NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
Organization and Basis of Presentation
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 primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.
This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).
The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2021 in the Condensed Consolidated Balance Sheets included in this Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2021 Form 10-K. This Form 10-Q should be read in conjunction with the 2021 Form 10-K.
The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.
NOTE 2: BANKRUPTCY FILING
Chapter 11 Proceedings
On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including provisions related to post-petition interest. PG&E Corporation and the Utility are unable to predict the timing and outcome of these appeals.
Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.
Unresolved Chapter 11 Claims
PG&E Corporation and the Utility have received over 100,000 proofs of claim since January 29, 2019, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and the Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims, including asserted litigation claims, trade creditor claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. Amounts expected to be allowed are reflected as current liabilities in the Condensed Consolidated Balance Sheets.
Holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).
In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 11 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 11 under the heading “Securities Class Action Litigation.”
In addition to filing objections in the Bankruptcy Court to claims that were subject to certain defenses which allowed PG&E Corporation and the Utility to file objections expunging those claims on an omnibus basis, PG&E Corporation and the Utility are working to resolve disputed claims, including Subordinated Debt Claims and HoldCo Rescission or Damage Claims. By order of the Bankruptcy Court, the current deadline for PG&E Corporation and the Utility to object to claims is December 19, 2022.
NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Revenue Recognition
Revenue from Contracts with Customers
The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.
Regulatory Balancing Account Revenue
The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.
The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
The following table presents the Utility’s revenues disaggregated by type of customer: | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Electric | | | | | | | |
| Revenue from contracts with customers | | | | | | | |
| Residential | $ | 1,213 | | | $ | 1,352 | | | $ | 2,707 | | | $ | 2,815 | |
| Commercial | 1,252 | | | 1,183 | | | 2,425 | | | 2,196 | |
| Industrial | 322 | | | 305 | | | 672 | | | 632 | |
| Agricultural | 484 | | | 431 | | | 700 | | | 583 | |
| Public street and highway lighting | 19 | | | 18 | | | 37 | | | 35 | |
Other (1) | (77) | | | 285 | | | (90) | | | 222 | |
| Total revenue from contracts with customers - electric | 3,213 | | | 3,574 | | | 6,451 | | | 6,483 | |
Regulatory balancing accounts (2) | 477 | | | 377 | | | 1,397 | | | 863 | |
| Total electric operating revenue | $ | 3,690 | | | $ | 3,951 | | | $ | 7,848 | | | $ | 7,346 | |
| | | | | | | |
| Natural gas | | | | | | | |
| Revenue from contracts with customers | | | | | | | |
| Residential | $ | 388 | | | $ | 418 | | | $ | 1,851 | | | $ | 1,626 | |
| Commercial | 197 | | | 139 | | | 541 | | | 384 | |
| Transportation service only | 356 | | | 346 | | | 755 | | | 672 | |
Other (1) | (88) | | | (137) | | | (267) | | | (184) | |
| Total revenue from contracts with customers - gas | 853 | | | 766 | | | 2,880 | | | 2,498 | |
Regulatory balancing accounts (2) | 575 | | | 498 | | | 188 | | | 87 | |
| Total natural gas operating revenue | 1,428 | | | 1,264 | | | 3,068 | | | 2,585 | |
| Total operating revenues | $ | 5,118 | | | $ | 5,215 | | | $ | 10,916 | | | $ | 9,931 | |
| | | | | | | |
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.
Variable Interest Entities
A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
Consolidated VIEs
Receivables Securitization Program
The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable, Other noncurrent assets, and Long-term debt, respectively, on the Condensed Consolidated Balance Sheets. As of June 30, 2022, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. As of July 21, 2022, the SPV has not made such request to increase the facility limit.
The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the six months ended June 30, 2022 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2022 and December 31, 2021, the SPV had net accounts receivable of $2.8 billion and $3.3 billion, respectively, and outstanding borrowings of $1.0 billion and $974 million, respectively, under the Receivables Securitization Program.
AB 1054 Securitization
PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The recovery bonds are scheduled to pay principal and interest semi-annually on January 15 and July 15 of each year. The final scheduled payment date is July 15, 2046. Amounts owed to bondholders are included in Long-term debt and Long-term debt, classified as current, on the Condensed Consolidated Balance Sheets.
PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the six months ended June 30, 2022 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $860 million.
SB 901 Securitization
PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property.
PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the six months ended June 30, 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). As of June 30, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $3.6 billion. On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). For more information, see Note 6 below.
Non-Consolidated VIEs
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of June 30, 2022, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of June 30, 2022, it did not consolidate any of them.
Contributions to the Wildfire Fund Established Pursuant to AB 1054
PG&E Corporation and the Utility account for contributions to the Wildfire Fund similarly to prepaid insurance, with expense being amortized to periods ratably based on an estimated period of coverage. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating that initial period of coverage, PG&E Corporation and the Utility started in 2019 with a dataset of 12 years of historical, publicly available fire-loss data for the period from 2007 to 2018 for wildfires caused by electrical equipment to create Monte Carlo simulations of expected loss. For each year after 2019, PG&E Corporation and the Utility added the fire-loss data for the preceding year to the dataset. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.
PG&E Corporation and the Utility evaluate and, where appropriate, update all assumptions quarterly. Changes in any of the assumptions could materially impact the estimated period of coverage. In the first quarter of 2022, PG&E Corporation and the Utility updated assumptions related to the mitigation effectiveness and historical fire loss dataset to align with the 2022 WMP. These updates did not change the estimated period of coverage, which continues to be 15 years from the inception of the Wildfire Fund.
As of June 30, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in Current assets - Wildfire Fund asset, and $5.1 billion in Non-current assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2022 and 2021, the Utility recorded amortization and accretion expense of $117 million and $118 million, respectively. During the six months ended June 30, 2022 and 2021, the Utility recorded amortization and accretion expense of $235 million and $237 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. As of June 30, 2022, PG&E Corporation and the Utility had recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.
For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.
Pension and Other Post-Retirement Benefits
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.
