 2020, the Utility and other parties submitted comments in this proceeding in response to an August 3, 2020 scoping ruling regarding SED’s report in a separate PSPS-related proceeding, OII to Examine the Late 2019 Public Safety Power Shutoff Events. In their comments, the Utility and other parties commented that issues raised in SED’s report should be addressed in a phase 3 of this OIR rulemaking proceeding.

On June 24, 2021, the CPUC adopted PSPS phase 3 guidelines, which require utilities to submit annual pre- and post- season reports, and establish requirements for accessibility, notification, and training. The phase 3 guidelines also clarify that the CPUC may review the reasonableness of a decision to initiate a PSPS event at any time and that IOUs must ensure customers are able to use medical equipment during PSPS events.

On November 12, 2019, the assigned commissioner and ALJ issued an order to show cause directing the Utility to show why it should not be sanctioned for the PSPS events of October 9-12, 2019, October 23-25, 2019, and October 26-November 1, 2019.

On May 26, 2021, the presiding officer issued a POD finding that the Utility was not reasonable in its implementation of these PSPS events. The POD proposed a penalty of $106 million, which would be offset by $86 million in bill credits that the Utility had already provided to customers. On June 25, 2021, the Utility filed an appeal of the POD arguing that no penalty should be imposed beyond the previously issued bill credits. That same day, the California Large Energy Consumers Association also filed an appeal asking that some portion of the bill credits be distributed to industrial customers. The Utility and others filed responses to the appeals on July 12, 2021. On September 23, 2021, the CPUC issued a modified POD regarding alleged violations in the Utility’s implementation of the 2019 PSPS events and reflected the same $106 million penalty amount as the May 26, 2021 POD. On October 29, 2021, the Utility filed an application for rehearing.

OII to Examine the Late 2019 Public Safety Power Shutoff Events

On November 13, 2019, the CPUC issued an OII to determine “whether California’s IOUs prioritized safety and complied with the CPUC’s regulations and requirements with respect to their PSPS events in late 2019.” The first phase of this proceeding focuses on (1) the effectiveness of the utilities’ procedures to notify the public of the PSPS events, (2) the utilities’ communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utilities’ management of their resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or GOs have been committed and to enforce compliance, if necessary.

On August 3, 2020, the assigned commissioner issued a ruling and scoping memo directing parties to file comments regarding: (1) whether the Utility and other large electric IOUs in October and November 2019 complied with the criteria set forth in applicable laws and regulations when pro-actively deenergizing and re-energizing their power lines, and (2) what corrective actions the CPUC should require of the Utility and other large electric IOUs for any failure in late 2019 to comply with the then-existing PSPS guidelines. Each of the large electric IOUs filed their comments on September 2, 2020, intervenors filed their comments on October 16, 2020, and reply comments were filed by all parties on November 16, 2020. Several parties proposed in their comments that penalties be imposed on the utilities for inadequate implementation of the PSPS events. For example, TURN proposed that the CPUC should treat each customer affected by a PSPS event, for which the utility has not adequately demonstrated that the benefits outweigh the public safety risks, as a separate offense, with each offense subject to a penalty of no less than $500 and no more than $100,000. In reply comments, the Utility argued that the proposed penalties should not be adopted for procedural and substantive reasons.

On March 10, 2021, the presiding judge directed the Utility and the other large electric IOUs to provide an accounting of the PSPS events that occurred in their service territories in calendar years 2019 and 2020 and how those PSPS events impacted revenue collections. On April 7, 2021, the Utility and San Diego Gas & Electric submitted their accountings. The Utility estimated the revenue impact from the 2019 PSPS and 2020 PSPS events at approximately $14 million and $5 million, respectively.

On April 20, 2021, the CPUC issued a PD in the case that found each of the large electric IOUs to be noncompliant with CPUC-required guidelines in certain of their 2019 PSPS events. The PD proposed a financial remedy and a number of corrective actions. The financial remedy would consist of forgoing collection of revenues from customers associated with electricity not sold during future PSPS events until it can be demonstrated that the utilities have made improvements in assessing public harm when determining whether to initiate a PSPS event. The corrective actions involve the Utility’s processes, reporting, and other aspects of its PSPS program. The CPUC’s final decision was issued on June 7, 2021 and modified some of the PD’s corrective actions but retained the financial remedy. On July 7, 2021, the Acton Town Council filed an application to rehear the decision. Responses to the application for rehearing were filed on July 22, 2021.

