NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
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, 2020 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2020 Form 10-K. This quarterly report should be read in conjunction with the 2020 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 the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective 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 Effective Date of July 1, 2020.
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 the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and 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 or noncurrent liabilities in the Condensed Consolidated Balance Sheets.
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order.
However, 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 Effective 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 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 10 under the heading “Securities Class Action Litigation.”
In addition to filing objections in the Bankruptcy Court to claims with respect to which PG&E Corporation and the Utility do not believe they have liability, PG&E Corporation and the Utility are working to resolve certain disputed general unsecured claims before a panel of mediators. On April 5, 2021, the Bankruptcy Court entered an order extending the deadline for PG&E Corporation and the Utility to object to claims to December 23, 2021, except for some claims filed by the United States and by Cal Fire, for which the Bankruptcy Court has approved stipulations extending the objection deadline to November or December 2021, depending on the claim. On October 19, 2021, PG&E Corporation and the Utility filed a motion for entry of an order further extending the deadline for PG&E Corporation and the Utility to object to claims through and including June 21, 2022, which motion is pending before the Bankruptcy Court.
Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings were pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. On May 20, 2021, the FERC approved an uncontested filing that would result in a final market clearing and funds distribution associated with the issues relating to short-term electric energy sales in California between May 2000 and June 2001 that have been litigated at the FERC and in other forums. In August 2021, both the Utility’s and the California Power Exchange’s bankruptcy courts approved the final market clearing. As a result, the Utility expects to receive $143 million from the California Power Exchange and various escrows that were established as part of the disputed claims settlements, reflected in Accounts receivable – other on the Condensed Consolidated Balance Sheets. As such, as of September 30, 2021, the Condensed Consolidated Balance Sheets reflected $0 in net claims within Disputed claims and customer refunds compared to $242 million as of December 31, 2020. The Utility expects to refund current regulatory liabilities of $419 million, reflected in Current liabilities – other on the Condensed Consolidated Balance Sheets, $143 million of which would be funded from the California Power Exchange and various escrows discussed above.
Reorganization Items, Net
Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $0 and $9 million for PG&E Corporation and the Utility, respectively, during the three months ended September 30, 2021 as compared to $6 million and $93 million for PG&E Corporation and the Utility, respectively, during same period in 2020. Cash paid for reorganization items, net was $31 million and $50 million for PG&E Corporation and the Utility, respectively, during the nine months ended September 30, 2021 as compared to $96 million and $300 million for PG&E Corporation and the Utility, respectively, during the same period in 2020. There were no amounts recorded to reorganization items during the three months ended September 30, 2021. Reorganization items, net for the nine months ended September 30, 2021 and three and nine months ended September 30, 2020 include the following:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2020
|
(in millions)
|
Utility
|
|
PG&E Corporation (1)
|
|
PG&E Corporation Consolidated
|
Debtor-in-possession financing costs
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Legal and other
|
90
|
|
|
55
|
|
|
145
|
|
Interest income
|
(8)
|
|
|
—
|
|
|
(8)
|
|
Total reorganization items, net
|
$
|
82
|
|
|
$
|
55
|
|
|
$
|
137
|
|
|
|
|
|
|
|
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2021
|
(in millions)
|
Utility
|
|
PG&E Corporation (1)
|
|
PG&E Corporation Consolidated
|
Debtor-in-possession financing costs
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Legal and other
|
21
|
|
|
(1)
|
|
|
20
|
|
Other
|
(9)
|
|
|
—
|
|
|
(9)
|
|
Total reorganization items, net
|
$
|
12
|
|
|
$
|
(1)
|
|
|
$
|
11
|
|
|
|
|
|
|
|
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2020
|
(in millions)
|
Utility
|
|
PG&E Corporation (1)
|
|
PG&E Corporation Consolidated
|
Debtor-in-possession financing costs
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Legal and other (2)
|
296
|
|
|
1,653
|
|
|
1,949
|
|
Interest income
|
(13)
|
|
|
(2)
|
|
|
(15)
|
|
Total reorganization items, net
|
$
|
286
|
|
|
$
|
1,651
|
|
|
$
|
1,937
|
|
|
|
|
|
|
|
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Amount includes $1.5 billion in equity backstop premium expense, bridge loan facility fees, and trustee fees.
NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.
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 VIE
The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5) in October 2020 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 September 30, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023.
The SPV is considered a VIE because its equity capitalization is insufficient to finance 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 period ended September 30, 2021 or is expected to be provided in the future that was not previously contractually required. As of September 30, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.9 billion and $2.6 billion, respectively, and outstanding borrowings of $1.0 billion and $1.0 billion, respectively, under the Receivables Securitization Program.
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 at September 30, 2021, 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 at September 30, 2021, it did not consolidate any of them.
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 nine months ended September 30, 2021 and 2020 were as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Benefits
|
|
Three Months Ended September 30,
|
(in millions)
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Service cost for benefits earned (1)
|
$
|
147
|
|
|
$
|
133
|
|
|
$
|
15
|
|
|
$
|
15
|
|
Interest cost
|
161
|
|
|
178
|
|
|
13
|
|
|
16
|
|
Expected return on plan assets
|
(261)
|
|
|
(261)
|
|
|
(33)
|
|
|
(34)
|
|
Amortization of prior service cost
|
(1)
|
|
|
(1)
|
|
|
3
|
|
|
3
|
|
Amortization of net actuarial loss
|
1
|
|
|
1
|
|
|
(8)
|
|
|
(5)
|
|
Net periodic benefit cost
|
47
|
|
|
50
|
|
|
(10)
|
|
|
(5)
|
|
Regulatory account transfer (2)
|
37
|
|
|
34
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
84
|
|
|
$
|
84
|
|
|
$
|
(10)
|
|
|
$
|
(5)
|
|
|
|
|
|
|
|
|
|
(1) A portion of service costs are 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.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Benefits
|
|
Nine Months Ended September 30,
|
(in millions)
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Service cost for benefits earned (1)
|
$
|
440
|
|
|
$
|
397
|
|
|
$
|
47
|
|
|
$
|
46
|
|
Interest cost
|
484
|
|
|
535
|
|
|
39
|
|
|
47
|
|
Expected return on plan assets
|
(784)
|
|
|
(783)
|
|
|
(103)
|
|
|
(103)
|
|
Amortization of prior service cost
|
(4)
|
|
|
(4)
|
|
|
10
|
|
|
10
|
|
Amortization of net actuarial loss
|
4
|
|
|
3
|
|
|
(24)
|
|
|
(15)
|
|
Net periodic benefit cost
|
140
|
|
|
148
|
|
|
(31)
|
|
|
(15)
|
|
Regulatory account transfer (2)
|
111
|
|
|
102
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
251
|
|
|
$
|
250
|
|
|
$
|
(31)
|
|
|
$
|
(15)
|
|
|
|
|
|
|
|
|
|
(1) A portion of service costs are 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:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
Total
|
(in millions, net of income tax)
|
Three Months Ended September 30, 2021
|
Beginning balance
|
$
|
(38)
|
|
|
$
|
17
|
|
|
$
|
(21)
|
|
Amounts reclassified from other comprehensive income: (1)
|
|
|
|
|
|
Amortization of prior service cost (net of taxes of $0 and $1, respectively)
|
(1)
|
|
|
2
|
|
|
1
|
|
Amortization of net actuarial loss (net of taxes of $0 and $3, respectively)
|
1
|
|
|
(5)
|
|
|
(4)
|
|
Regulatory account transfer (net of taxes of $1 and $2, respectively)
|
1
|
|
|
3
|
|
|
4
|
|
Net current period other comprehensive gain (loss)
|
1
|
|
|
—
|
|
|
1
|
|
Ending balance
|
$
|
(37)
|
|
|
$
|
17
|
|
|
$
|
(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 September 30, 2020
|
Beginning balance
|
$
|
(22)
|
|
|
$
|
17
|
|
|
$
|
(5)
|
|
Amounts reclassified from other comprehensive income: (1)
|
|
|
|
|
|
Amortization of prior service cost (net of taxes of $0 and $1, respectively)
|
(1)
|
|
|
2
|
|
|
1
|
|
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)
|
1
|
|
|
(4)
|
|
|
(3)
|
|
Regulatory account transfer (net of taxes of $1 and $0, respectively)
|
—
|
|
|
2
|
|
|
2
|
|
Net current period other comprehensive gain (loss)
|
—
|
|
|
—
|
|
|
—
|
|
Ending balance
|
$
|
(22)
|
|
|
$
|
17
|
|
|
$
|
(5)
|
|
|
|
|
|
|
|
(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)
|
Nine Months Ended September 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 $3, respectively)
|
(3)
|
|
|
7
|
|
|
4
|
|
Amortization of net actuarial loss (net of taxes of $1 and $7, respectively)
|
3
|
|
|
(17)
|
|
|
(14)
|
|
Regulatory account transfer (net of taxes of $1 and $4, respectively)
|
2
|
|
|
10
|
|
|
12
|
|
Net current period other comprehensive gain (loss)
|
2
|
|
|
—
|
|
|
2
|
|
Ending balance
|
$
|
(37)
|
|
|
$
|
17
|
|
|
$
|
(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)
|
Nine Months Ended September 30, 2020
|
Beginning balance
|
$
|
(22)
|
|
|
$
|
17
|
|
|
$
|
(5)
|
|
Amounts reclassified from other comprehensive income: (1)
|
|
|
|
|
|
Amortization of prior service cost (net of taxes of $1 and $3, respectively)
|
(3)
|
|
|
7
|
|
|
4
|
|
Amortization of net actuarial loss (net of taxes of $1 and $4, respectively)
|
2
|
|
|
(11)
|
|
|
(9)
|
|
Regulatory account transfer (net of taxes of $1 and $1, respectively)
|
1
|
|
|
4
|
|
|
5
|
|
Net current period other comprehensive gain (loss)
|
—
|
|
|
—
|
|
|
—
|
|
Ending balance
|
$
|
(22)
|
|
|
$
|
17
|
|
|
$
|
(5)
|
|
|
|
|
|
|
|
(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.