The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2022 and 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Benefits |
| Three Months Ended June 30, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
Service cost for benefits earned (1) | $ | 144 | | | $ | 146 | | | $ | 16 | | | $ | 16 | |
| Interest cost | 173 | | | 162 | | | 14 | | | 13 | |
| Expected return on plan assets | (298) | | | (262) | | | (33) | | | (35) | |
| Amortization of prior service cost | (1) | | | (2) | | | 1 | | | 3 | |
| Amortization of net actuarial (gain) loss | 1 | | | 2 | | | (10) | | | (8) | |
| Net periodic benefit cost | 19 | | | 46 | | | (12) | | | (11) | |
Regulatory account transfer (2) | 64 | | | 37 | | | — | | | — | |
| Total | $ | 83 | | | $ | 83 | | | $ | (12) | | | $ | (11) | |
| | | | | | | |
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Benefits |
| Six Months Ended June 30, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
Service cost for benefits earned (1) | $ | 288 | | | $ | 293 | | | $ | 31 | | | $ | 32 | |
| Interest cost | 346 | | | 323 | | | 27 | | | 26 | |
| Expected return on plan assets | (595) | | | (523) | | | (65) | | | (70) | |
| Amortization of prior service cost | (2) | | | (3) | | | 3 | | | 7 | |
| Amortization of net actuarial (gain) loss | 1 | | | 3 | | | (20) | | | (16) | |
| Net periodic benefit cost | 38 | | | 93 | | | (24) | | | (21) | |
Regulatory account transfer (2) | 127 | | | 74 | | | — | | | — | |
| Total | $ | 165 | | | $ | 167 | | | $ | (24) | | | $ | (21) | |
| | | | | | | |
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) consisted of the following: | | | | | | | | | | | | | | | | | | | | | | | |
| Pension
Benefits | | Other
Benefits | | Customer Credit Trust | | Total |
| (in millions, net of income tax) | Three Months Ended June 30, 2022 |
| Beginning balance | $ | (33) | | | $ | 18 | | | $ | — | | | $ | (15) | |
| Other comprehensive income before reclassification | | | | | | | |
Loss on investments (net of taxes of $0, $0 and $2, respectively) | — | | | — | | | (5) | | | (5) | |
Amounts reclassified from other comprehensive income: (1) | | | | | | | |
Amortization of prior service cost (net of taxes of $0, $0 and $0, respectively) | (1) | | | 1 | | | — | | | — | |
Amortization of net actuarial (gain) loss (net of taxes of $0, $3 and $0, respectively) | 1 | | | (7) | | | — | | | (6) | |
Regulatory account transfer (net of taxes of $0, $3 and $0, respectively) | — | | | 6 | | | — | | | 6 | |
| Net current period other comprehensive loss | — | | | — | | | (5) | | | (5) | |
| Ending balance | $ | (33) | | | $ | 18 | | | $ | (5) | | | $ | (20) | |
| | | | | | | |
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
| | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other
Benefits | | Total |
| (in millions, net of income tax) | Three Months Ended June 30, 2021 |
| Beginning balance | $ | (38) | | | $ | 17 | | | $ | (21) | |
Amounts reclassified from other comprehensive income: (1) | | | | | |
Amortization of prior service cost (net of taxes of $1 and $1, respectively) | (1) | | | 2 | | | 1 | |
Amortization of net actuarial loss (net of taxes of $1 and $2, respectively) | 1 | | | (6) | | | (5) | |
Regulatory account transfer (net of taxes of $0 and $1, respectively) | — | | | 4 | | | 4 | |
| Net current period other comprehensive gain (loss) | — | | | — | | | — | |
| Ending balance | $ | (38) | | | $ | 17 | | | $ | (21) | |
| | | | | |
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension
Benefits | | Other
Benefits | | Customer Credit Trust | | Total |
| (in millions, net of income tax) | Six Months Ended June 30, 2022 |
| Beginning balance | $ | (33) | | | $ | 18 | | | $ | — | | | $ | (15) | |
| Other comprehensive income before reclassification | | | | | | | |
Loss on investments (net of taxes of $0, $0 and $2, respectively) | — | | | — | | | (5) | | | (5) | |
Amounts reclassified from other comprehensive income: (1) | | | | | | | |
Amortization of prior service cost (net of taxes of $0, $1 and $0, respectively) | (2) | | | 2 | | | — | | | — | |
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively) | 1 | | | (14) | | | — | | | (13) | |
Regulatory account transfer (net of taxes of $0, $5 and $0, respectively) | 1 | | | 12 | | | — | | | 13 | |
| Net current period other comprehensive loss | — | | | — | | | (5) | | | (5) | |
| Ending balance | $ | (33) | | | $ | 18 | | | $ | (5) | | | $ | (20) | |
| | | | | | | |
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
| | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other
Benefits | | Total |
| (in millions, net of income tax) | Six Months Ended June 30, 2021 |
| Beginning balance | $ | (39) | | | $ | 17 | | | $ | (22) | |
Amounts reclassified from other comprehensive income: (1) | | | | | |
Amortization of prior service cost (net of taxes of $1 and $2, respectively) | (2) | | | 5 | | | 3 | |
Amortization of net actuarial loss (net of taxes of $1 and $4, respectively) | 2 | | | (12) | | | (10) | |
Regulatory account transfer (net of taxes of $0 and $2, respectively) | 1 | | | 7 | | | 8 | |
| Net current period other comprehensive gain | 1 | | | — | | | 1 | |
| Ending balance | $ | (38) | | | $ | 17 | | | $ | (21) | |
| | | | | |
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Voluntary Separation Program
In the second quarter of 2022, PG&E Corporation and the Utility enacted a voluntary separation program (the “VSP”), which provides separation benefits to approximately 445 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility will account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance, which is expected to occur during the second half of 2022.
Financial Assets Measured at Amortized Cost – Credit Losses
PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of June 30, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets.
Trade Receivables
Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.
As of June 30, 2022, expected credit losses of $76 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. As of June 30, 2022, the RUBA current balancing accounts receivable balance was $95 million, CPPMA long-term regulatory asset balance was $12 million, and FERC long-term regulatory asset balance was not material.
Other Receivables and Available-For-Sale Debt Securities
Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 11 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of the claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for its available-for-sale debt securities. An impairment may exist if there is an intent to sell or a requirement to sell before recovery of the amortized basis. If such an impairment exists, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.
As of June 30, 2022, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Recently Adopted Accounting Standards
Debt
In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.
Accounting Standards Issued But Not Yet Adopted
Troubled Debt Restructurings and Vintage Disclosures
In March 2022, the FASB issued ASU No. 2022-02, Financial Instruments - Credit Losses (Topic 326): Troubled Debt Restructurings and Vintage Disclosures, which requires that an entity disclose current-period gross write-offs by year of origination for financing receivables and net investment in leases within the scope of Subtopic 326-20. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2023, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Long-term regulatory assets are comprised of the following: | | | | | | | | | | | |
| | Balance at |
| (in millions) | June 30, 2022 | | December 31, 2021 |
Pension benefits (1) | $ | 582 | | | $ | 708 | |
| Environmental compliance costs | 1,042 | | | 1,089 | |
Utility retained generation (2) | 110 | | | 133 | |
| Price risk management | 177 | | | 216 | |
Catastrophic event memorandum account (3) | 951 | | | 1,119 | |
Wildfire expense memorandum account (4) | 361 | | | 347 | |
Fire hazard prevention memorandum account (5) | 75 | | | 75 | |
Fire risk mitigation memorandum account (6) | 84 | | | 44 | |
Wildfire mitigation plan memorandum account (7) | 535 | | | 424 | |
Deferred income taxes (8) | 2,222 | | | 1,849 | |
Insurance premium costs (9) | 165 | | | 207 | |
Wildfire mitigation balancing account (10) | 287 | | | 273 | |
Vegetation management balancing account (11) | 1,557 | | | 1,411 | |
COVID-19 pandemic protection memorandum accounts (12) | 33 | | | 49 | |
Microgrid memorandum account (13) | 165 | | | 163 | |
Financing costs (14) | 190 | | | 175 | |
SB 901 securitization (15) | 5,492 | | | — | |
AROs in excess of recoveries (16) | 211 | | | — | |
| Other | 976 | | | 925 | |
| Total long-term regulatory assets | $ | 15,215 | | | $ | 9,207 | |
| | | |
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of June 30, 2022 and December 31, 2021, $52 million and $49 million in COVID-19 related costs was recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Recovery of WEMA costs is subject to CPUC review and approval.