The Utility is unable to predict the outcome of this proceeding.

Power Charge Indifference Adjustment OIR

On May 20, 2021 the CPUC approved a final decision, removing the power charge indifference adjustment rate cap and trigger mechanism and adopting a limited proposal for portfolio management focused only on the Utility’s renewables portfolio standard eligible resources. On June 23, 2021, six parties filed a joint application for rehearing. On July 8, 2021, the Utility filed reply comments. The CPUC has not ruled on the joint application for rehearing.

Central Procurement of the Resource Adequacy Program

On June 17, 2020, the CPUC issued a decision providing guidance on the CPE function within the RA program. The decision shifts local RA procurement responsibility under the CPUC’s RA program from all LSEs to a CPE in two distribution service areas, including the Utility’s distribution service area, resulting in a change from decentralized to centralized local RA procurement in those distribution service areas. The decision also adopted implementation details for the central procurement of multi-year local RA, ordered the Utility and another IOU to serve as the CPE for their respective distribution service areas, and adopted a hybrid central procurement framework for the multi-year local RA program beginning for the 2023 RA compliance year.

The decision requires the Utility, as the CPE for its distribution service area, to conduct a competitive, all-source solicitation for local RA procurement, with any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, or any LSE or third-party with an existing local RA contract eligible to bid into the solicitation.

On December 3, 2020, the CPUC issued a follow-up decision adopting a compensation mechanism applicable to certain local resources that may be procured by the CPE for purposes of reducing the total CPE procurement requirements. This mechanism applies to new preferred local resources and new local energy storage resources, including utility-owned generation. Procurement by the Utility of, and compensation for, such resources will occur outside of the competitive, all-source solicitation.

The cost allocation mechanism methodology is adopted as the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function. The administrative costs incurred in serving the central procurement entity function will also be recoverable under the cost allocation mechanism.

On January 29, 2021, the Utility submitted an advice letter seeking approval by the CPUC’s energy division of a detailed CPE procurement plan. On March 25, 2021, the CPUC’s energy division issued a disposition letter converting the advice letter into an information-only submittal, which does not require approval by the CPUC.

On April 23, 2021, the Utility issued the 2021 CPE local RA request for offers in furtherance of fulfilling its obligations as CPE under the above-referenced CPUC decisions. The Utility executed the agreements resulting from its request for offers in September 2021.

Integrated Resource Planning Procurement

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision requires incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period 2021-2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision requires that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directs the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision.

The Utility has procured its required RA capacity for the August 1, 2021 milestone from third parties through CPUC-approved contracts for lithium-ion battery energy storage resources with terms ranging from 10-15 years. On December 22, 2020, the Utility filed an advice letter seeking CPUC approval of an additional group of similar contracts that would satisfy the balance of the Utility’s procurement obligations for the August 1, 2022 and August 1, 2023 milestones. On April 15, 2021, the CPUC approved the contracts.

The CPUC is developing a modified cost allocation mechanism methodology, under which the Utility will be able to recover procurement and administrative costs it incurs in serving the backstop procurement function.

On June 24, 2021, the CPUC unanimously adopted a decision to address incremental system reliability needs between 2024 and 2026 due to, in part, the pending retirements of Diablo Canyon and once-through-cooling natural gas plants in Southern California by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs subject to the CPUC’s integrated resource planning authority. The decision sets procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision sets the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

On August 17, 2021, the CPUC issued a ruling seeking comments on a preferred resource portfolio for use in the integrated resource planning proceeding and by the CAISO in the 2022-2023 transmission planning process. The Utility filed opening and reply comments on September 27, 2021 and October 11, 2021, respectively. A final decision is expected before the end of 2021.

OIR to Further Develop a Risk-Based Decision-Making Framework for Electric and Gas Utilities

On July 20, 2020, the CPUC initiated a rulemaking proceeding to consider ways to strengthen the risk-based decision-making framework that regulated energy utilities use to assess, manage, mitigate and minimize safety risks. The rulemaking will build on requirements for a utility risk framework adopted in the first Safety Model Assessment Proceeding. The CPUC’s goal is to further the prioritization of safety by electric and gas utilities.