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 GRC and GT&S rate cases, which have been combined in the 2023 GRC. 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 CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized 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:
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Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
(in millions)
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Electric
|
|
|
|
|
|
|
|
Revenue from contracts with customers
|
|
|
|
|
|
|
|
Residential
|
$
|
1,962
|
|
|
$
|
1,862
|
|
|
$
|
4,778
|
|
|
$
|
4,092
|
|
Commercial
|
1,580
|
|
|
1,455
|
|
|
3,776
|
|
|
3,537
|
|
Industrial
|
467
|
|
|
453
|
|
|
1,099
|
|
|
1,135
|
|
Agricultural
|
655
|
|
|
657
|
|
|
1,238
|
|
|
1,149
|
|
Public street and highway lighting
|
18
|
|
|
17
|
|
|
53
|
|
|
51
|
|
Other (1)
|
(52)
|
|
|
(148)
|
|
|
169
|
|
|
54
|
|
Total revenue from contracts with customers - electric
|
4,630
|
|
|
4,296
|
|
|
11,113
|
|
|
10,018
|
|
Regulatory balancing accounts (2)
|
(449)
|
|
|
(486)
|
|
|
414
|
|
|
267
|
|
Total electric operating revenue
|
$
|
4,181
|
|
|
$
|
3,810
|
|
|
$
|
11,527
|
|
|
$
|
10,285
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
|
|
|
|
|
Revenue from contracts with customers
|
|
|
|
|
|
|
|
Residential
|
$
|
295
|
|
|
$
|
303
|
|
|
$
|
1,921
|
|
|
$
|
1,795
|
|
Commercial
|
102
|
|
|
90
|
|
|
486
|
|
|
434
|
|
Transportation service only
|
323
|
|
|
259
|
|
|
995
|
|
|
902
|
|
Other (1)
|
16
|
|
|
27
|
|
|
(168)
|
|
|
(153)
|
|
Total revenue from contracts with customers - gas
|
736
|
|
|
679
|
|
|
3,234
|
|
|
2,978
|
|
Regulatory balancing accounts (2)
|
548
|
|
|
393
|
|
|
635
|
|
|
458
|
|
Total natural gas operating revenue
|
$
|
1,284
|
|
|
$
|
1,072
|
|
|
$
|
3,869
|
|
|
$
|
3,436
|
|
Total operating revenues
|
$
|
5,465
|
|
|
$
|
4,882
|
|
|
$
|
15,396
|
|
|
$
|
13,721
|
|
|
|
|
|
|
|
|
|
(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.
Initial and annual contributions to the Wildfire Fund established pursuant to AB 1054
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 contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from customers. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).
On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of September 30, 2021, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage.
As of September 30, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other noncurrent liabilities, $461 million in current assets - Wildfire Fund asset, and $5.4 billion in noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three and nine months ended September 30, 2021 and 2020, the Utility recorded amortization and accretion expense of $162 million, $399 million, $120 million, and $293 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Condensed Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.
AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a five year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to six years. Similarly, a ten percent change to the assumption regarding current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.
Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level 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 other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.
PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such acceleration of the amortization of the asset could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. As of September 30, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire and $42 million of accelerated amortization, reflected in Wildfire Fund expense.
Financial Instruments—Credit Losses
PG&E Corporation and the Utility have four categories of financial assets in scope, each with their own associated credit risks. PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to current economic conditions. 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 10 below. Wildfire fund receivable risk is related to the Wildfire Fund’s durability, which is a measurement of the claim-paying capacity. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. During the three and nine months ended September 30, 2021, expected credit losses of $91 million and $280 million, respectively, were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. During the three and nine months ended September 30, 2020, expected credit losses of $33 million and $96 million, respectively, were recorded to Operating and maintenance expense on the Condensed Consolidated Statements of Income. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At September 30, 2021, the RUBA current balancing accounts receivable balance was $250 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $33 million, respectively.
Sale of Transmission Tower Wireless Licenses
On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.
The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.
The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market additional attachment locations on up to 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.
In addition, the Utility and SBA entered into a Pipeline Cell Site Transaction Agreement pursuant to which the Utility and SBA established terms and conditions for adding additional cell sites under the License Agreement. Pipeline Cell Sites are locations where the Utility was in the process of locating a new Cell Site for a wireless carrier at the close of the transaction.
In exchange for the exclusive license and entry into the License Agreement, SBA paid the Utility $946 million of the purchase price at the closing. On August 15, 2021, the post-closing period ended, and the Utility and SBA agreed to a final purchase price of $947 million, pursuant to the terms of the Transaction Agreement.
The Utility recorded approximately $370 million of the $947 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $947 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a third-party discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are presented within Other noncurrent liabilities on the Condensed Consolidated Balance Sheets.
The Utility recorded the remaining approximately $471 million ($455 million of which was noncurrent) of the sale proceeds to regulatory liabilities, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.
The financing obligation is amortized through Electric operating revenue and Interest expense on the Condensed Consolidated Statements of Income using the effective interest method and the deferred revenue balance is amortized through Electric operating revenue ratably over the 100-year term.
Recently Adopted Accounting Standards
Income Taxes
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. PG&E Corporation and the Utility adopted this ASU on January 1, 2021. There was no material impact to 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
Debt
In August 2020, the 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 on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, 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 and Liabilities
Regulatory Assets
Long-term regulatory assets are comprised of the following:
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|
|
|
|
|
|
|
|
|
|
Balance at
|
(in millions)
|
September 30, 2021
|
|
December 31, 2020
|
Pension benefits (1)
|
$
|
2,136
|
|
|
$
|
2,245
|
|
Environmental compliance costs
|
1,082
|
|
|
1,112
|
|
Utility retained generation (2)
|
145
|
|
|
181
|
|
Price risk management
|
223
|
|
|
204
|
|
Unamortized loss, net of gain, on reacquired debt
|
40
|
|
|
49
|
|
Catastrophic event memorandum account (3)
|
989
|
|
|
842
|
|
Wildfire expense memorandum account (4)
|
455
|
|
|
400
|
|
Fire hazard prevention memorandum account (5)
|
75
|
|
|
137
|
|
Fire risk mitigation memorandum account (6)
|
44
|
|
|
66
|
|
Wildfire mitigation plan memorandum account (7)
|
342
|
|
|
390
|
|
Deferred income taxes (8)
|
1,515
|
|
|
908
|
|
Insurance premium costs (9)
|
232
|
|
|
294
|
|
Wildfire mitigation balancing account (10)
|
215
|
|
|
156
|
|
General rate case memorandum accounts (11)
|
117
|
|
|
376
|
|
Vegetation management balancing account (12)
|
690
|
|
|
592
|
|
COVID-19 pandemic protection memorandum account (13)
|
47
|
|
|
84
|
|
Other
|
1,132
|
|
|
942
|
|
Total long-term regulatory assets
|
$
|
9,479
|
|
|
$
|
8,978
|
|
|
|
|
|
(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 September 30, 2021, $64 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Includes $339 million incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire plus the noncurrent portion of incremental wildfire liability insurance premium costs for the period July 26, 2017 through December 31, 2019 totaling $116 million. 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 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 June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through September 30, 2021. 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 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 January 1, 2020 through September 30, 2021. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
(11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 22 months, beginning March 1, 2021.
(12) Represents costs from routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.
(13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. On a go forward basis, the CPPMA applies only to small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. The RUBA applies to residential customers and was approved on April 13, 2021 with an effective date of June 11, 2020. As of September 30, 2021, the Utility had recorded an aggregate under-collection of $297 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA and the RUBA are in effect. Of the $297 million under-collection, at September 30, 2021, $250 million is recorded in the RUBA current balancing accounts receivable and $30 million is recorded in the CPPMA. The remaining $17 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following:
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|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
(in millions)
|
September 30, 2021
|
|
December 31, 2020
|
Cost of removal obligations (1)
|
$
|
7,216
|
|
|
$
|
6,905
|
|
Recoveries in excess of AROs (2)
|
306
|
|
|
458
|
|
Public purpose programs (3)
|
974
|
|
|
948
|
|
Employee benefit plans (4)
|
1,022
|
|
|
995
|
|
Tower Licenses (5)
|
455
|
|
|
—
|
|
SFGO Sale (6)
|
359
|
|
|
—
|
|
Other
|
1,329
|
|
|
1,118
|
|
Total long-term regulatory liabilities
|
$
|
11,661
|
|
|
$
|
10,424
|
|
|
|
|
|
(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 9 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 $455 million, $314 million and $141 million will be refunded to FERC and CPUC jurisdiction customers, respectively. (See Note 3 above.)
(6) Represents the noncurrent portion of the gain on the sale of SFGO that will be refunded to customers.