(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.
(6) Includes costs associated with the 2019 WMP for the period from January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.
(7) Includes costs associated with the 2019 WMP for the period from June 5, 2019 through December 31, 2019, the 2020 WMP for the period from January 1, 2020 through December 31, 2020, the 2021 WMP for the period from January 1, 2021 through December 31, 2021 and the 2022 WMP for the period from January 1, 2022 through June 30, 2022. Recovery of WMPMA costs is subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for insurance costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.
(10) Includes costs associated with certain wildfire mitigation activities for the period from January 1, 2020 through June 30, 2022. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
(11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.
(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation cost, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of June 30, 2022, the Utility had recorded an under-collection of $12 million for small business customers. The remaining $21 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded an under-collection of $30 million for residential under-collections pending approval for recovery in the RUBA in addition to under-collections recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.
(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s Cost of Capital or other regulatory filings.
(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid via fixed recovery charges, which is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below.
(16) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 10 below.
Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following: | | | | | | | | | | | |
| | Balance at |
| (in millions) | June 30, 2022 | | December 31, 2021 |
Cost of removal obligations (1) | $ | 7,537 | | | $ | 7,306 | |
Recoveries in excess of AROs (2) | — | | | 388 | |
Public purpose programs (3) | 1,066 | | | 946 | |
Employee benefit plans (4) | 1,240 | | | 1,229 | |
Transmission tower wireless licenses (5) | 438 | | | 446 | |
SFGO sale (6) | 304 | | | 343 | |
SB 901 securitization (7) | 5,510 | | | — | |
| Other | 851 | | | 1,341 | |
Total long-term regulatory liabilities | $ | 16,946 | | | $ | 11,999 | |
| | | |
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 10 below.
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(4) Represents cumulative differences between incurred costs and amounts collected in rates for post-retirement medical, post-retirement life and long-term disability plans.
(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $438 million, $305 million and $133 million will be refunded to FERC and CPUC jurisdiction customers, respectively. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.
(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that is being distributed to customers over a five-year period, beginning in 2022.
(7) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits. The balance reflects qualifying shareholder tax benefits that PG&E Corporation has recognized to date, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares, upon which time PG&E Corporation will recognize the associated tax benefits related to the sale. See Note 6 below.
Regulatory Balancing Accounts
Current regulatory balancing accounts receivable and payable are comprised of the following:
| | | | | | | | | | | |
| Balance at |
| (in millions) | June 30, 2022 | | December 31, 2021 |
| Electric distribution | $ | 1,006 | | | $ | — | |
| Energy procurement | 673 | | | 310 | |
| Public purpose programs | 312 | | | 321 | |
Fire hazard prevention memorandum account (1) | — | | | 50 | |
Fire risk mitigation memorandum account (1) | — | | | 14 | |
Wildfire mitigation plan memorandum account (1) | — | | | 67 | |
Wildfire mitigation balancing account (2) | — | | | 91 | |
| General rate case memorandum accounts | 235 | | | 468 | |
| Vegetation management balancing account | 472 | | | 127 | |
| Insurance premium costs | 247 | | | 605 | |
| Wildfire expense memorandum account | — | | | 440 | |
| Residential uncollectibles balancing accounts | 95 | | | 127 | |
| Catastrophic event memorandum account | 315 | | | — | |
| Other | 515 | | | 379 | |
| Total regulatory balancing accounts receivable | $ | 3,870 | | | $ | 2,999 | |
| | | |
(1) Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.
(2) The balance as of June 30, 2022 is a $34 million payable and incorporated into the current regulatory balancing account payable table below in the “Other” line item.
| | | | | | | | | | | |
| Balance at |
| (in millions) | June 30, 2022 | | December 31, 2021 |
| Electric distribution | $ | — | | | $ | 121 | |
| Electric transmission | 457 | | | 24 | |
| Gas distribution and transmission | 17 | | | 83 | |
| Energy procurement | 98 | | | 211 | |
| Public purpose programs | 270 | | | 259 | |
| Nuclear decommissioning adjustment mechanism | 74 | | | 137 | |
| Other | 678 | | | 286 | |
| Total regulatory balancing accounts payable | $ | 1,594 | | | $ | 1,121 | |
For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.
NOTE 5: DEBT
Credit Facilities
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | Termination
Date | | Maximum Facility Limit | | Loans Outstanding | | Letters of Credit Outstanding | | Facility
Availability | |
| Utility revolving credit facility | June 2026 | | $ | 4,000 | | (1) | $ | 1,210 | | | $ | 790 | | | $ | 2,000 | | |
Utility Receivables Securitization Program (2) | September 2023 | | 1,000 | | (3) | 1,000 | | | — | | | — | | (3) |
| PG&E Corporation revolving credit facility | June 2024 | | 500 | | | — | | | — | | | 500 | | |
| Total credit facilities | | | $ | 5,500 | | | $ | 2,210 | | | $ | 790 | | | $ | 2,500 | | |
| | | | | | | | | | |
(1) Includes a $1.5 billion letter of credit sublimit.
(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above.
(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit (which was $1.0 billion as of June 30, 2022) 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. As of June 30, 2022, the Receivables Securitization Program had a maximum borrowing base of $1.0 billion and was fully drawn.
On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.
On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). The 364-Day 2022A Tranche Loans have a maturity date of April 3, 2023 and bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022A Tranche Loans on April 4, 2022. On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.
On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.
On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. As of July 21, 2022, the SPV has not made such request to increase the facility limit.
Long-Term Debt Issuances and Redemptions
Utility
On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes.
On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.
Intercompany Note Payable
As previously disclosed, 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. On June 17, 2022, this loan was repaid in full.
NOTE 6: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.
Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers, with the proceeds of the securitization used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. 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 (“CHT Decision”). As requested, the decision authorized 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 fixed recovery 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 to the customer credit trust of $2.0 billion, with $1.0 billion to be contributed 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.
On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable.
On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches:
| | | | | | | | | | | |
| Tranche | Amount | Interest Rate | Due Date |
| A-1 | $ | 540,000,000 | | 3.594 | % | June 1, 2032 |
| A-2 | $ | 540,000,000 | | 4.263 | % | June 1, 2038 |
| A-3 | $ | 360,000,000 | | 4.377 | % | June 3, 2041 |
| A-4 | $ | 1,260,000,000 | | 4.451 | % | December 1, 2049 |
| A-5 | $ | 900,000,000 | | 4.674 | % | December 1, 2053 |
The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.