On November 2, 2020, the assigned commissioner issued a scoping memo establishing the scope, schedule, and categorization for phase 1 and phase 2 of the proceeding. Phase 1, which began November 2020, is considering (i) clarifications to the technical requirements of the risk-based decision-making framework; (ii) safety and operational performance metrics; and (iii) refining procedural requirements for the risk assessment mitigation phase report.

On November 17, 2020, the assigned commissioner issued a ruling regarding the development of safety and operational metrics for the Utility. The ruling directed the Utility to propose metrics that are “suitable for the use as triggering events as specified in the Enhanced Oversight and Enforcement Process” and “suitable, over time, for the Commission, intervenors, and the public to potentially use to gauge the safety and operational performance of all gas and electric IOUs.” On January 15, 2021, the Utility filed a response proposing 12 safety and operational metrics using the criteria outlined by the ruling. On January 25, 2021, parties filed responses to the Utility’s proposal.

On June 4, 2021, the ALJ issued a ruling incorporating a staff proposal regarding the Utility’s safety and operational metrics. The proposal recommends 40 safety and operational metrics addressing worker and contractor safety, electric safety risks, reliability, gas safety risks, customer satisfaction, and clean energy goals. Parties filed opening and reply comments seeking modifications to the proposal on June 29 and July 9, 2021, respectively.

On September 17, 2021, the CPUC issued a PD on phase 1. The PD refines the risk-based decision-making framework; adopts 32 safety and operational metrics, which can serve as triggering events in the EOEP; requires the Utility to report on performance against these metrics on a semi-annual basis; and adopts 10 new and 19 updated safety performance metrics which the Utility will be required to include in the annual Safety Performance Metrics Report. The CPUC is scheduled to vote on the PD on November 4, 2021.

OIR to Revisit Net Energy Metering Tariffs

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 19, 2020, the assigned commissioner and the ALJ issued a scoping memo and ruling for this proceeding. The scoping memo separated the proceeding into two phases. In the first phase, the CPUC will address several issues, including determining the principles to assist in the development and evaluation of a successor to the current NEM tariffs, assessing what information from a study on existing tariffs should inform the successor, outlining the methods to use to analyze the program elements and the resulting proposals, and determining the program elements or specific features that should be included in the successor tariff. In the second phase, the CPUC will consider what additional or enhanced consumer protections for customers should be adopted, as well as other issues that may arise, such as the virtual net energy metering tariffs, NEM aggregation tariff, the Renewable Energy Self-Generation Bill Credit Transfer program, and the NEM fuel cell tariff.

On February 11, 2021, the CPUC issued a final decision that outlined certain guiding principles to assist in the development and evaluation of proposals for the successor to the current NEM tariff.

Parties submitted opening testimony on June 18, 2021 and rebuttal testimony on July 16, 2021. Evidentiary hearings commenced on July 26, 2021. Opening briefs were filed on August 31, 2021 and reply briefs were filed September 14, 2021 by approximately 20 parties, including the joint IOUs.

OIR to Address Energy Utility Customer Debt Accumulated during the Coronavirus Pandemic

On February 11, 2021, the CPUC initiated a rulemaking proceeding to consider arrearage relief for utility customers with outstanding utility bills when the moratorium on service disconnections ended. The OIR will evaluate a more global program beyond the currently approved arrearage management program focused on low-income residential customers that is funded by the Utility’s customers. The OIR may consider various funding approaches for this expanded debt forgiveness proposal, which could include shareholder funding.

On June 30, 2021, the CPUC issued a final decision directing the Utility and other IOUs to automatically enroll residential customers and small business customers more than 60 days in arrears in payment plans. The decision also set forth an intent to revisit additional remaining issues initially scoped in the proceeding, including incorporation of state and federally funded arrearage relief. The decision also extended the moratorium on service disconnections for residential and small business, as well as medium and large commercial and industrial customers through September 30, 2021.

On July 29, 2021, the CPUC issued a scoping memo for the second phase of this proceeding. The Utility submitted a brief on issues relating to CCAs on August 27, 2021. On September 13, 2021, the Utility filed comments on the remaining issues from the scoping memo. The CPUC issued a PD on the CCA issues on October 15, 2021. The PD determines that the utilities must allocate payments received on outstanding customer accounts proportionately between utility charges and CCAs through September 2024, regardless of customer disconnection status. Comments on the PD are due November 4, 2021 and replies are due November 9, 2021.