Regulatory Balancing Accounts
Current regulatory balancing accounts receivable and payable are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable Balance at
|
(in millions)
|
September 30, 2021
|
|
December 31, 2020
|
Gas distribution and transmission
|
$
|
225
|
|
|
$
|
102
|
|
Energy procurement
|
225
|
|
|
413
|
|
Public purpose programs
|
278
|
|
|
292
|
|
Fire hazard prevention memorandum account
|
81
|
|
|
121
|
|
Fire risk mitigation memorandum account
|
22
|
|
|
33
|
|
Wildfire mitigation plan memorandum account
|
108
|
|
|
161
|
|
Wildfire mitigation balancing account
|
41
|
|
|
27
|
|
General rate case memorandum accounts
|
467
|
|
|
313
|
|
Vegetation management balancing account
|
277
|
|
|
115
|
|
Insurance premium costs
|
508
|
|
|
135
|
|
Other
|
673
|
|
|
289
|
|
Total regulatory balancing accounts receivable
|
$
|
2,905
|
|
|
$
|
2,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payable Balance at
|
(in millions)
|
September 30, 2021
|
|
December 31, 2020
|
Electric distribution
|
$
|
330
|
|
|
$
|
55
|
|
Electric transmission
|
100
|
|
|
267
|
|
Gas distribution and transmission
|
53
|
|
|
76
|
|
Energy procurement
|
133
|
|
|
158
|
|
Public purpose programs
|
300
|
|
|
410
|
|
Other
|
223
|
|
|
279
|
|
Total regulatory balancing accounts payable
|
$
|
1,139
|
|
|
$
|
1,245
|
|
For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 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 at September 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Termination
Date
|
|
Facility Limit
|
|
Borrowings Outstanding
|
|
Letters of Credit Outstanding
|
|
Facility
Availability
|
|
Utility revolving credit facility
|
June 2026
|
|
$
|
4,000
|
|
(1)
|
$
|
1,020
|
|
|
$
|
604
|
|
|
$
|
2,376
|
|
|
Utility term loan credit facility
|
January 2022, October 2022
|
(2)
|
1,500
|
|
|
1,500
|
|
|
—
|
|
|
—
|
|
|
Utility receivables securitization program (3)
|
September 2023
|
|
1,000
|
|
(4)
|
1,000
|
|
|
—
|
|
|
—
|
|
(4)
|
PG&E Corporation revolving credit facility
|
June 2024
|
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
|
Total credit facilities
|
|
|
$
|
7,000
|
|
|
$
|
3,520
|
|
|
$
|
604
|
|
|
$
|
2,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes a $1.5 billion letter of credit sublimit.
(2) $184 million of the Utility term loan credit facility has a January 2022 termination date, and $1.3 billion of the Utility term loan credit facility has an October 2022 termination date.
(3) On October 5, 2020, the Utility entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023. For more information, see “Variable Interest Entities” in Note 3.
(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
Utility
As previously disclosed, on July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”). The Utility Revolving Credit Agreement had a maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.
As previously disclosed, on June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026, and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.
As previously disclosed, on July 1, 2020, the Utility entered into a $3.0 billion term loan credit agreement (the “Utility Term Loan Credit Agreement”) comprised of 364-day tranche loans in the aggregate principal amount of $1.5 billion (the “364-Day Tranche Loans”) and 18-month tranche loans in the aggregate principal amount of $1.5 billion (the “18-Month Tranche Loans”). As previously disclosed, the 364-Day Tranche Loans were paid in full on March 11, 2021. The 18-Month Tranche Loans had an initial maturity date of January 1, 2022.
On October 29, 2021, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of a portion of the 18-Month Tranche Loans in an amount equal to $1.3 billion (the “Extended 18-Month Tranche Loans”) to October 1, 2022. The maturity date for a portion of the 18-Month Tranche Loans in an amount equal to $184 million was not extended and continues to have a maturity date of January 1, 2022. To the extent that any Extended 18-Month Tranche Loans remain outstanding on June 1, 2022, a fee will be due and owing to the lenders under the Extended 18-Month Tranche Loans.
PG&E Corporation
As previously disclosed, on July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, subject to two one-year extensions at the option of PG&E Corporation.
As previously disclosed, on June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.
Long-Term Debt Issuances and Redemptions
Utility
In March 2021, the Utility issued $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s term loan credit agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement and (iii) general corporate purposes.
In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.
Intercompany Note Payable
On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The rate of interest on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of September 30, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Condensed Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Condensed Consolidated Balance Sheet.
SB 901
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 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact 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. In connection with the proposed transaction, the Utility would retire $6.0 billion of Utility debt. 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. Three parties filed applications for rehearing of the decision, and the Utility filed a response to those applications on May 14, 2021. On May 11, 2021, the CPUC issued a financing order authorizing the issuance of $7.5 billion of recovery bonds in connection with the post-emergence transaction. Two parties filed applications for rehearing of the financing order, and the Utility filed a response to those applications on June 4, 2021. On August 12, 2021, the CPUC issued decisions denying the applications for rehearing. On September 10, 2021, TURN filed a petition for writ of review of the decision and financing order in state court. Responses to the petition were submitted on October 15, 2021. TURN’s reply is due November 9, 2021.
AB 1054
AB 1054 provides that certain capital expenditures may be securitized by a customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization, pursuant to AB 1054, for a transaction to securitize up to $1.19 billion of fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021. On June 24, 2021, the CPUC issued a financing order authorizing the issuance of up to approximately $1.2 billion of recovery bonds to recover up to $1.19 billion of fire risk mitigation capital expenditures plus an estimated $13.3 million in related upfront financing costs. On July 6, 2021, the financing order became final and non-appealable. The final amount to be securitized will be based on the capital expenditures incurred by the Utility prior to the securitization transaction.
NOTE 6: 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 Agreement”) 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 nine months ended September 30, 2021, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of September 30, 2021, 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 Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these 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). PG&E Corporation’s and the Utility’s Amended Articles of Incorporation (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 an agreement (the “PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement”), pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, 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 are effectively excluded from the total number of outstanding equity securities when calculating a person’s percentage ownership for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because it is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,463,112,791 shares outstanding as of October 27, 2021, only 1,507,625,611 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective percentage ownership limitation for purposes of the Amended Articles as of October 27, 2021 was 2.9% of outstanding shares. As of October 27, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock.
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by section 382 of the Internal Revenue Code.
PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement
In accordance with the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, the grantor trust election has been filed.
With the grantor trust election, the Utility’s tax deductions occur as and when the Fire Victim Trust pays the fire victims rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. For PG&E Corporation common stock transferred to the Fire Victim Trust, the amount of the tax deduction will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust.
Under the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, the parties agreed to exchange the 477,743,590 shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). Accordingly, on July 9, 2021, PG&E Corporation issued 477,743,590 New Shares to ShareCo, which has the sole purpose of holding the New Shares in a designated brokerage account to facilitate the exchange process. When the Fire Victim Trust desires to sell any or all of its Plan Shares, the Fire Victim Trust may exchange any number of Plan Shares for a corresponding number of New Shares on a share-for-share basis (without any further consideration payable by either party) and thereafter promptly dispose of the New Shares in one or more transactions with one or more third parties. In the event that the Fire Victim Trust is unable to timely dispose of New Shares under certain circumstances (such shares, the “Nonconforming New Shares”), PG&E Corporation has authorized up to 250,000,000 additional shares of PG&E Corporation common stock, which may be transferred by ShareCo to the Fire Victim Trust on behalf of the Utility, in exchange for the Nonconforming New Shares, following the same procedures as for an exchange of Plan Shares for New Shares. The Plan Shares and any Non-Conforming New Shares exchanged will be held thereafter by the Utility. In the event that the Fire Victim Trust disposes of any common stock subject to the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement without complying with the terms of the agreement, the Fire Victim Trust may be required to make a payment to the Utility designed to compensate the Utility for adverse tax consequences arising from nonconforming sale transactions.
Upon PG&E Corporation’s issuance of the New Shares to ShareCo, PG&E Corporation’s common stock increased by $4.85 billion, the fair value of the shares on July 9, 2021. The increase to common stock is fully offset by the fair value of treasury stock recorded. The issuance of the New Shares did not have an impact on the total number of outstanding common shares as the New Shares are currently held by ShareCo and as such, there was no impact on basic or diluted EPS for the quarter ended September 30, 2021.
When the Fire Victim Trust notifies the Utility that it intends to sell shares, ShareCo (on behalf of the Utility) will transfer the New Shares to the Fire Victim Trust and the Fire Victim Trust will transfer the Plan Shares to the Utility. The Utility has no plan or intention to dispose of the Plan Shares at any time. As shares are exchanged with the Fire Victim Trust, the Utility will record the cost of shares and PG&E Corporation’s investment within additional paid in capital and PG&E Corporation’s presentation of common stock and treasury stock will decrease by the fair value per share established on July 9, 2021.
As of September 30, 2021, none of the 250,000,000 reserved shares had been issued.
Dividends
On December 20, 2017, the boards of directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.
Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the boards of directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the boards of directors may deem relevant. On April 9, 2020, the Bankruptcy Court entered an order that restricts PG&E Corporation from paying common dividends until it has recognized $6.2 billion in Non-GAAP Core earnings following the Effective Date of the Plan (Non-GAAP Core Earnings means GAAP earnings adjusted for certain non-core items). It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.
NOTE 7: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income (loss) attributable to 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 (loss) attributable to common shareholders and weighted average common shares outstanding for calculating diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
(in millions, except per share amounts)
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Income (loss) attributable to common shareholders
|
$
|
(1,091)
|
|
|
$
|
83
|
|
|
$
|
(574)
|
|
|
$
|
(1,518)
|
|
Weighted average common shares outstanding, basic
|
1,985
|
|
|
1,967
|
|
|
1,985
|
|
|
1,012
|
|
Add incremental shares from assumed conversions:
|
|
|
|
|
|
|
|
Employee share-based compensation
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
Equity Units
|
—
|
|
|
168
|
|
|
—
|
|
|
—
|
|
Weighted average common shares outstanding, diluted
|
1,985
|
|
|
2,140
|
|
|
1,985
|
|
|
1,012
|
|
Total income (loss) per common share, diluted
|
$
|
(0.55)
|
|
|
$
|
0.04
|
|
|
$
|
(0.29)
|
|
|
$
|
(1.50)
|
|
All potentially dilutive securities were excluded from the calculation of outstanding common shares on a diluted basis in periods where PG&E Corporation has incurred a net loss.
