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.

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 and Long-term debt, respectively, on the Condensed Consolidated Balance Sheets. As of June 30, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated.

The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. 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 June 30, 2021 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.7 billion and $2.6 billion, respectively, and outstanding borrowings of $1.0 billion and $1.0 billion, respectively, under the Receivables Securitization Program.

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 June 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 June 30, 2021, it did not consolidate any of them.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2021 and 2020 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2021		2020		2021		2020
Service cost for benefits earned (1)	$	146	$	132	$	16	$	16
Interest cost	162		179		13		15
Expected return on plan assets	(262)		(261)		(35)		(35)
Amortization of prior service cost	(2)		(2)		3		4
Amortization of net actuarial loss	2		1		(8)		(5)
Net periodic benefit cost	46		49		(11)		(5)
Regulatory account transfer (2)	37		34		—		—
Total	$	83	$	83	$	(11)	$	(5)


	Pension Benefits				Other Benefits
	Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Service cost for benefits earned (1)	$	293	$	264	$	32	$	31
Interest cost	323		357		26		31
Expected return on plan assets	(523)		(522)		(70)		(69)
Amortization of prior service cost	(3)		(3)		7		7
Amortization of net actuarial loss	3		2		(16)		(10)
Net periodic benefit cost	93		98		(21)		(10)
Regulatory account transfer (2)	74		68		—		—
Total	$	167	$	166	$	(21)	$	(10)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) consisted of the following:


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Three Months Ended June 30, 2021
Beginning balance	$	(38)	$	17	$	(21)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $1, respectively)	(1)		2		1
Amortization of net actuarial loss (net of taxes of $1 and $2, respectively)	1		(6)		(5)
Regulatory account transfer (net of taxes of $0 and $1, respectively)	—		4		4
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(38)	$	17	$	(21)


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Three Months Ended June 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 $1, respectively)	(1)		3		2
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	—		(4)		(4)
Regulatory account transfer (net of taxes of $0 and $0, respectively)	1		1		2
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(22)	$	17	$	(5)


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Six Months Ended June 30, 2021
Beginning balance	$	(39)	$	17	$	(22)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $2, respectively)	(2)		5		3
Amortization of net actuarial loss (net of taxes of $1 and $4, respectively)	2		(12)		(10)
Regulatory account transfer (net of taxes of $0 and $2, respectively)	1		7		8
Net current period other comprehensive gain (loss)	1		—		1
Ending balance	$	(38)	$	17	$	(21)


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Six Months Ended June 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 $2, respectively)	(2)		5		3
Amortization of net actuarial loss (net of taxes of $1 and $3, respectively)	1		(7)		(6)
Regulatory account transfer (net of taxes of $0 and $1, respectively)	1		2		3
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(22)	$	17	$	(5)

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.

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:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2021		2020		2021		2020
Electric
Revenue from contracts with customers
Residential	$	1,352	$	987	$	2,815	$	2,230
Commercial	1,183		1,075		2,196		2,082
Industrial	305		342		632		682
Agricultural	431		368		583		491
Public street and highway lighting	18		17		35		34
Other (1)	285		269		222		203
Total revenue from contracts with customers - electric	3,574		3,058		6,483		5,722
Regulatory balancing accounts (2)	377		377		863		753
Total electric operating revenue	$	3,951	$	3,435	$	7,346	$	6,475

Natural gas
Revenue from contracts with customers
Residential	$	418	$	426	$	1,626	$	1,492
Commercial	139		110		384		344
Transportation service only	346		296		672		643
Other (1)	(137)		(159)		(184)		(180)
Total revenue from contracts with customers - gas	766		673		2,498		2,299
Regulatory balancing accounts (2)	498		425		87		65
Total natural gas operating revenue	1,264		1,098		2,585		2,364
Total operating revenues	$	5,215	$	4,533	$	9,931	$	8,839

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 at least 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 June 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 June 30, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other noncurrent liabilities, $464 million in current assets - Wildfire Fund asset, and $5.6 billion in noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three and six months ended June 30, 2021, the Utility recorded amortization and accretion expense of $118 million and $237 million, respectively. The amortization of the asset, accretion of the liability, and if applicable, impairment 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 US 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, 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 will assess the Wildfire Fund asset for impairment 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 impairment 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. At June 30, 2021, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

PG&E Corporation and the Utility have three 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. 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 six months ended June 30, 2021, expected credit losses of $113 million and $189 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 six months ended June 30, 2020, expected credit losses of $44 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 June 30, 2021, the RUBA current balancing accounts receivable balance was $182 million, and CPPMA and FERC long-term regulatory asset balances were $26 million and $26 million, respectively.

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 agreed to pay the Utility a purchase price of $973 million. SBA paid the Utility $946 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement through August 15, 2021.

The Utility recorded approximately $365 million of the $946 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 $946 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.

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.

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.