On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision.
On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches:
| | | | | | | | | | | |
| Tranche | Amount | Interest Rate | Due Date |
| B-1 | $ | 613,080,000 | | 4.022 | % | June 1, 2033 |
| B-2 | $ | 600,000,000 | | 4.722 | % | June 1, 2039 |
| B-3 | $ | 500,040,000 | | 5.081 | % | June 3, 2043 |
| B-4 | $ | 1,149,960,000 | | 5.212 | % | December 1, 2049 |
| B-5 | $ | 1,036,920,000 | | 5.099 | % | June 1, 2054 |
The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024.
Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 10). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating Revenues for the three and six months ended June 30, 2022.
Also pursuant to the CHT decision, the Utility recorded a $5.5 billion SB 901 securitization regulatory asset (see Note 4), reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.51 billion SB 901 securitization regulatory liability (see Note 4), which represents certain shareholder tax benefits the Utility has recognized as of June 30, 2022 that will be returned to customers, net of amortization for the period. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. As a result of the initial recognition of the SB 901 securitization regulatory asset and liability, in the three and six months ended June 30, 2022, the Utility recorded a $40 million pre-tax charge, reflected in SB 901 securitization charge, net in the Condensed Consolidated Statements of Income. The SB 901 securitization charge, net is expected to increase in future periods as the aforementioned tax benefits are recognized and recorded within deferred income taxes.
The following table illustrates the financial statement impact upon establishment of the regulatory asset and liability:
| | | | | |
| (in millions) | |
SB 901 securitization regulatory assets | $ | 5,500 | |
SB 901 securitization regulatory liability | (5,540) | |
| SB 901 securitization charges, net | $ | (40) | |
NOTE 7: EQUITY
At the Market Equity Distribution Program
On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (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. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.
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 (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.
During the six months ended June 30, 2022, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of June 30, 2022, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings.
Ownership Restrictions in PG&E Corporation’s Amended Articles
Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). 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). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.
On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the 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, 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 owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,465,411,810 shares outstanding as of July 21, 2022, only 1,609,924,630 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of July 21, 2022, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of July 21, 2022 was 3.10% of the outstanding shares. On January 31, 2022 and April 14, 2022, the Fire Victim Trust exchanged 40,000,000 and 60,000,000 Plan Shares, respectively, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. The Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 100,000,000 shares resulted in an aggregate tax benefit of $337 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements in the six months ended June 30, 2022. As of July 21, 2022, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 100,000,000 shares of PG&E Corporation common stock in the aggregate.
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.
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.
On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million, which was paid on May 15, 2022, to holders of record on April 29, 2022. On June 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on August 15, 2022, to holders of record on July 29, 2022.
On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. No dividend is payable until declared by the Board of Directors of the Utility.
Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors of PG&E Corporation and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors of PG&E Corporation may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items. It is indeterminate as to when PG&E Corporation will commence the payment of dividends on its common stock.
NOTE 8: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, | | |
| (in millions, except per share amounts) | 2022 | | 2021 | | 2022 | | 2021 | | | | |
| Income available for common shareholders | $ | 356 | | | $ | 397 | | | $ | 831 | | | $ | 517 | | | | | |
| Weighted average common shares outstanding, basic | 1,987 | | | 1,985 | | | 1,987 | | | 1,985 | | | | | |
| Add incremental shares from assumed conversions: | | | | | | | | | | | |
| Employee share-based compensation | 8 | | | 5 | | | 8 | | | 5 | | | | | |
| Equity Units | 146 | | | 156 | | | 146 | | | 156 | | | | | |
| Weighted average common shares outstanding, diluted | 2,141 | | | 2,146 | | | 2,141 | | | 2,146 | | | | | |
| Total income per common share, diluted | $ | 0.17 | | | $ | 0.18 | | | $ | 0.39 | | | $ | 0.24 | | | | | |
For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
NOTE 9: DERIVATIVES
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.
Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.
Volume of Derivative Activity
The volumes of the Utility’s outstanding derivatives were as follows: | | | | | | | | | | | | | | | | | | | | |
| | | | | Contract Volume at |
| Underlying Product | | Instruments | | June 30, 2022 | | December 31, 2021 |
Natural Gas (1) (MMBtus (2)) | | Forwards, Futures and Swaps | | 226,068,548 | | | 173,361,635 | |
| | | Options | | 27,055,000 | | | 14,420,000 | |
| Electricity (Megawatt-hours) | | Forwards, Futures and Swaps | | 11,270,318 | | | 10,283,639 | |
| | Options | | 502,000 | | | 288,000 | |
| | | Congestion Revenue Rights (3) | | 221,557,712 | | | 239,857,610 | |
| | | | | | |
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Presentation of Derivative Instruments in the Financial Statements
As of June 30, 2022, the Utility’s outstanding derivative balances were as follows: | | | | | | | | | | | | | | | | | | | | | | | |
| | Commodity Risk |
| (in millions) | Gross Derivative
Balance | | Netting | | Cash Collateral | | Total Derivative
Balance |
| Current assets – other | $ | 83 | | | $ | (21) | | | $ | 67 | | | $ | 129 | |
| Other noncurrent assets – other | 163 | | | — | | | — | | | 163 | |
| Current liabilities – other | (124) | | | 21 | | | 21 | | | (82) | |
| Noncurrent liabilities – other | (177) | | | — | | | — | | | (177) | |
| Total commodity risk | $ | (55) | | | $ | — | | | $ | 88 | | | $ | 33 | |
As of December 31, 2021, the Utility’s outstanding derivative balances were as follows: | | | | | | | | | | | | | | | | | | | | | | | |
| | Commodity Risk |
| (in millions) | Gross Derivative
Balance | | Netting | | Cash Collateral | | Total Derivative
Balance |
| Current assets – other | $ | 58 | | | $ | (9) | | | $ | 152 | | | $ | 201 | |
| Other noncurrent assets – other | 169 | | | — | | | — | | | 169 | |
| Current liabilities – other | (53) | | | 9 | | | 18 | | | (26) | |
| Noncurrent liabilities – other | (216) | | | — | | | — | | | (216) | |
| Total commodity risk | $ | (42) | | | $ | — | | | $ | 170 | | | $ | 128 | |
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.
Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of June 30, 2022, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
NOTE 10: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
•Level 3 – Unobservable inputs which are supported by little or no market activities.