NOTE 8: 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 customer 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 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 in 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
|
|
September 30, 2021
|
|
December 31, 2020
|
Natural Gas (1) (MMBtus (2))
|
|
Forwards, Futures and Swaps
|
|
187,134,065
|
|
|
146,642,863
|
|
|
|
Options
|
|
50,880,000
|
|
|
14,140,000
|
|
Electricity (MWh)
|
|
Forwards, Futures and Swaps
|
|
11,652,406
|
|
|
9,435,830
|
|
|
|
Options
|
|
184,800
|
|
|
—
|
|
|
|
Congestion Revenue Rights (3)
|
|
247,960,149
|
|
|
266,091,470
|
|
|
|
|
|
|
|
|
(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
At September 30, 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
|
$
|
142
|
|
|
$
|
(5)
|
|
|
$
|
95
|
|
|
$
|
232
|
|
Noncurrent assets – other
|
131
|
|
|
—
|
|
|
—
|
|
|
131
|
|
Current liabilities – other
|
(36)
|
|
|
5
|
|
|
17
|
|
|
(14)
|
|
Noncurrent liabilities – other
|
(223)
|
|
|
—
|
|
|
—
|
|
|
(223)
|
|
Total commodity risk
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
112
|
|
|
$
|
126
|
|
At December 31, 2020, 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
|
$
|
33
|
|
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
148
|
|
Noncurrent assets – other
|
136
|
|
|
—
|
|
|
—
|
|
|
136
|
|
Current liabilities – other
|
(38)
|
|
|
—
|
|
|
15
|
|
|
(23)
|
|
Noncurrent liabilities – other
|
(204)
|
|
|
—
|
|
|
10
|
|
|
(194)
|
|
Total commodity risk
|
$
|
(73)
|
|
|
$
|
—
|
|
|
$
|
140
|
|
|
$
|
67
|
|
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 September 30, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
NOTE 9: 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
|
|
September 30, 2021
|
(in millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting (1)
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
$
|
411
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
411
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
25
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
Global equity securities
|
2,478
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,478
|
|
Fixed-income securities
|
1,054
|
|
|
825
|
|
|
—
|
|
|
—
|
|
|
1,879
|
|
Assets measured at NAV
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28
|
|
Total nuclear decommissioning trusts (2)
|
3,557
|
|
|
825
|
|
|
—
|
|
|
—
|
|
|
4,410
|
|
Price risk management instruments (Note 8)
|
|
|
|
|
|
|
|
|
|
Electricity
|
—
|
|
|
40
|
|
|
163
|
|
|
13
|
|
|
216
|
|
Gas
|
—
|
|
|
70
|
|
|
—
|
|
|
77
|
|
|
147
|
|
Total price risk management instruments
|
—
|
|
|
110
|
|
|
163
|
|
|
90
|
|
|
363
|
|
Rabbi trusts
|
|
|
|
|
|
|
|
|
|
Fixed-income securities
|
—
|
|
|
104
|
|
|
—
|
|
|
—
|
|
|
104
|
|
Life insurance contracts
|
—
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
77
|
|
Total rabbi trusts
|
—
|
|
|
181
|
|
|
—
|
|
|
—
|
|
|
181
|
|
Long-term disability trust
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
Assets measured at NAV
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
139
|
|
Total long-term disability trust
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
145
|
|
TOTAL ASSETS
|
$
|
3,974
|
|
|
$
|
1,116
|
|
|
$
|
163
|
|
|
$
|
90
|
|
|
$
|
5,510
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Price risk management instruments (Note 8)
|
|
|
|
|
|
|
|
|
|
Electricity
|
—
|
|
|
4
|
|
|
243
|
|
|
(17)
|
|
|
230
|
|
Gas
|
—
|
|
|
12
|
|
|
—
|
|
|
(5)
|
|
|
7
|
|
TOTAL LIABILITIES
|
$
|
—
|
|
|
$
|
16
|
|
|
$
|
243
|
|
|
$
|
(22)
|
|
|
$
|
237
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $740 million, primarily related to deferred taxes on appreciation of investment value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
December 31, 2020
|
(in millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting (1)
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
$
|
470
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
470
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
27
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27
|
|
Global equity securities
|
2,398
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,398
|
|
Fixed-income securities
|
924
|
|
|
835
|
|
|
—
|
|
|
—
|
|
|
1,759
|
|
Assets measured at NAV
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
Total nuclear decommissioning trusts (2)
|
3,349
|
|
|
835
|
|
|
—
|
|
|
—
|
|
|
4,209
|
|
Price risk management instruments (Note 8)
|
|
|
|
|
|
|
|
|
|
Electricity
|
—
|
|
|
2
|
|
|
166
|
|
|
2
|
|
|
170
|
|
Gas
|
—
|
|
|
1
|
|
|
—
|
|
|
113
|
|
|
114
|
|
Total price risk management instruments
|
—
|
|
|
3
|
|
|
166
|
|
|
115
|
|
|
284
|
|
Rabbi trusts
|
|
|
|
|
|
|
|
|
|
Fixed-income securities
|
—
|
|
|
106
|
|
|
—
|
|
|
—
|
|
|
106
|
|
Life insurance contracts
|
—
|
|
|
79
|
|
|
—
|
|
|
—
|
|
|
79
|
|
Total rabbi trusts
|
—
|
|
|
185
|
|
|
—
|
|
|
—
|
|
|
185
|
|
Long-term disability trust
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Assets measured at NAV
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
158
|
|
Total long-term disability trust
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
167
|
|
TOTAL ASSETS
|
$
|
3,828
|
|
|
$
|
1,023
|
|
|
$
|
166
|
|
|
$
|
115
|
|
|
$
|
5,315
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Price risk management instruments (Note 8)
|
|
|
|
|
|
|
|
|
|
Electricity
|
—
|
|
|
1
|
|
|
238
|
|
|
(25)
|
|
|
214
|
|
Gas
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
TOTAL LIABILITIES
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
238
|
|
|
$
|
(25)
|
|
|
$
|
217
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $671 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 nine months ended September 30, 2021 and 2020.
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 and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued 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 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. Market and credit risk management 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 customer rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. (See Note 8 above.)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at
|
|
|
|
|
|
|
(in millions)
|
|
September 30, 2021
|
|
|
|
|
|
|
Fair Value Measurement
|
|
Assets
|
|
Liabilities
|
|
Valuation
Technique
|
|
Unobservable
Input
|
|
Range(1) /Weighted-Average Price (2)
|
Congestion revenue rights
|
|
$
|
135
|
|
|
$
|
75
|
|
|
Market approach
|
|
CRR auction prices
|
|
$(320.25) - $320.25 / 0.25
|
Power purchase agreements
|
|
$
|
28
|
|
|
$
|
168
|
|
|
Discounted cash flow
|
|
Forward prices
|
|
$(8.16) - $232.15 / 49.17
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at
|
|
|
|
|
|
|
(in millions)
|
|
December 31, 2020
|
|
|
|
|
|
|
Fair Value Measurement
|
|
Assets
|
|
Liabilities
|
|
Valuation Technique
|
|
Unobservable Input
|
|
Range (1)/Weighted-Average Price (2)
|
Congestion revenue rights
|
|
$
|
153
|
|
|
$
|
74
|
|
|
Market approach
|
|
CRR auction prices
|
|
$(320.25) - $320.25 / 0.30
|
Power purchase agreements
|
|
$
|
13
|
|
|
$
|
164
|
|
|
Discounted cash flow
|
|
Forward prices
|
|
$12.56 - $148.30 / 35.52
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents price per MWh.
(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 instruments for the three and nine months ended September 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Risk Management Instruments
|
(in millions)
|
2021
|
|
2020
|
Asset (liability) balance as of July 1
|
$
|
(18)
|
|
|
$
|
(66)
|
|
Net realized and unrealized gains (losses):
|
|
|
|
Included in regulatory assets and liabilities or balancing accounts (1)
|
(62)
|
|
|
(31)
|
|
Asset (liability) balance as of September 30
|
$
|
(80)
|
|
|
$
|
(97)
|
|
|
|
|
|
(1) The costs related to price risk management activities are fully passed through to customers in 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)
|
2021
|
|
2020
|
Asset balance as of January 1
|
$
|
(72)
|
|
|
$
|
5
|
|
Net realized and unrealized gains (losses):
|
|
|
|
Included in regulatory assets and liabilities or balancing accounts (1)
|
(8)
|
|
|
(102)
|
|
Asset (liability) balance as of September 30
|
$
|
(80)
|
|
|
$
|
(97)
|
|
|
|
|
|
(1) The costs related to price risk management activities are fully passed through to customers in 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; and customer deposits approximate their carrying values at September 30, 2021 and December 31, 2020, 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 September 30, 2021
|
|
At December 31, 2020
|
(in millions)
|
Carrying Amount
|
|
Level 2 Fair Value
|
|
Carrying Amount
|
|
Level 2 Fair Value
|
Debt (Note 5)
|
|
|
|
|
|
|
|
PG&E Corporation
|
$
|
4,620
|
|
|
$
|
4,714
|
|
|
$
|
1,901
|
|
|
$
|
2,175
|
|
Utility
|
30,366
|
|
|
33,241
|
|
|
29,664
|
|
|
32,632
|
|
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 September 30, 2021
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
Short-term investments
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
25
|
|
Global equity securities
|
500
|
|
|
2,013
|
|
|
(7)
|
|
|
2,506
|
|
Fixed-income securities
|
1,785
|
|
|
105
|
|
|
(11)
|
|
|
1,879
|
|
Total (1)
|
$
|
2,310
|
|
|
$
|
2,118
|
|
|
$
|
(18)
|
|
|
$
|
4,410
|
|
As of December 31, 2020
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
Short-term investments
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27
|
|
Global equity securities
|
543
|
|
|
1,881
|
|
|
(1)
|
|
|
2,423
|
|
Fixed-income securities
|
1,610
|
|
|
152
|
|
|
(3)
|
|
|
1,759
|
|
Total (1)
|
$
|
2,180
|
|
|
$
|
2,033
|
|
|
$
|
(4)
|
|
|
$
|
4,209
|
|
|
|
|
|
|
|
|
|
(1) Represents amounts before deducting $740 million and $671 million for the periods ended September 30, 2021 and December 31, 2020, 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)
|
September 30, 2021
|
Less than 1 year
|
$
|
46
|
|
1–5 years
|
500
|
|
5–10 years
|
462
|
|
More than 10 years
|
871
|
|
Total maturities of fixed-income securities
|
$
|
1,879
|
|
The following table provides a summary of activity for fixed income and equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
(in millions)
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Proceeds from sales and maturities of nuclear decommissioning trust investments
|
$
|
224
|
|
|
$
|
890
|
|
|
$
|
1,176
|
|
|
$
|
1,144
|
|
Gross realized gains on securities
|
21
|
|
|
51
|
|
|
150
|
|
|
59
|
|
Gross realized losses on securities
|
(2)
|
|
|
(22)
|
|
|
(18)
|
|
|
(34)
|
|
NOTE 10: WILDFIRE-RELATED CONTINGENCIES
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, 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 the 2019 Kincade fire, 2020 Zogg fire, and 2021 Dixie fire may change.