Self-Reports to the CPUC

The Utility self-reports certain errors and omissions to the CPUC. The Utility could face penalties, enforcement action, or other adverse legal or regulatory consequences for these errors or omissions, including under the EOEP. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

Electric Asset Inspections

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 (including failure to perform inspections in compliance with GO 165 of approximately 55,000 poles in 2020) 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 in the future. 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.

The Utility continues to evaluate whether there are additional failures to comply with GOs 95 and 165 and the 2020 WMP, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews.

Subsurface Electric Ducts

On October 21, 2021, the Utility notified the CPUC of inconsistent application of the requirements to locate and mark empty subsurface electric ducts in accordance with Government Code section 4216(k), 4216(s) and 4216.3(a)(1)(A).

Rate Cases

2023 General Rate Case

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC. In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC.

In a GRC, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). For its 2023 test year, the Utility has requested revenue requirements of $15.46 billion, an increase of $3.56 billion over the adopted 2020 GRC and 2019 GT&S revenue requirements for 2022 of $11.90 billion. The GRC application further states that the Utility’s requested 2023 revenue requirements represent a 9.6% increase over its total revenue requirements for 2022 (including both amounts that are authorized and that are requested outside of the GRC and remain subject to the regulatory process). The requested weighted-average GRC rate base for 2023 is approximately $48.52 billion, which corresponds to an increase of $9.35 billion over the authorized rate base for 2022 of $39.17 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized GRC revenues in 2024, 2025, and 2026 by $930 million, $590 million, and $381 million, respectively. The Utility estimates its proposed revenue requirements for 2024, 2025, and 2026 would result in revenue requirement increases of 2.4%, 1.9%, and 1.5%, compared to its total estimated revenue requirements for 2023, 2024, and 2025, respectively. Over the 2023-2026 GRC period, the Utility plans to make average annual capital investments of approximately $7.75 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

The following table compares the Utility’s initial requested revenue requirements for 2023 with the comparable revenue requirements currently authorized for 2022, by both line of business and cost category:

Line of Business (1)			Amounts requested in the 2023 GRC application						Amounts currently authorized for 2022 (2)						Requested increase compared to currently authorized amounts
(in millions)
Gas distribution			$	2,870					$	2,321					$	550
Gas transmission and storage			1,989						1,662						327
Electric distribution			8,171						5,514						2,657
Electric generation			2,431						2,404						26
Total revenue requirements			$	15,461					$	11,901					$	3,560

(1) May not sum due to rounding.

(2) These amounts include revenues from Decision (“D.”) 20-12-005 (the Utility’s 2020 GRC), D.19-09-025 (the Utility’s 2019 GT&S) adjusted for D.19-12-056 and Advice Letter (“AL”) 4275-G/5887-E (Cost of Capital changes adopted for Long Term Debt and Common Stock) and AL 4367-G/6062-E (Excess Accumulated Deferred Income Taxes Pursuant to the 2017 Tax Act). Also included are the 2022 adopted revenue requirements associated with the following previously separately-funded projects: AL 5322-E (Energy Storage), D.16-12-065 (Electric Vehicle Charging Network Phase I), D.14-03-021 (Mobile Home Park to the Meter), D.20-11-035 (2019 CEMA), AL 4392-G/6100-E (Wildfire Mitigation Balancing Account and Vegetation Management Balancing Account), AL 4444-G/6210-E (RTBA).

In the 2023 GRC application, the Utility proposes a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Among other things, the Utility proposes to invest a total of approximately $31 billion between 2023 and 2026 to reduce wildfire risk; improve gas and electric system safety, reliability, and resiliency; increase the use of new, innovative technologies; and expand its clean energy infrastructure.

In addition to coverage that may be available from the private insurance market, the Utility also proposes to use self-insurance as part of its wildfire insurance program as follows: (1) the Utility’s recommended approach, a new self-insurance structure whereby the Utility would seek customer-funded self-insurance in the amount of $250 million annually and traditional private insurance procurement for amounts between the accumulated self-insurance balance and $1.0 billion; or, alternatively (2) continuing the currently authorized mechanism whereby the Utility seeks procurement of wildfire liability insurance instruments through the private insurance market and is authorized to use any unspent authorized revenue requirements on self-insurance.