The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements |
| | At June 30, 2022 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting (1) | | Total |
| Assets: | | | | | | | | | |
| Short-term investments | $ | 197 | | | $ | — | | | $ | — | | | $ | — | | | $ | 197 | |
| Fixed-income securities | — | | | 50 | | | — | | | — | | | 50 | |
| Nuclear decommissioning trusts | | | | | | | | | |
| Short-term investments | 60 | | | — | | | — | | | — | | | 60 | |
| Global equity securities | 1,826 | | | — | | | — | | | — | | | 1,826 | |
| Fixed-income securities | 1,089 | | | 850 | | | — | | | — | | | 1,939 | |
| Assets measured at NAV | — | | | — | | | — | | | — | | | 25 | |
Total nuclear decommissioning trusts (2) | 2,975 | | | 850 | | | — | | | — | | | 3,850 | |
Customer credit trust | | | | | | | | | |
| Short-term investments | 43 | | | 55 | | | — | | | — | | | 98 | |
| Global equity securities | 132 | | | — | | | — | | | — | | | 132 | |
| Fixed-income securities | 101 | | | 147 | | | — | | | — | | | 248 | |
Total customer credit trust | 276 | | | 202 | | | — | | | — | | | 478 | |
| Price risk management instruments (Note 9) | | | | | | | | | |
| Electricity | — | | | 26 | | | 205 | | | 25 | | | 256 | |
| Gas | — | | | 15 | | | — | | | 21 | | | 36 | |
| Total price risk management instruments | — | | | 41 | | | 205 | | | 46 | | | 292 | |
| Rabbi trusts | | | | | | | | | |
| Fixed-income securities | — | | | 96 | | | — | | | — | | | 96 | |
| Life insurance contracts | — | | | 68 | | | — | | | — | | | 68 | |
| Total rabbi trusts | — | | | 164 | | | — | | | — | | | 164 | |
| Long-term disability trust | | | | | | | | | |
| Short-term investments | 8 | | | — | | | — | | | — | | | 8 | |
| Assets measured at NAV | — | | | — | | | — | | | — | | | 131 | |
| Total long-term disability trust | 8 | | | — | | | — | | | — | | | 139 | |
| TOTAL ASSETS | $ | 3,456 | | | $ | 1,307 | | | $ | 205 | | | $ | 46 | | | $ | 5,170 | |
| Liabilities: | | | | | | | | | |
| Price risk management instruments (Note 9) | | | | | | | | | |
| Electricity | $ | — | | | $ | 75 | | | $ | 194 | | | $ | (29) | | | $ | 240 | |
| Gas | — | | | 32 | | | — | | | (13) | | | 19 | |
| TOTAL LIABILITIES | $ | — | | | $ | 107 | | | $ | 194 | | | $ | (42) | | | $ | 259 | |
| | | | | | | | | |
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $559 million primarily related to deferred taxes on appreciation of investment value.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements |
| | December 31, 2021 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting (1) | | Total |
| Assets: | | | | | | | | | |
| Short-term investments | $ | 289 | | | $ | — | | | $ | — | | | $ | — | | | $ | 289 | |
| Nuclear decommissioning trusts | | | | | | | | | |
| Short-term investments | 22 | | | — | | | — | | | — | | | 22 | |
| Global equity securities | 2,504 | | | — | | | — | | | — | | | 2,504 | |
| Fixed-income securities | 1,158 | | | 866 | | | — | | | — | | | 2,024 | |
| Assets measured at NAV | — | | | — | | | — | | | — | | | 31 | |
Total nuclear decommissioning trusts (2) | 3,684 | | | 866 | | | — | | | — | | | 4,581 | |
| Price risk management instruments (Note 9) | | | | | | | | | |
| Electricity | — | | | 9 | | | 214 | | | 6 | | | 229 | |
| Gas | — | | | 4 | | | — | | | 137 | | | 141 | |
| Total price risk management instruments | — | | | 13 | | | 214 | | | 143 | | | 370 | |
| Rabbi trusts | | | | | | | | | |
| Fixed-income securities | — | | | 104 | | | — | | | — | | | 104 | |
| Life insurance contracts | — | | | 76 | | | — | | | — | | | 76 | |
| Total rabbi trusts | — | | | 180 | | | — | | | — | | | 180 | |
| Long-term disability trust | | | | | | | | | |
| Short-term investments | 6 | | | — | | | — | | | — | | | 6 | |
| Assets measured at NAV | — | | | — | | | — | | | — | | | 132 | |
| Total long-term disability trust | 6 | | | — | | | — | | | — | | | 138 | |
| TOTAL ASSETS | $ | 3,979 | | | $ | 1,059 | | | $ | 214 | | | $ | 143 | | | $ | 5,558 | |
| Liabilities: | | | | | | | | | |
| Price risk management instruments (Note 9) | | | | | | | | | |
| Electricity | — | | | 11 | | | 248 | | | (24) | | | 235 | |
| Gas | — | | | 10 | | | — | | | (3) | | | 7 | |
| TOTAL LIABILITIES | $ | — | | | $ | 21 | | | $ | 248 | | | $ | (27) | | | $ | 242 | |
| | | | | | | | | |
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the three and six months ended June 30, 2022 and 2021.
Trust Assets
Assets Measured at Fair Value
In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets, Customer credit trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds classified as Level 1.
Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.
Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.
Level 3 Measurements and Uncertainty Analysis
Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. See Note 9 above. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fair Value at | | | | | | |
| (in millions) | | At June 30, 2022 | | Valuation
Technique | | Unobservable
Input | | |
| Fair Value Measurement | | Assets | | Liabilities | | | | Range (1)/Weighted-Average Price (2) |
| Congestion revenue rights | | $ | 172 | | | $ | 90 | | | Market approach | | CRR auction prices | | $ (2,265.69) - 2,265.94 / 0.39 |
| Power purchase agreements | | $ | 33 | | | $ | 104 | | | Discounted cash flow | | Forward prices | | $ (6.89) - 186.92 / 56.24 |
| | | | | | | | | | |
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fair Value at | | | | | | |
| (in millions) | | At December 31, 2021 | | Valuation
Technique | | Unobservable
Input | | |
| Fair Value Measurement | | Assets | | Liabilities | | | | Range (1)/Weighted-Average Price (2) |
| Congestion revenue rights | | $ | 188 | | | $ | 93 | | | Market approach | | CRR auction prices | | $ (40.77) - 2,265.94 / 0.40 |
| Power purchase agreements | | $ | 26 | | | $ | 155 | | | Discounted cash flow | | Forward prices | | $ (7.97) - 256.20 / 47.17 |
| | | | | | | | | | |
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2022 and 2021, respectively: | | | | | | | | | | | |
| | Price Risk Management Instruments |
| (in millions) | 2022 | | 2021 |
| Liability balance as of April 1 | $ | (24) | | | $ | (94) | |
| Net realized and unrealized gains: | | | |
Included in regulatory assets and liabilities or balancing accounts (1) | 35 | | | 76 | |
| Asset (Liability) balance as of June 30 | $ | 11 | | | $ | (18) | |
| | | |
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
| | | | | | | | | | | |
| | Price Risk Management Instruments |
| (in millions) | 2022 | | 2021 |
| Liability balance as of January 1 | $ | (34) | | | $ | (72) | |
| Net realized and unrealized gains: | | | |
Included in regulatory assets and liabilities or balancing accounts (1) | 45 | | | 54 | |
| Asset (Liability) balance as of June 30 | $ | 11 | | | $ | (18) | |
| | | |
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Financial Instruments
PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of June 30, 2022 and December 31, 2021, as they are short-term in nature.