Restructuring Support Agreement with the TCC
On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments.
2019 Kincade Fire
According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “Kincade incident update”), indicated that the 2019 Kincade fire had consumed 77,758 acres. In the Kincade incident update, Cal Fire reported no fatalities and four first responder injuries. The Kincade incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. 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 October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.
The Utility submitted EIRs (the “Kincade EIRs”) to the CPUC indicating that:
•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;
•various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time;
•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;
•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and
•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.
On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.”
On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint (the “Kincade Complaint”) charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. The Kincade Complaint alleges three felony counts of recklessly causing a fire that caused great bodily injury to six firefighters and/or burned inhabited and other structures, inhabited property, forest land and personal property, in violation of Penal Code section 452; two felony counts of reckless emission of air contaminants that caused great bodily injury to two minors, in violation of Health and Safety Code section 42400.3(c); one misdemeanor count of carelessly or negligently throwing or placing substances that may cause a fire, in violation of Health and Safety Code section 13001; one misdemeanor count of negligently causing fire, in violation of Public Resources Code section 4421; three misdemeanor counts of violation by a public utility, in violation of Public Utilities Code section 2110; and 23 misdemeanor counts of recklessly or negligently emitting air contaminants, in violation of Health and Safety Code sections 42400.3(b) and 42400.1(a). If convicted of any of the charges in the Kincade Complaint, 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.
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 April 20, 2021, the court held an initial hearing in the case. 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. The Utility pled not guilty to all charges on October 13, 2021. A preliminary hearing on the charges is scheduled to begin February 8, 2022.
PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and, as of October 29, 2021, have responded to all data requests received.
Potential liabilities related to the 2019 Kincade fire depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), 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, 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.
As of October 27, 2021, PG&E Corporation and the Utility are aware of approximately 64 complaints on behalf of at least 1,377 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and 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. In addition, on October 18, 2021, Cal Fire filed a complaint seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. 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 2019 Kincade fire. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. On April 8, 2021, the coordination motion judge ordered that the cases be coordinated, and on April 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. The plaintiffs filed master complaints on July 16, 2021, and 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. The plaintiffs filed an opposition to PG&E Corporation and the Utility’s demurrer on September 13, 2021. PG&E Corporation and the Utility filed a reply on October 1, 2021. A hearing on the demurrer is scheduled for November 5, 2021.
If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, 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 from their customers. 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. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.)
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 the information contained in the Kincade EIRs, Cal Fire’s determination of the cause, other information gathered as part of PG&E Corporation’s and the Utility’s investigation, and the charges filed by the Sonoma County District Attorney’s Office, 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 $625 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of PG&E Corporation’s and the Utility’s Quarterly Report on Form 10-Q for the period ended March 31, 2021 (the “Q1 Form 10-Q”), including the status of negotiations with certain subrogation entities, PG&E Corporation and the Utility recorded an additional charge in the first quarter of 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance). The aggregate liability remained unchanged as of September 30, 2021.
Based on the facts and circumstances available to the Utility as of the filing of this Form 10-Q, PG&E Corporation and the Utility recorded an additional liability of $40 million reflected in Other current liabilities on the Condensed Consolidated Financial Statements in the third quarter of 2021 for probable losses in connection with a pending CPUC investigation into the 2019 Kincade fire. The outcome of this investigation is not final and is expected to include additional obligations for the Utility.
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, 2020.
|
|
|
|
|
|
Loss Accrual (in millions)
|
|
Balance at December 31, 2020
|
625
|
|
Accrued Losses
|
175
|
|
Payments (1)
|
(31)
|
|
Balance at September 30, 2021
|
$
|
769
|
|
|
|
(1) As of September 30, 2021, PG&E Corporation and the Utility entered into settlement agreements in connection with the 2019 Kincade fire of approximately $31 million, which has been paid in full by PG&E Corporation and the Utility. Subsequent to September 30, 2021, PG&E Corporation and the Utility have entered into additional settlements and made additional payments and expect to continue to do so.
The aggregate liability of $800 million for claims in connection with the 2019 Kincade fire (before available insurance and before taking into account the settlement payments) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. This $800 million estimate does 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. 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 2019 Kincade fire, including if PG&E Corporation or the Utility were found to have been negligent.
Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Kincade Complaint, 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 victim and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Kincade Complaint, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire would materially exceed the $800 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2019 Kincade fire civil claims. 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 ordered by the court presiding over the criminal proceeding.
The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided.
PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $800 million (before available insurance) 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 proceedings initiated against the Utility by the Sonoma County District Attorney’s Office. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, 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, 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 Sonoma County 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 potential damages.
The process for estimating losses associated with potential claims related to the 2019 Kincade fire 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, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change.
The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of September 30, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million. 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.
2020 Zogg Fire
According to Cal Fire, on September 27, 2020, 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. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “Zogg incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The Zogg incident update reported four fatalities and one injury. The Zogg incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management.
On October 9, 2020, the Utility submitted an EIR (the “Zogg EIR”) to the CPUC indicating that:
•wildfire camera and satellite data on September 27, 2020 show smoke, heat, or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time;
•according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area; and
•the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes.
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 a criminal complaint (the “Zogg Complaint”) charging the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire. The Zogg Complaint alleges four felony counts of involuntary manslaughter based on the four deaths that occurred during the 2020 Zogg fire, in violation of Penal Code section 192(b); six felony counts of recklessly causing a fire and causing great bodily injury, fire to inhabited structure, or fire of structure or forest, with three counts relating to the 2020 Zogg fire and one count relating to each of the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire (each described below), in violation of Penal Code section 452(a)–(c); one felony count of recklessly causing a fire to property of another, based on harm to domesticated animals during the 2020 Zogg fire, in violation of Penal Code section 452(d); two misdemeanor counts of negligent fire starting, one in connection with the 2020 Zogg fire and one in connection with the 2020 Ponder fire, in violation of Health and Safety Code section 13001; one misdemeanor count of failure to maintain firebreak, in connection with the 2020 Zogg fire, in violation of Public Resources Code section 4292; one misdemeanor count of failure to maintain clearance, in connection with the 2020 Zogg fire, in violation of Public Resources Code section 4293; two misdemeanor counts of unlawfully starting a fire, one in connection with the 2020 Zogg fire and one in connection with the 2020 Ponder fire, in violation of Public Resources Code section 4421; two misdemeanor counts of negligently causing a fire by device, one in connection with the 2020 Zogg fire and one in connection with the 2020 Ponder fire, in violation of Public Resources Code section 4435; two misdemeanor counts of failure to comply with regulations, one in connection with the 2020 Zogg fire and one in connection with the 2020 Ponder fire, in violation of Public Utilities Code section 2110; five misdemeanor counts of negligently emitting air contaminants during the 2020 Zogg fire, in violation of Health and Safety Code section 42400.1(a); and five misdemeanor counts of recklessly emitting air contamination that results in an unreasonable risk of great bodily injury during the 2020 Zogg fire, in violation of Health and Safety Code section 42400.3(b). As noted above, some of the charges included in the Zogg Complaint relate to the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. According to the Zogg Complaint, all three of those fires occurred in Shasta County, with the 2020 Daniel fire occurring on July 28, 2020, the 2020 Ponder fire occurring on October 19, 2020, and the 2021 Woody fire occurring on August 19, 2021. If convicted of any of the charges in the Zogg Complaint, 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.
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 do not have access to all of the evidence that Cal Fire gathered.
PG&E Corporation and the Utility have received and are responding to data requests from the CPUC relating to the 2020 Zogg fire. PG&E Corporation and the Utility are providing information and responses to document requests from the Shasta County District Attorney’s Office relating to the 2020 Zogg fire. 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.
Potential liabilities related to the 2020 Zogg fire depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), 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. If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the 2020 Zogg fire, 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. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.
As of October 27, 2021, PG&E Corporation and the Utility are aware of approximately 17 complaints on behalf of at least 315 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and 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 distribution lines was the cause of 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. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. On May 12, 2021, the coordination motion judge ordered that the cases be coordinated, and on June 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. 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. The plaintiffs filed an opposition to PG&E Corporation and the Utility’s demurrer on October 6, 2021. At an October 4, 2021 hearing, the San Francisco County Superior Court set a trial date of February 6, 2023. The court will determine the scope of the trial and the cases to be tried at a later date. A hearing on the demurrer is scheduled for November 5, 2021.
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 the information contained in the Zogg EIR and 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 $275 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of the Q1 Form 10-Q, including the status of negotiations with certain agencies and additional damages information from certain plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire in the amount of $25 million for the three months ended March 31, 2021. Based on additional facts and circumstances available to the Utility as of the date of the filing of PG&E Corporation’s and the Utility’s Quarterly Report on Form 10-Q for the period ended June 30, 2021, including the status of negotiations with certain subrogation entities and individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire of $75 million for the three months ended June 30, 2021, for an aggregate liability of $375 million (before available insurance). There were negotiations with certain subrogation entities during the quarter ended September 30, 2021, however, the aggregate liability remained unchanged as of September 30, 2021.
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, 2020.
|
|
|
|
|
|
Loss Accrual (in millions)
|
|
Balance at December 31, 2020
|
$
|
275
|
|
Accrued Losses
|
100
|
|
Payments (1)
|
(127)
|
|
Balance at September 30, 2021
|
$
|
248
|
|
|
|
(1) As of September 30, 2021, PG&E Corporation and the Utility entered into settlement agreements in connection with the 2020 Zogg fire of approximately $127 million, which has been paid by PG&E Corporation and the Utility. Subsequent to September 30, 2021, PG&E Corporation and the Utility have entered into additional settlements and made additional payments and expect to continue to do so.