In addition, the Utility requests authorization to establish one new balancing account and one new memorandum account as follows:

• Catastrophic Events Straight-Time Labor Balancing Account, a two-way account which would recover straight-time labor costs associated with catastrophic events. These costs are currently recovered through the Catastrophic Events Memorandum Account process.

• Helms Capacity Memorandum Account, which would allow the Utility to track and recover the actual costs associated with upgrading the Helms Pumped Storage Facility through a future application.

The Utility is not seeking recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7.

On August 27, 2021, the Utility served supplemental testimony that would, if approved, reduce the requested revenue requirement in 2023 by approximately $100 million, primarily associated with gas transmission revenue requirements.

On October 1, 2021, the CPUC issued a scoping memo indicating that the CPUC will issue a decision on an initial track of the proceeding in the second quarter of 2023. The scoping memo also established a second track of the 2023 GRC to consider costs incurred from 2019 to 2021 that are recorded in balancing or memorandum accounts for, among other work, wildfire mitigation and gas system safety improvements. The second track will review more than $500 million in capital and $160 million in expense included in the Utility’s initial 2023 GRC application for the period from 2019 to 2020, plus additional costs recorded in memorandum and balancing accounts in 2021. The scoping memo indicates that the CPUC will issue a decision on the second track in the third quarter of 2023.

The Utility is unable to predict the timing and outcome of this application.

2022 Cost of Capital Proceeding

On August 23, 2021, the Utility filed an application with the CPUC, requesting that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 (the “2022 cost of capital application”).

In its 2022 cost of capital application, the Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), return on equity, cost of preferred stock, and cost of debt. The Utility proposed to establish for 2022 a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a return on equity of 11%, and to retain the existing capital structure. If authorized, this would result in a $201.3 million total increase above currently adopted in its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage revenue requirements. The estimated revenue increase is based on the 2022 adopted electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base and does not reflect projected infrastructure investments beyond 2022. The Utility also requested an increase of 159 basis points above the three-month commercial paper rate for interest on the balancing and memorandum accounts specified in the application, which would result in an estimated $58.7 million increase in recovery of short-term financing costs based on recent balancing account net under-collections. The actual revenue requirement impact of the short-term financing cost proposal will differ depending on the recorded balances in the balancing and memorandum accounts in 2022.

As an alternative to its proposal to adopt a new cost of capital for 2022, the Utility requested a suspension of the cost of capital mechanism formula adjustment mechanism in 2021 that, absent the filing of the 2022 cost of capital application, would adjust the cost of capital effective January 1, 2022. If the alternative proposal is granted, the Utility would maintain its current authorized rate of return on equity, would adjust its cost of long-term debt (using the methodology specified in the formula adjustment mechanism), and would file a regularly scheduled cost of capital application in April 2022 for the cost of capital beginning on January 1, 2023.

The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general and the Utility in particular to the same extent as the overall financial markets. The application explains that the filing of an off-cycle cost of capital application suspends the operation of the cost of capital formula adjustment mechanism. On October 28, 2021, the CPUC ruled that the application did not suspend the cost of capital formula adjustment mechanism.

For 2022, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $121.9 million for electric generation and distribution and $47.8 million for gas distribution operations, assuming 2022 authorized rate base amounts from the 2020 GRC decision. The revenues for the gas transmission and storage operations would increase by approximately $31.6 million, assuming 2022 authorized rate base amounts from the 2019 Gas Transmission and Storage Rate Case decision. However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2023 GRC, which is currently pending before the CPUC, the revenue requirement changes resulting from the Utility’s requested return on equity may differ from the amounts reflected in this cost of capital application for the period beyond 2022.

Parties filed protests to the Utility’s application on September 24, 2021. The Utility filed a reply on October 4, 2021.

By November 8, 2021, the Utility will file the materials which would have been included in the formula adjustment mechanism advice letter in the proceeding. The Utility is unable to predict the outcome of this application.