The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): | | | | | | | | | | | | | | | | | | | | | | | |
| | At June 30, 2022 | | At December 31, 2021 |
| (in millions) | Carrying Amount | | Level 2 Fair Value | | Carrying Amount | | Level 2 Fair Value |
| Debt (Note 5) | | | | | | | |
PG&E Corporation | $ | 4,617 | | | $ | 4,239 | | | $ | 4,619 | | | $ | 4,796 | |
| Utility | 34,220 | | | 29,096 | | | 31,816 | | | 35,803 | |
Nuclear Decommissioning Trust Investments
The following table provides a summary of equity securities and available-for-sale debt securities: | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | Amortized
Cost | | Total
Unrealized
Gains | | Total
Unrealized
Losses | | Total Fair
Value |
| As of June 30, 2022 | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | |
| Short-term investments | $ | 60 | | | $ | — | | | $ | — | | | $ | 60 | |
| Global equity securities | 423 | | | 1,443 | | | (15) | | | 1,851 | |
| Fixed-income securities | 2,029 | | | 20 | | | (110) | | | 1,939 | |
Total (1) | $ | 2,512 | | | $ | 1,463 | | | $ | (125) | | | $ | 3,850 | |
| As of December 31, 2021 | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | |
| Short-term investments | $ | 22 | | | $ | — | | | $ | — | | | $ | 22 | |
| Global equity securities | 479 | | | 2,066 | | | (10) | | | 2,535 | |
| Fixed-income securities | 1,938 | | | 98 | | | (12) | | | 2,024 | |
Total (1) | $ | 2,439 | | | $ | 2,164 | | | $ | (22) | | | $ | 4,581 | |
| | | | | | | |
(1) Represents amounts before deducting $559 million and $783 million as of June 30, 2022 and December 31, 2021, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of fixed-income securities by contractual maturity is as follows: | | | | | |
| | As of |
| (in millions) | June 30, 2022 |
| Less than 1 year | $ | 11 | |
| 1–5 years | 620 | |
| 5–10 years | 461 | |
| More than 10 years | 847 | |
| Total maturities of fixed-income securities | $ | 1,939 | |
The following table provides a summary of activity for the fixed-income and equity securities:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| (in millions) | 2022 | | 2021 | | 2022 | | 2021 |
| Proceeds from sales and maturities of nuclear decommissioning trust investments | $ | 948 | | | $ | 401 | | | $ | 1,369 | | | $ | 952 | |
| Gross realized gains on securities | 81 | | | 74 | | | 137 | | | 129 | |
| Gross realized losses on securities | (58) | | | (3) | | | (65) | | | (16) | |
Customer Credit Trust
The following table provides a summary of equity securities and available-for-sale debt securities:
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | Amortized
Cost | | Total
Unrealized
Gains | | Total
Unrealized
Losses | | Total Fair
Value |
| As of June 30, 2022 | | | | | | | |
| Customer credit trust | | | | | | | |
| Short-term investments | $ | 98 | | | $ | — | | | $ | — | | | $ | 98 | |
| Global equity securities | 139 | | | — | | | (7) | | | 132 | |
| Fixed-income securities | 248 | | | 1 | | | (1) | | | 248 | |
Total | $ | 485 | | | $ | 1 | | | $ | (8) | | | $ | 478 | |
| | | | | | | |
The fair value of fixed-income securities by contractual maturity is as follows:
| | | | | |
| | As of |
| (in millions) | June 30, 2022 |
| Less than 1 year | $ | — | |
| 1–5 years | 38 | |
| 5–10 years | 116 | |
| More than 10 years | 94 | |
| Total maturities of fixed-income securities | $ | 248 | |
Gross realized gains and losses on sales of fixed-income and equity securities were immaterial as of June 30, 2022.
NOTE 11: WILDFIRE-RELATED CONTINGENCIES
Liability Overview
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
The process for estimating losses associated with potential claims related to wildfires requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change.
Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.
Criminal charges have been filed against the Utility in connection with the 2020 Zogg fire. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. In the event that the Utility were convicted of certain charges in connection with the 2020 Zogg fire, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the fire would materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments, if such payments were ordered by the court presiding over the criminal proceeding in connection with the 2020 Zogg fire.
PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.
If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.
PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire and three other fires in Shasta County, California. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.
2019 Kincade Fire
According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.
On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.
On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed the Kincade Complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Kincade Complaint. It further announced that it would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the Kincade Complaint. At a hearing on September 9, 2021, the Sonoma County Superior Court overruled the demurrer. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation.
On December 2, 2021, the CPUC approved a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, and it may not seek recovery of this $85 million of costs. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of general orders or statutory requirements. As of June 30, 2022, PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflected $40 million within Other current liabilities in connection with the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed. On January 10, 2022, The Utility Reform Network (“TURN”) filed an application for rehearing of the Kincade SED Settlement. On January 25, 2022, the Utility filed an opposition to the application for rehearing. On April 21, 2022, the CPUC granted TURN’s application for the limited purpose of requiring SED to include in the decision approving the settlement an analysis of the appropriate penalty using the CPUC’s methodology and denied TURN’s application in all other respects. On July 14, 2022, the CPUC approved the SED settlement.
As of July 21, 2022, PG&E Corporation and the Utility are aware of approximately 104 complaints on behalf of at least 2,657 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. Trial is set for November 7, 2022.
In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022.
On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The summary adjudication hearing is currently set for August 5, 2022.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the status of settlement discussions with certain subrogation entities and individuals, PG&E Corporation and the Utility recorded an additional charge in the second quarter of 2022 for potential losses in connection with the 2019 Kincade fire of $150 million, for an aggregate liability of $950 million (before available insurance).
The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility (other than as described above), (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.
The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021.
| | | | | |
| Loss Accrual (in millions) | |
Balance at December 31, 2021 | $ | 769 | |
| Accrued Losses | 150 | |
Payments | (9) | |
Balance at June 30, 2022 | $ | 910 | |
The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of June 30, 2022, the Utility recorded an insurance receivable for the full amount of the $430 million.
2020 Zogg Fire
According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.
On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.
On September 24, 2021, the Shasta County District Attorney’s Office filed the Zogg Complaint charging the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges in the Zogg Complaint. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts contained in the Zogg Complaint. At a hearing on May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges in the Zogg Complaint. The preliminary hearing is scheduled to begin on January 18, 2023.
Various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete.
As of July 21, 2022, PG&E Corporation and the Utility are aware of approximately 24 complaints on behalf of at least 460 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The trial is set for February 6, 2023. In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). The aggregate liability remained unchanged as of June 30, 2022.
The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.