The aggregate liability of $375 million for claims in connection with the 2020 Zogg fire (before available insurance and before taking into account the settlement payments) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $375 million estimate does 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. 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, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2020 Zogg fire, 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 the loss will be greater than $375 million and 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. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, 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.
Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Zogg Complaint relating to the 2020 Zogg fire, 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 victim and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Zogg Complaint relating to 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 2020 Zogg fire would materially exceed the $375 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2020 Zogg fire civil claims. 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 ordered by the court presiding over the criminal proceeding.
PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, 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. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties.
The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of September 30, 2021, the Utility has recorded an insurance receivable for $331 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 $16 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. Recovery under the Utility’s insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
2021 Dixie Fire
On July 18, 2021, the Utility submitted an EIR (the “Dixie EIR”) reporting that on July 13, 2021, at approximately 4:40 p.m. Pacific Time, a wildfire was observed in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. The last Cal Fire incident update, dated October 25, 2021 at 7:46 a.m., reported that the 2021 Dixie fire had consumed 963,309 acres in areas of Butte County, Plumas County, Tehama County, Lassen County, and Shasta County; that incident update also reported 1,329 structures destroyed (including 717 residential structures), 95 structures damaged, and one fatality, which according to a report on the U.S. Forest Service website was a fire fighter who passed away due to COVID-19 after returning home from the 2021 Dixie fire.
The Dixie EIR indicated, among other things, that:
•On July 13, 2021 at approximately 7:00 a.m., the Utility’s outage system indicated that Cresta Dam off of Highway 70 in the Feather River Canyon lost power;
•Due to the challenging terrain and road work resulting in a bridge closure, the responding Utility troubleman was not able to reach the pole with the fuse until approximately 4:40 p.m.;
•There the responding Utility troubleman observed two of three fuses opened and what appeared to him to be a healthy green tree leaning into the Bucks Creek 1101 12 kV conductor, which was still intact and suspended on the poles; and
•The responding Utility troubleman also observed a fire on the ground near the base of the tree.
After submitting the Dixie EIR, the Utility learned that it was notified of the outage by the Rock Creek Switching Center receiving Supervisory Control and Data Acquisition alarms indicating a loss of power at the Utility’s Cresta Dam, rather than the outage system. On August 13, 2021, the Utility submitted a supplemental EIR (“20-Day Report”) to the CPUC disclosing additional detail then known about the 2021 Dixie fire.
On July 18, 2021, Cal Fire allowed the Utility to observe while Cal Fire took possession of some Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2021 Dixie fire. Cal Fire has not issued a determination as to the cause.
Subsequent to the ignition of the 2021 Dixie fire, according to the National Wildfire Coordinating Group’s InciWeb incident overview (the “incident overview”), a wildfire began on July 22, 2021 at approximately 5:15 p.m. Pacific Time 3.5 miles north of Quincy in Plumas County, California (the “2021 Fly fire”), located in the service territory of the Utility. The incident overview reports as of July 25, 2021 at 12:00 a.m. that the 2021 Fly fire had consumed 4,300 acres and was 5% contained and that, as of the night of July 24/25, the 2021 Fly fire had merged with the 2021 Dixie fire and that the incident overview would not be providing further updates on the 2021 Fly fire. For the purposes of estimating potential liabilities, the 2021 Fly fire is being considered a part of the 2021 Dixie fire.
The cause of the 2021 Dixie fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. The Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices are investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. PG&E Corporation and the Utility have received document and information requests from Cal Fire and the Butte County District Attorney’s Office. PG&E Corporation and the Utility have received data requests from the SED and OEIS relating to the 2021 Dixie fire. On October 7, 2021, the United States Attorney’s Office for the Eastern District of California served PG&E Corporation and the Utility with a subpoena for the production of documents. It is uncertain when any 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 preliminary and 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.
Potential liabilities related to the 2021 Dixie fire depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), 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 governmental entities. If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the 2021 Dixie fire, 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. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.
As of October 27, 2021, PG&E Corporation and the Utility are aware of approximately 10 complaints on behalf of at least 676 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Plumas, the California Superior Court for the County of Shasta, and the California Superior Court for the County of San Francisco, and 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 distribution lines was the cause of the 2021 Dixie fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. Additional investigations and other actions may arise out of the 2021 Dixie fire. The timing and outcome for resolution of any such claims or investigations are uncertain.
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 the information contained in the Dixie EIR and other 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 for the quarter ended September 30, 2021 (before available recoveries).
The aggregate liability of $1.15 billion for claims in connection with the 2021 Dixie fire (before available recoveries) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $1.15 billion estimate does 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 agencies, including for damage to land and vegetation in national parks or national forests or fire suppression costs, or by state, county and local agencies, including for fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. 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 2021 Dixie fire, including if PG&E Corporation or the Utility were found to have been negligent.
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 loss 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 and other resources damaged or destroyed by the 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 wildfire 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 National Interagency Coordination Center Incident Management Situation Report dated October 22, 2021 at 7:30 a.m. Mountain Time, over $630 million of costs had been incurred in suppressing the 2021 Dixie fire. PG&E currently estimates that the fire burned approximately 70,000 acres of national park and approximately 685,000 acres of national forests.
The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to periods in which both the 2020 Zogg fire and 2021 Dixie fire occurred in an aggregate amount of $900 million. Recovery under the Utility’s insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire. As of September 30, 2021, the Utility has recorded an insurance receivable of $569 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 $331 million insurance receivable recorded in connection with the 2020 Zogg fire. 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.
To the extent liabilities related to the 2021 Dixie fire exceed $1.0 billion, the Utility would 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. As of September 30, 2021, the Utility has 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 has also recorded a $98 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 $339 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. (See “Regulatory Recovery” below).
The cause of the 2021 Dixie fire remains under investigation and there are a number of unknown facts surrounding the cause of the 2021 Dixie fire, the Utility’s liability for the fire, and if liability is incurred, the Utility’s ability to seek recovery of costs from insurance, the Wildfire Fund (or whether such amounts are required to be reimbursed) and regulatory recovery. The Utility could be subject to significant liability in connection with this fire. If such liability was 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.
Loss Recoveries
PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. Failure to obtain substantial or full recovery of costs related to wildfires in a timely manner or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Total probable recoveries for the 2021 Dixie fire as of September 30, 2021 are:
|
|
|
|
|
|
Recovery sources (in millions)
|
2021 Dixie fire
|
Insurance
|
$
|
569
|
|
FERC TO rates
|
98
|
|
WEMA
|
339
|
|
AB 1054 Wildfire Fund
|
150
|
|
Probable recoveries at September 30, 2021
|
$
|
1,156
|
|
Insurance
Insurance Coverage
In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period of April 13, 2021 to April 1, 2022, and approximately $32 million in wildfire liability reinsurance for the period of April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire liability reinsurance for the period of July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period of August 1, 2020 to August 1, 2021. On August 1, 2021, the $600 million of existing wildfire liability coverage renewed on a 12-month term covering the period of August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.
In June 2021, the Utility purchased approximately $535 million in non-wildfire liability coverage for the period of June 1, 2021 to April 1, 2022 at a cost of approximately $89 million. This coverage is in addition to approximately $140 million in existing non-wildfire liability insurance for the period of August 1, 2020 to August 1, 2021. In connection with the June 2021 renewal, the Utility procured an extension of this existing coverage to April 1, 2022 at a premium cost of approximately $30 million. The Utility also has $50 million in additional non-wildfire liability coverage available through one of its wildfire liability policies with shared limits. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million. As of September 30, 2021, PG&E Corporation and the Utility had prepaid insurance of $537 million, reflected in Other current assets on the Condensed Consolidated Balance Sheets.
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 general liability insurance coverage. An advice letter is required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage.
Insurance Receivable
PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through September 30, 2021, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $331 million for probable insurance recoveries in connection with the 2020 Zogg fire and $569 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.
If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
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:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance Receivable (in millions)
|
2021 Dixie fire
|
|
2020 Zogg fire
|
|
2019 Kincade fire
|
|
2017 Northern California wildfires
|
|
Total
|
Balance at December 31, 2020
|
$
|
—
|
|
|
$
|
219
|
|
|
$
|
430
|
|
|
$
|
25
|
|
|
$
|
674
|
|
Accrued insurance recoveries
|
569
|
|
|
112
|
|
|
—
|
|
|
—
|
|
|
681
|
|
Reimbursements
|
—
|
|
|
—
|
|
|
(16)
|
|
|
(25)
|
|
|
(41)
|
|
Balance at September 30, 2021
|
$
|
569
|
|
|
$
|
331
|
|
|
$
|
414
|
|
|
$
|
—
|
|
|
$
|
1,314
|
|
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 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, for the quarter ended September 30, 2021, the Utility recorded a $98 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
In June 2018, the CPUC approved the establishment of the WEMA, which provides for tracking of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered in rates. As noted above, the Utility capitalizes and records as regulatory assets costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. For the quarter ended September 30, 2021, 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 through the WEMA and the Utility recorded a $339 million regulatory asset.
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. 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 year (“Coverage Year”) and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054. Eligible electric utility companies must declare a Coverage Year of exactly twelve months, that commences as of a certain date and time, to the administrator of the Wildfire Fund. PG&E Corporation and the Utility have yet to make a formal declaration to the Wildfire Fund administrator. The accrued Wildfire Fund receivable as of September 30, 2021 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire.
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 applying the prudency standard in AB 1054, not to be just and reasonable, 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 $2.9 billion based on its 2021 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 fails 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. The same prudency standard will be applied in any CPUC review of an application filed by the Utility seeking recovery of costs recorded to WEMA.