2020 Cost of Capital Proceeding

On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020. The decision maintains the common equity component of the Utility’s capital structure at 52%, and reduces its preferred stock component from 1% to 0.5%. The decision also approves the cost of debt requested by the Utility. The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remains unchanged. In any year in which the difference between the average Moody’s utility bond rates, as measured in the 12-month period from October through September (the index), and 4.5% (the benchmark) 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 must initiate this adjustment mechanism by filing an advice letter on or before October 15, to become effective on January 1 of the next year.

The cost of capital adjustment mechanism was triggered because the average Moody’s Baa- utility bond index in the 12-month period from October through September was 117 basis points below the Utility’s cost of capital benchmark rate of 4.5%.

On October 28, 2021, the CPUC ruled that the 2022 Cost of Capital application did not suspend the adjustment mechanism. By November 8, 2021, the Utility will file materials which would have been included in the October 15, 2021 advice letter in the 2022 Cost of Capital proceeding. See “2022 Cost of Capital Proceeding” above for more information.

2015 Gas Transmission and Storage Rate Case

As previously disclosed, in its final decision in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount forecast to be recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit. On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On July 7, 2021, a joint motion was filed to adopt a settlement agreement. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. On July 9, 2021, the ALJ granted a motion to include an additional party. The ALJ ruled that the party’s participation would be limited to commenting on the settlement agreement and proposed decision, and that the party may not broaden the current scope of issues or introduce new evidentiary information. Comments on the settlement agreement were due August 6, 2021. No party submitted comments on the settlement.

On November 10, 2020, the Utility filed a motion seeking approximately $100 million in interim rates, assuming the CPUC reaches a final decision in this matter in late 2021 or early 2022. The CPUC has not yet ruled upon the Utility’s motion.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder.

On March 17, 2020, the FERC issued an order denying requests for rehearing previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals. Oral argument was held on April 16, 2021. The Utility is unable to predict the timing and outcome of this proceeding.

For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7 of the 2020 Form 10-K.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

As previously disclosed, 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.

Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.9%, and an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period, proposed to remove certain items from the Utility’s rate base and revenue requirement, and rejected the Utility’s direct assignment of common plant to transmission and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios.

As previously disclosed, on October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order, 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 the FERC Opinion No. 569-A, issued on May 21, 2020. Initial briefs and testimony were filed on December 14, 2020 and responses were filed on February 12, 2021.

As previously disclosed, on December 17, 2020, the FERC denied all the pending requests for rehearing that were previously submitted by the Utility and intervenors. On February 11, 2021, the Utility filed a petition for review of the order in the Court of Appeals. On March 4, 2021, the Court of Appeals issued an order holding the Utility’s petition for review in abeyance until July 14, 2021 so that the FERC has time to issue a substantive order on rehearing. On April 15, 2021, the FERC issued a substantive order denying the Utility’s request for rehearing and granting the request for rehearing of two parties regarding the impact of the Tax Act on TO18 rates in January and February 2018. The Utility has sought rehearing of the FERC’s reversal on the applicability of the Tax Act on TO18 rates which may affect the timing for judicial review of the FERC order on the Utility’s request for rehearing. On June 8, 2021, the Utility filed a second petition for review in the Court of Appeals on aspects of the rehearing order other than the Tax Act. On June 17, 2021, the FERC issued a notice denying the Utility’s request for rehearing on the applicability of the Tax Act on TO18 rates by operation of law and providing for further consideration. On June 21, 2021, the Court of Appeals ordered that the Utility’s two petitions for review be consolidated and held both petitions in abeyance until July 14, 2021. On July 22, 2021, the Court of Appeals ordered that the Utility’s two petitions for review be held in abeyance until further order of the court and directed the parties to file motions to govern further proceedings within 75 days after the FERC issues a substantive order on the Utility’s request for rehearing on the applicability of the Tax Act on TO18 rates. On August 13, 2021, the Utility filed a third petition for review in the Court of Appeals from the FERC’s June 17, 2021 notice, which the Court of Appeals ordered be consolidated with the Utility’s prior two petitions and subject to the deadlines in the Court’s July 22, 2021 order. On August 19, 2021, the FERC issued a substantive order denying the Utility’s request for rehearing on the applicability of the Tax Act on TO18 rates. On October 15, 2021, the Utility filed a fourth petition for review in the Court of Appeals from the FERC’s August 19, 2021 rehearing order. The parties are required to file a motion to govern further proceedings in the Court of Appeals by November 2, 2021.