The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021.
| | | | | |
| Loss Accrual (in millions) | |
Balance at December 31, 2021 | $ | 211 | |
| Accrued Losses | — | |
| Payments | (80) | |
Balance at June 30, 2022 | $ | 131 | |
The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of June 30, 2022, the Utility recorded an insurance receivable for $346 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $31 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.
2021 Dixie Fire
According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.
On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols, implementation of those protocols, and day-of-event response, the Utility disagrees with the allegations of the Cal Fire Investigation Report and plans to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.
The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.
On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the Court entered the Judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation.
As of July 21, 2022, PG&E Corporation and the Utility are aware of approximately 42 complaints on behalf of at least 1,273 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On July 27, 2022, the court set a trial date of June 5, 2023.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). The aggregate liability remained unchanged as of June 30, 2022.
The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility (other than as described above), (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.
As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable due to the incomplete information available to PG&E Corporation and the Utility as of the date of this filing as to facts pertinent to potential claims and defenses. Moreover, PG&E Corporation and the Utility are currently unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility currently estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.
The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021.
| | | | | |
| Loss Accrual (in millions) | |
Balance at December 31, 2021 | $ | 1,150 | |
| Accrued Losses | — | |
| Payments | (4) | |
Balance at June 30, 2022 | $ | 1,146 | |
The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of June 30, 2022, the Utility recorded an insurance receivable of $555 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $346 million insurance receivable recorded in connection with the 2020 Zogg fire.
As of June 30, 2022, the Utility recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $104 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $361 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. An immaterial increase was recorded in the second quarter of 2022.
Loss Recoveries
PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” and “2021 Dixie Fire.”
Total probable recoveries for the 2021 Dixie fire as of June 30, 2022 are:
| | | | | |
| Potential Recovery Source (in millions) | 2021 Dixie fire |
| Insurance | $ | 555 | |
| FERC TO rates | 104 | |
| WEMA | 361 | |
| Wildfire Fund | 150 | |
Probable recoveries at June 30, 2022 | $ | 1,170 | |
The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described herein, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Insurance
Insurance Coverage
In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in existing wildfire liability insurance in August 2021 for the period from August 1, 2021 to August 1, 2022, which is scheduled to renew in August 2022 for an additional coverage period of August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.
In April 2022, the Utility purchased approximately $725 million in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.
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.
In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 4 above.
Insurance Receivable
Through June 30, 2022, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $346 million for probable insurance recoveries in connection with the 2020 Zogg fire, and $555 million for probable insurance recoveries in connection with the 2021 Dixie fire. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.
The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | |
| Insurance Receivable (in millions) | 2021 Dixie fire | | 2020 Zogg fire | | 2019 Kincade fire | | Total |
Balance at December 31, 2021 | $ | 563 | | | $ | 270 | | | $ | 414 | | | $ | 1,247 | |
Accrued insurance recoveries (1) | (8) | | | 8 | | | — | | | — | |
Reimbursements (2) | — | | | (98) | | | (25) | | | (123) | |
Balance at June 30, 2022 | $ | 555 | | | $ | 180 | | | $ | 389 | | | $ | 1,124 | |
| | | | | | | |
(1) For the six months ended June 30, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $8 million.
(2) On July 14, 2022, the Utility received $19 million of insurance reimbursements related to the 2020 Zogg fire.
Regulatory Recovery
FERC TO rates
The Utility recognizes income and reduces its regulatory liability for potential refund through the FERC TO formula rate in future rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire, as of June 30, 2022, the Utility recorded a $104 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.
WEMA
The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of June 30, 2022, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery and the Utility recorded a $361 million regulatory asset in the WEMA. Cost recovery for incremental insurance premiums is addressed through a balancing account mechanism.
Wildfire Fund under AB 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. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. 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. The accrued Wildfire Fund receivable as of June 30, 2022 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire. For 2022, PG&E Corporation and the Utility have elected a Coverage Year that commences on January 1, 2022 at 12:01 a.m. Pacific Time and ends on December 31, 2022 at 12:00 a.m. Pacific Time.
Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses based on relevant factors that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.0 billion based on its 2022 equity rate base, and is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.
Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 31, 2022, the OEIS approved the Utility’s 2021 application and issued the Utility’s 2021 safety certification.
The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.
The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.
As of June 30, 2022, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.
For more information see Note 3 above.
Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Potential Insurance Recoveries
As further described under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. These securities claims are collectively referred to in this section as the “Wildfire-Related Securities Claims.”
Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the terms of the FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with carriers of the D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the Wildfire-Related Securities Claims. As of June 30, 2022 and each as further described below:
•For the Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the consolidated securities actions, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.
•For the Insurance Coverage Claims, PG&E Corporation entered into an agreement with certain of its D&O Insurance carriers and has reached an agreement in principle with some of its other D&O Insurance carriers to settle the majority of the Insurance Coverage Claims and recorded an insurance receivable for $272 million. PG&E Corporation records a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and PG&E Corporation can reasonably estimate the amount or its range.
•For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants will cause $117 million to be paid to the Fire Victim Trust. Proceeds from the D&O Insurance coverage will be paid first to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and then PG&E Corporation will apply the remaining proceeds to the Wildfire-Related Securities Claims. Accordingly, PG&E Corporation recorded a $117 million payable to the Fire Victim Trust as of June 30, 2022.
As a result, PG&E Corporation believes it is probable that it will incur a net loss of $145 million in connection with these matters. As of June 30, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Condensed Consolidated Statements of Income.
In the event that one or more of the settlements in these matters does not become effective, some or all parties are expected to continue to litigate, and at least some of the amounts of PG&E Corporation’s expected liabilities will remain uncertain.
Wildfire-Related Derivative Litigation
Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain then-current and former members of the boards of directors and certain then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). On April 13, 2018, the plaintiffs filed a consolidated complaint. On January 28, 2019, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims, if any, directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation or the Utility for amounts owed pursuant to their indemnification obligations in connection with such causes of action. On March 8, 2021, the court granted a stipulation by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff.
On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.
On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.
On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants will cause $117 million to be paid to the Fire Victim Trust from D&O Insurance policy proceeds, and the Fire Victim Trust will release, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement amount must be paid solely from insurance proceeds from the “Side B” D&O Insurance coverage. Accordingly, the settlement is contingent upon, among other things, a final order from the Bankruptcy Court approving settlements among PG&E Corporation, the Utility, and their D&O Insurance carriers (see “Indemnification Obligations and D&O Insurance Coverage” below). The settlement is also contingent upon an order from the Bankruptcy Court approving a settlement of the claims described under the heading “Wildfire-Related Securities Class Action” below, subject to certain exceptions. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action has been stayed. As of June 30, 2022, PG&E Corporation recorded a $117 million payable to the Fire Victim Trust.
On January 25, 2019, a separate purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On March 30, 2022, the plaintiff filed a request to dismiss this action.
Securities Class Action Litigation
Wildfire-Related Securities Class Action
In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.
Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.
On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933 based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.