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. Those requirements are: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, (iv) the electrical corporation has established an executive incentive compensation structure approved by the division and structured to promote safety as a priority and to ensure public safety and utility financial stability with performance metrics, including incentive compensation based on meeting performance metrics that are measurable and enforceable, for all executive officers, (v) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues, and (vi) the electrical corporation has established a compensation structure for any new or amended contracts for executive officers, as set forth in section 8389(e) of the Public Utilities Code. 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. On January 14, 2021, the OEIS approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. 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. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of OEIS’ issuance of the safety certification, which the CPUC declined to provide on April 14, 2021.
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. For more information regarding contributions to the Wildfire Fund, see Note 3 above.
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.
PG&E Corporation and the Utility record a receivable for the Wildfire Fund when it is deemed probable that recovery of a recorded loss will occur. As of September 30, 2021, 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 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.
Wildfire-Related Derivative Litigation
Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in 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 are 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. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, 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 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. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action. The assignment became effective as of the Effective Date of the Plan. On November 12, 2020, the trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter, to which the parties later stipulated. On March 8, 2021, the court granted the parties’ stipulation 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 February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. 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 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 is a party to the action. A case management conference was held on March 18, 2021 and the Trotter v. Chew and Trotter v. Williams actions were consolidated on March 30, 2021. A hearing on the defendants’ demurrers and a further case management conference was held August 4, 2021, and the demurrers have been taken under submission. Trial is set for June 27, 2022.
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. A stipulation and proposed order to voluntarily dismiss this action was filed on April 20, 2021 and a case management conference on the dismissal order is set for December 8, 2021.
The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.
Securities Class Action Litigation
Wildfire-Related Securities Class Action
In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California (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 related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. 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 the Public Employees Retirement Association of New Mexico (“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.
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 names 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 is named as a defendant. The complaint alleges 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. The complaint asserts claims under section 11 and section 15 of the Securities Act, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. 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 conclusion of 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.
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims
Claims against PG&E Corporation and the Utility 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, will be resolved 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 the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the 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 Effective 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 Effective 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 business, financial condition, results of operations, 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 (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).
The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, PERA filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, PERA filed a notice of appeal regarding the denial of its motion. On March 8, 2021, the District Court issued an order dismissing the appeal.
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 February 16, 2021, the TCC filed a motion to dismiss PERA’s appeal. On March 9, 2021, PERA filed its opposition to the motion to dismiss, and on March 16, 2021, PG&E Corporation and the Utility filed a statement with respect to the motion to dismiss. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction, and denied as moot the TCC’s motion to dismiss. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the Ninth Circuit Court of Appeals. The 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 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. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. 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 requesting trading information from holders of Subordinated Claims. Pursuant to those procedures, PG&E Corporation and the Utility have filed in the Bankruptcy Court 16 separate omnibus objections 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 several 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.
De-energization Securities Class Action
On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a then-current director and certain then-current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s PSPS events, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint 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, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing co-lead plaintiffs and approving the selection of the plaintiffs’ counsel.
On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a current officer of PG&E Corporation as defendants, and no longer asserts claims against certain current and former officers of PG&E Corporation previously named in the action.
On May 15, 2020, the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020, the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter.
On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement.
The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing was held on March 11, 2021, where the District Court requested certain supplemental filings, which the parties filed on March 18, 2021. On April 20, 2021, the District Court granted the motion for preliminary approval of the settlement. On July 12, 2021, the plaintiffs filed a motion for final approval of the settlement. At a final hearing to approve the settlement on September 16, 2021, the District Court requested further information from the plaintiffs, which they provided. The District Court has since taken the matter under submission. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.
Indemnification Obligations and Directors’ and Officers’ 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 extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated above in Note 10 under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain directors’ and officers’ 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 in Note 10 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 multiple years of directors’ and officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter may impact the directors’ and officers’ insurance proceeds available in the other matters.
On March 17, 2021, the trustee for the Fire Victim Trust filed a lawsuit entitled Trotter v. PG&E Corporation, et al., in San Francisco Superior Court, seeking, among other things, a declaration that the trustee for the Fire Victim Trust be permitted to participate in the arbitration with the carriers. The trustee named PG&E Corporation, the Utility, and the insurance carriers as defendants. On March 25, 2021, PG&E Corporation and the Utility removed the action to the Bankruptcy Court. On March 29, 2021, the Fire Victim Trust made a motion to remand the lawsuit back to state court, which the Bankruptcy Court denied on April 20, 2021. On April 30, 2021, the Fire Victim Trust moved for summary judgment. Oppositions and cross-motions to the summary judgment motion were filed by PG&E Corporation, the Utility and the insurance carriers on May 21, 2021. The Fire Victim Trust filed a reply on May 28, 2021, and the matter was heard on June 15, 2021. On June 22, 2021, the Bankruptcy Court entered an order denying the Fire Victim Trust’s motion for summary judgment and granting the defendants’ cross-motions for summary judgment. On June 29, 2021, the Bankruptcy Court entered judgment in favor of all defendants and against the Fire Victim Trust.
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 directors’ and officers’ 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.
District Attorneys’ Offices Investigations
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. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.
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, which was established under the Plan of Reorganization in Bankruptcy Court and is managed by a trustee and a claims administrator. The Court continued the hearing to February 25, 2022 for a further update.
Following the 2019 Kincade fire, the Sonoma County District Attorney’s Office opened a criminal investigation of the 2019 Kincade fire. On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint against the Utility related to the 2019 Kincade fire. For more information, see “2019 Kincade Fire” above.
Following the 2020 Zogg fire, the Shasta County District Attorney’s Office opened a criminal investigation of the 2020 Zogg fire. On September 24 2021, the Shasta County District Attorney’s office filed a criminal complaint against the Utility related to the 2020 Zogg fire and three other fires. For more information, see “2020 Zogg Fire” above.
Following the 2021 Dixie fire, several District Attorney’s Offices and the United States Attorney’s Office for the Eastern District of California have opened criminal investigations of the 2021 Dixie fire, and potentially other fires (including, the 2021 Bader fire and the 2021 Fly fire). For more information, see “2021 Dixie Fire” above.
Additional investigations and other actions may arise out of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, or other fires. The timing and outcome for resolution of any such investigations are uncertain.
NOTE 11: 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’s and the Utility’s policy is to 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.
Enforcement Matters
U.S. District Court Matters and Probation
In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
CPUC and FERC Matters
Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code, Commission General Orders or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.
As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and the Coalition of California Utility Employees (“CUE”) jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. The settlement agreement became effective on the Effective Date.
Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility recorded $1.625 billion of the disallowed costs during the year ended December 31, 2020.
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(in millions)
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Description(1)
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Expense
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Capital
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Total
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Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)
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$
|
236
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|
|
$
|
—
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|
|
$
|
236
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|
Transmission Safety Inspections and Repairs Expense (TO)(2)
|
433
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|
|
—
|
|
|
433
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|
Vegetation Management Support Costs (FHPMA)
|
36
|
|
|
—
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|
|
36
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|
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)
|
82
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|
|
66
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|
|
148
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|
2018 Camp Fire CEMA Expense (CEMA)
|
435
|
|
|
—
|
|
|
435
|
|
2018 Camp Fire CEMA Capital for Restoration (CEMA)
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—
|
|
|
253
|
|
|
253
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|
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)
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—
|
|
|
84
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|
|
84
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Total
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$
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1,222
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|
|
$
|
403
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|
|
$
|
1,625
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(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
(2) Transmission amounts are under the FERC’s regulatory authority.
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.
The Utility expects additional system enhancement spending pursuant to the settlement agreement to occur through 2025.
On April 20, 2020, the assigned commissioner issued a decision different adopting, with changes, the proposed modifications set forth in the request for review. The decision different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for system enhancement initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to customers to those savings generated by disallowed operating expenditures. The decision different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the decision different to the CPUC, accepting the modifications. The CPUC approved the decision different on May 7, 2020.
As it relates to the additional $198 million in disallowed costs as adopted in the decision different, the Utility has recorded the full amount, primarily in the WMPMA, through September 30, 2021.
On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the applications for rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeal. Responses to the petition were submitted on March 25, 2021. On July 29, 2021, the appeal was rejected by the appellate court. The deadline for any further appeals was August 9, 2021. No further appeals were filed.
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 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing 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. Initial briefs were filed on December 14, 2020, and reply briefs were filed on February 12, 2021. In addition, the order addresses a number of other issues including: (1) approving depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%; (2) reducing forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period; and (3) upholding the initial decision’s rejection of the Utility’s direct assignment of common plant to transmission and requiring the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. On the direct assignment issue, applying labor ratios to certain common plant would result in an allocation of 6.15% of common plant to the FERC in comparison to 8.84% under the Utility’s direct assignment method.
The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021 in the District of Columbia Court of Appeals. On March 4, 2021, the Court of Appeals issued an order holding the Utility’s petition for review in abeyance until July 14, 2021, so that the FERC would have time to issue a substantive order on rehearing. On April 15, 2021, the FERC issued a substantive order denying the Utility’s request for rehearing and granting the request for rehearing of two parties regarding the impact of the Tax Act on TO18 rates in January and February 2018. The Utility sought rehearing of the FERC’s reversal on the applicability of the Tax Act on TO18 rates which may affect the timing for judicial review of the FERC order on the Utility’s request for rehearing. On June 8, 2021, the Utility filed a second petition for review in the Court of Appeals on the aspects of the rehearing order other than the Tax Act. On June 17, 2021, the FERC issued a notice denying the Utility’s request for rehearing on the applicability of the Tax Act on TO18 rates by operation of law and providing for further consideration. On June 21, 2021, the Court of Appeals ordered that the Utility’s two petitions for review be consolidated and held both petitions in abeyance until July 14, 2021. On July 22, 2021, the Court of Appeals ordered that the Utility’s two petitions for review be held in abeyance until further order of the court and directed the parties to file motions to govern further proceedings within 75 days after the FERC issues a substantive order on the Utility’s request for rehearing on the applicability of the Tax Act on TO18 rates. On August 13, 2021, the Utility filed a third petition for review in the Court of Appeals from the FERC’s June 17, 2021 notice, which the Court of Appeals ordered to be consolidated with the Utility’s prior two petitions and subject to the deadlines in the Court’s July 22, 2021 order. On August 19, 2021, the FERC issued a substantive order denying the Utility’s request for rehearing on the applicability of the Tax Act on the TO18 rates. On October 15, 2021, the Utility filed a fourth petition for review in the Court of Appeals from the FERC’s August 19, 2021 rehearing order. The parties are required to file a motion to govern further proceedings in the Court of Appeals by November 2, 2021.