As a result of the FERC’s April 15, 2021 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 third quarter of 2021 by approximately $308 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 September 30, 2021, the Utility has recorded approximately $180 million to Regulatory assets.

Aside from the ultimate outcome of the common plant allocation, which is subject to further appellate briefing and a further FERC decision on ROE, the FERC’s April 15, 2021 order is 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. (See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

The Utility is unable to predict the timing and outcome of this proceeding.

For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7 of the 2020 Form 10-K.

Nuclear Decommissioning Cost Triennial Proceeding

While the Utility expects active decommissioning to begin soon after expiration of the current operating licenses, the Utility expects that the decommissioning of Diablo Canyon will take many years. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory, site restoration, and remediation requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

As previously disclosed, on December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion to decommission the Diablo Canyon facilities.

Also, as previously disclosed, on January 10, 2020, the settlement agreement that the parties had reached in this proceeding was filed with the CPUC, along with a joint motion for adoption of the settlement agreement. On September 9, 2021, the CPUC issued a final decision approving the settlement agreement with modifications and approving the Utility’s 2018 NDCTP application. Under the final decision, the Utility will collect annual revenue requirements of $112.5 million for the funding of the Diablo Canyon non-qualified trust over an eight-year period commencing January 1, 2022 and $3.9 million for funding of the Humboldt Bay tax qualified trust, subject to any revisions required by the outcome of the Utility’s 2021 NDCTP application, which will be submitted to the CPUC in December 2021. Additionally, the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs was deemed reasonable.

LEGISLATIVE AND REGULATORY INITIATIVES

Assembly Bill 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054. Eligible electric utility companies must declare a Coverage Year of exactly twelve months, that commences as of a certain date and time to the administrator of the Wildfire Fund.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to a principal amount of approximately $1.19 billion related to fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021. The CPUC issued a financing order authorizing the transaction on June 24, 2021.

Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. On July 1, 2020, having satisfied the conditions for the Utility’s participation in the Wildfire Fund, the Utility deposited approximately $5 billion in the Wildfire Fund, which represents the Utility’s initial and first annual contributions. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.

Assembly Bill 242, which was signed into law on September 23, 2021, expanded the definition of a “covered wildfire” from AB 1054 to also include those wildfires determined by a court of competent jurisdiction to be caused by an electrical corporation, and those wildfires asserted to have been caused by an electrical corporation that result in a court-approved dismissal resulting from the settlement of third-party damage claims.

Assembly Bill 135

On July 16, 2021 the California governor signed into law AB 135, a bill which implements a $1.0 billion appropriation to prevent service disconnections for utility customers experiencing financial hardship due to the COVID-19 pandemic by providing financing assistance to customer accounts in arrears. AB 135 sets aside $695 million for IOU electric and gas distribution customers. The Utility and the CCAs in its territory expect to receive $341 million to reduce the amounts owed by customer accounts in arrears. The amount of funding will be determined by the California Department of Community Services and Development, which is the agency responsible for administering the California Arrearage Payment Program.

Vaccine Mandates

On September 9, 2021, President Biden issued two EOs that could affect the Utility. One EO would require that all employers with at least 100 employees ensure that their employees are fully vaccinated for COVID-19 or obtain a negative COVID-19 test at least once a week. The implementation of this EO is still being developed by the Department of Labor’s Occupational Safety and Health Administration. The second EO would require certain COVID-19 precautions for government contractors and their subcontractors, including mandatory employee vaccination. The Utility has been requested to accept a bilateral modification to its federal contracts to implement the government contractor mandates. While the Utility supports vaccinations for its employees, the Utility has not agreed to the bilateral modification. The ultimate implementation of the two EOs could result in workplace disruptions, employee attrition and difficulty securing future labor needs.

ENVIRONMENTAL MATTERS

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 wastes; 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 Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.)

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and “Contractual Commitments” in Item 7 MD&A of the 2020 Form 10-K.

Off-Balance Sheet Arrangements

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 in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

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 2020 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, 2021.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, contributions to the Wildfire Fund, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting policies and their key characteristics are discussed in detail in the 2020 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.