On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with any such claims submitted through a proof of claim to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases. On April 29, 2021, the District Court issued a notice of intent to stay this action pending completion of the claims procedures in the bankruptcy proceedings. PERA filed objections to the notice of intent to stay on May 28, 2021. PG&E Corporation and the Utility filed a response to PERA’s objections on June 10, 2021, the officer, director, and underwriter defendants filed a response to PERA’s objections on June 11, 2021, and PERA filed a sur-response on June 21, 2021. The District Court has not taken further action with respect to its notice of intent to stay.
Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. PG&E Corporation recorded a liability in the aggregate amount of $300 million as of June 30, 2022 (before available insurance), which represents its best loss estimate for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such agreement.
Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process
PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).
While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows:
•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and
•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.
PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.
On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. PERA’s appeal to the Ninth Circuit remains pending.
On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.
PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by continuing to collect trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.
Indemnification Obligations and D&O Insurance Coverage
To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with the carriers regarding, among other things, the applicability of one year of D&O Insurance policies to those matters (the “Insurance Coverage Claims”).
In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants entered into an agreement with certain of their D&O Insurance carriers and have reached an agreement in principle with some of their other D&O Insurance carriers to settle the majority of the Insurance Coverage Claims. As a result of these agreements, PG&E Corporation will receive insurance coverage in an aggregate amount of $272 million. These settlements are contingent upon approval by the Bankruptcy Court. As of June 30, 2022, PG&E Corporation recorded an insurance receivable for $272 million. Proceeds from the D&O Insurance coverage will be paid first to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and then PG&E Corporation will apply the remaining proceeds to the Wildfire-Related Securities Claims.
PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.
The extent of PG&E Corporation’s and the Utility’s recovery of the D&O Insurance proceeds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Butte County District Attorney’s Office Investigation into the 2018 Camp Fire
Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.
On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).
On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to October 7, 2022.
NOTE 12: OTHER CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
CPUC and FERC Matters
Transmission Owner Rate Case Revenue Subject to Refund
The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.
On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.
On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue on rehearing.
As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the second quarter of 2022 by approximately $357 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $223 million to Regulatory assets.
On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in the TO18 proceeding.
On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.
On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.
On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds.
2020 WMCE Interim Rate Relief Subject to Refund
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.
As previously disclosed, on October 23, 2020, the CPUC approved $447 million in interim rate relief (which includes interest) pertaining to costs addressed in the 2020 WMCE application. As a result, the Utility proposed to recover the remaining $868 million revenue requirement 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 being subject to refund.
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.
On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to recover a revenue requirement of $591 million over a 24-month amortization period, which is in addition to the interim rate relief of $447 million. On April 7, 2022, the CPUC extended the statutory deadline for a PD in this matter to October 1, 2022.
2022 Cost of Capital Application
The Utility’s annual cost of capital adjustment mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.
On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC 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 “2022 cost of capital application”). The 2022 cost of capital application requested 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 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding.
In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.
On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes starting on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application. As of June 30, 2022, the Utility had not recorded a reserve for refunds related to these memorandum accounts.
On December 24, 2021, the CPUC issued a scoping memo in the 2022 cost of capital application limiting the scope of the Utility’s 2022 cost of capital application to the 2022 cost of capital only.
To set the 2022 cost of capital, the CPUC will consider (i) whether there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022; and (ii) if so, whether to leave the cost of capital components at pre-2022 levels for the year 2022, or open a second phase to consider alternative cost of capital proposals for the year 2022. The Utility’s position is that there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and that the CPUC should leave the cost of capital components at pre-2022 levels for 2022. Briefing concluded on March 25, 2022.
If the CPUC determines that the 2022 cost of capital application establishes extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and leaves the Utility’s cost of capital components at pre-2022 levels for 2022, the cost of long-term debt would be 4.17%, the return on preferred stock would be 5.52%, and the ROE would be 10.25%. If the CPUC opens a second phase of the proceeding, the CPUC would set the cost of capital for 2022 based on alternative cost of capital proposals that would address the technical cost of capital material included within the Utility’s 2022 cost of capital application.
If the CPUC determines that there are not extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022, the cost of capital adjustment mechanism would operate and the cost of long-term debt would be 4.15%, the return on preferred stock would be 5.52%, and the ROE would be 9.67%. The resulting decrease in the CPUC jurisdictional gas and electric revenue requirement would be approximately $163 million ($99 million electric and $64 million gas).
2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit
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 July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. On July 14, 2022, the CPUC approved a final decision approving the settlement agreement, which resolved all issues in this proceeding and authorized 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 will be amortized in rates over 60 months and $43 million associated with 2022 will be amortized in rates over 12 months beginning August 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application was included in test year 2023 rate base in the Utility’s consolidated 2023 GRC.
Other Matters
PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters totaled $87 million and $77 million as of June 30, 2022 and December 31, 2021, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
PSPS Class Action
On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.
On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.
The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The appellant filed his opening brief on July 1, 2022. The Utility’s answering brief is due by August 31, 2022, and the appellant’s reply brief is due within 20 days of the Utility’s answering brief.
The Utility is unable to determine the timing and outcome of this proceeding.
CZU Lightning Complex Fire Notices of Violation
Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.
Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded a charge during the fourth quarter of 2021 for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
Environmental Remediation Contingencies
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following: | | | | | | | | | | | |
| | Balance at |
| (in millions) | June 30, 2022 | | December 31, 2021 |
| Topock natural gas compressor station | $ | 301 | | | $ | 299 | |
| Hinkley natural gas compressor station | 117 | | | 123 | |
Former MGP sites owned by the Utility or third parties (1) | 653 | | | 667 | |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) | 114 | | | 104 | |
Fossil fuel-fired generation facilities and sites (3) | 55 | | | 70 | |
| Total environmental remediation liability | $ | 1,240 | | | $ | 1,263 | |
| | | |
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.
The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.
The Utility’s environmental remediation liability as of June 30, 2022, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of June 30, 2022, the Utility expected to recover $982 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.
Natural Gas Compressor Station Sites
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
Topock Site
The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $240 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.
Hinkley Site
The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2022. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $136 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.
Former Manufactured Gas Plants
Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $491 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.
Utility-Owned Generation Facilities and Third-Party Disposal Sites
Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $48 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.
Fossil Fuel-Fired Generation Sites
In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $47 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance
The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.
Purchase Commitments
In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2021, the Utility had undiscounted future expected obligations of approximately $34 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.
Oakland Headquarters Lease
On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.
The term of the Lease began on April 8, 2022. The Lease term will expire in 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.
The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). If the option is exercised, the Purchase Price would be paid in 2023.
The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of further subdivided spaces. As of June 30, 2022, part of the space in the Lease has been made available for use. The Utility has recorded approximately $233 million in Operating lease right of use assets, approximately $55 million of leasehold improvements, which includes approximately $42 million that was provided to the Utility as lease incentives, and approximately $275 million in Operating lease liabilities in the Condensed Consolidated Financial Statements related to the Lease.