As a result of the FERC’s April 15, 2021 order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the third quarter of 2021 by approximately $308 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $180 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.
2018 CEMA Interim Rate Relief Subject to Refund
On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation.
On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a revised application, revised testimony and revised workpapers, reflecting a new revenue requirement request of $669 million, pursuant to a CPUC ruling allowing these changes.
The Utility expects to file a settlement agreement with certain parties in early November 2021 and for the CPUC to issue a final decision in the first or second quarter of 2022.
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. All of the costs presented in the 2020 WMCE application are subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.
The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflect work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million. The requested revenue for CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events.
Hearings were held in June 2021. On July 23, 2021, the parties filed opening briefs and reply briefs were filed on August 6, 2021. On September 21, 2021, the Utility filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this hearing to April 1, 2022.
For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see Note 4 above and the 2020 Form 10-K.
2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit
On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of 2011 to 2014 capital spending in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million of recorded expenditures. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.
On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million of 2015 to 2022 revenue requirements associated with the $512 million of certified capital expenditures. On July 7, 2021, a joint motion was filed to adopt a settlement agreement. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. On July 9, 2021, the ALJ granted a motion to include an additional party. The ALJ ruled that the party’s participation would be limited to commenting on the settlement agreement and proposed decision, and that the party may not broaden the current scope of issues or introduce new evidentiary information.
The scoping memo calls for the issuance of a PD in the fourth quarter of 2021.
The Utility is unable to determine the timing and outcome of this proceeding.
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 (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $88 million and $134 million at September 30, 2021 and December 31, 2020, 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 January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. On March 30, 2020, the Bankruptcy Court granted the Utility’s motion to dismiss this class action 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. The appellant filed his opening brief on June 25, 2021. A former executive director of the CPUC filed an amicus brief on July 2, 2021, asking the Ninth Circuit to reverse the decision of the District Court and to remand the case for further proceedings. The answering brief of PG&E Corporation and the Utility was filed August 25, 2021. On September 1, 2021, the CPUC filed an amicus brief asking the Ninth Circuit to affirm the District Court’s dismissal. The appellant’s reply brief was filed on October 15, 2021.
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 and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, on July 2, 2021, the CPUC issued a ruling denying the Utility’s motion to dismiss but limiting the issues to be determined to whether the Utility’s activities in response to the 2020 CZU Lightning Complex fire violated the Utility’s obligations under certain sections of Public Utilities Code and CPUC orders. The CPUC has set a deadline of November 19, 2021 for all parties to submit direct prepared testimony and scheduled evidentiary hearings in late January 2022. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues.
Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. 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. Violations can result in penalties, remediation and other relief.
Environmental Remediation Contingencies
The Utility’s environmental remediation liability is primarily included in noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
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Balance at
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(in millions)
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September 30, 2021
|
|
December 31, 2020
|
Topock natural gas compressor station
|
$
|
299
|
|
|
$
|
303
|
|
Hinkley natural gas compressor station
|
129
|
|
|
132
|
|
Former manufactured gas plant sites owned by the Utility or third parties (1)
|
686
|
|
|
659
|
|
Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites (2)
|
112
|
|
|
111
|
|
Fossil fuel-fired generation facilities and sites (3)
|
74
|
|
|
96
|
|
Total environmental remediation liability
|
$
|
1,300
|
|
|
$
|
1,301
|
|
|
|
|
|
(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 manufactured gas plant 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 at September 30, 2021, 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. At September 30, 2021, the Utility expected to recover $1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.
For more information, see remediation site descriptions below and see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.
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 will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $219 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 HSM, where 90% of the costs are recovered in 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 $138 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 $479 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 HSM, where 90% of the costs are recovered in 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 $49 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 HSM, where 90% of the costs are recovered in 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 $44 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 $42 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 2020 Form 10-K.
Tax Matters
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by section 382 of the Internal Revenue Code.
As a result of the grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion which will be offset by payments made by the Fire Victim Trust to the fire victims and the net activities of the Fire Victim Trust to date. Additionally, there was a $1.3 billion charge, net of tax, decreasing net deferred tax assets for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will recognize income tax benefits and the corresponding deferred tax asset as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. As of October 27, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact in PG&E Corporation’s and the Utility’s consolidated financial statements for the quarter ended September 30, 2021. For more information, see Note 6 above.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision for the Utility:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Federal statutory income tax rate
|
21.0
|
%
|
|
21.0
|
%
|
|
21.0
|
%
|
|
21.0
|
%
|
Increase (decrease) in income tax rate resulting from:
|
|
|
|
|
|
|
|
State income tax (net of federal benefit) (1)
|
303.4
|
%
|
|
(17.8)
|
%
|
|
45.3
|
%
|
|
30.9
|
%
|
Effect of regulatory treatment of fixed asset differences (2)
|
(156.8)
|
%
|
|
(113.5)
|
%
|
|
(57.4)
|
%
|
|
(48.1)
|
%
|
Fire Victim Trust (3)
|
994.5
|
%
|
|
—
|
%
|
|
155.4
|
%
|
|
—
|
%
|
Bankruptcy and Emergence
|
0.5
|
%
|
|
1.4
|
%
|
|
0.3
|
%
|
|
75.2
|
%
|
Other, net
|
25.8
|
%
|
|
(8.0)
|
%
|
|
4.8
|
%
|
|
(4.5)
|
%
|
Effective tax rate
|
1,188.4
|
%
|
|
(116.9)
|
%
|
|
169.4
|
%
|
|
74.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. PG&E Corporation’s and the Utility’s effective tax rate is impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2021 and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) Includes the effect of the grantor trust election. For more information, see Note 6 above.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision for PG&E Corporation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Federal statutory income tax rate
|
21.0
|
%
|
|
21.0
|
%
|
|
21.0
|
%
|
|
21.0
|
%
|
Increase (decrease) in income tax rate resulting from:
|
|
|
|
|
|
|
|
State income tax (net of federal benefit) (1)
|
788.8
|
%
|
|
84.2
|
%
|
|
61.8
|
%
|
|
(15.5)
|
%
|
Effect of regulatory treatment of fixed asset differences (2)
|
(413.4)
|
%
|
|
403.7
|
%
|
|
(81.9)
|
%
|
|
25.2
|
%
|
Fire Victim Trust (3)
|
2,621.7
|
%
|
|
—
|
%
|
|
221.8
|
%
|
|
—
|
%
|
Bankruptcy and Emergence
|
1.3
|
%
|
|
(47.2)
|
%
|
|
0.4
|
%
|
|
(69.4)
|
%
|
Other, net
|
72.6
|
%
|
|
31.1
|
%
|
|
8.1
|
%
|
|
3.3
|
%
|
Effective tax rate
|
3,092.0
|
%
|
|
492.8
|
%
|
|
231.2
|
%
|
|
(35.4)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. PG&E Corporation’s and the Utility’s effective tax rate is impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2021 and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) Includes the effect of the grantor trust election. For more information, see Note 6 above.
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, 2020, the Utility had undiscounted future expected obligations of approximately $35 billion. (See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.)
Oakland Headquarters Lease and Sale of SFGO
On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “TMG Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The TMG Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the TMG Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “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”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the TMG Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.
Pursuant to the terms of the TMG Agreement, concurrent with the Landlord’s acquisition of the building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million on or before the Lease Date (as defined in the Agreement and the Lease Agreement), and (ii) a lease security letter of credit in the amount of $75 million.
The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 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 the 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. As of September 30, 2021, the Lease Agreement did not have any impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.
On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO in connection with the TMG Agreement. On May 21, 2021, the Utility entered into a purchase agreement (the “Purchase Agreement”) with HNG Atlas US LP to sell the SFGO for $800 million, subject to prorations and adjustments. On May 26, 2021, the Utility filed an amended settlement agreement with the CPUC. Under the amended settlement agreement, the parties agreed that (1) the Utility’s headquarters strategy, including the move to Oakland, the sale of SFGO, and the terms of the agreement to lease and the option to purchase the Lakeside Building, is reasonable, (2) all of the gain on sale of SFGO will be distributed to customers over five years, beginning in 2022, and (3) the costs associated with the Utility’s move to the Lakeside Building and development will be considered at later stages of the proceeding and through a petition for modification of the final decision in the proceeding. On July 22, 2021, the CPUC issued a PD approving the purchase agreement and the ratemaking treatment proposed under the parties’ settlement. On August 19, 2021, the CPUC issued a final decision approving the amended settlement agreement.
On September 17, 2021, the sale of SFGO closed and the Utility received net cash proceeds of $749 million. As of September 30, 2021, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets reflect the sale of SFGO as a reduction to Property, plant, and equipment by $565 million and to Accumulated depreciation by $238 million. Additionally, in accordance with the final decision, the pre-tax gain of $422 million was recorded to current and noncurrent regulatory liabilities as of September 30, 2021 and will be amortized for the benefit of customers over five years, along with corresponding reductions to the adopted GRC 2020 revenue requirements for 2021 and 2022 associated from the removal of SFGO from rate base after the sale.
Additionally on September 17, 2021, the Utility entered into a leaseback agreement with HNG Atlas US LP (the “Leaseback Agreement”) to leaseback certain space in SFGO to accommodate essential onsite work. The Leaseback Agreement commenced on September 17, 2021 and continues through various dates for the various leased spaces, with December 31, 2023 being the latest lease expiration date.
Certain provisions in the Leaseback Agreement have met the appropriate thresholds for lease accounting and have been recorded to Operating lease right of use asset on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets in the amount of $7 million as of September 30, 2021.