FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

PACIFIC GAS AND ELECTRIC COMPANY

Year/Period of Report

End of:

2023

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered, or
4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).

What and Where to Submit

Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426

For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

The CPA Certification Statement should:

Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.

When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS

Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......

"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.

Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10

"Sec. 309.

The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM NO.

1/3-Q

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Identification

01 Exact Legal Name of Respondent

PACIFIC GAS AND ELECTRIC COMPANY

02 Year/ Period of Report

End of:

2023

03 Previous Name and Date of Change (If name changed during year)

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

300 LAKESIDE DRIVE, OAKLAND, CA 94612

05 Name of Contact Person

JENNIFER GARBODEN

06 Title of Contact Person

DIRECTOR, CORP ACCOUNTING

07 Address of Contact Person (Street, City, State, Zip Code)

300 LAKESIDE DRIVE, OAKLAND, CA 94612

08 Telephone of Contact Person, Including Area Code

(415) 973-5456

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

08/17/2023

Quarterly Corporate Officer Certification

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Stephanie Williams

02 Title

Vice President, CFO, and Controller, Pacific Gas and Electric Company

03 Signature

/s/ Stephanie Williams

04 Date Signed (Mo, Da, Yr)

08/17/2023

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

List of Schedules
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. State the estimated annual effect and nature of any important wage scale changes during the year. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. (Reserved.) If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1. Changes in and important additions to franchise rights: PG&E and the City of Richmond have reached agreement on a change in the electric and gas franchise fee rates. The franchise agreements provide either party may request a change in the rate upon the 20-year anniversary of granting the franchise. The parties previously held an arbitration on whether Richmond satisfied certain pre-conditions to requesting a change in rate, which resulted in an arbitrator’s decision the conditions were satisfied. PG&E and the City thereafter reached agreement on a new 2.3% rate for the gas and electric franchises. Subject to approval from the California Public Utilities Commission, the 1.3% increase in the gas franchise rate, and the 1.3% of increase in the electric franchise rate will be collected as a surcharge from Richmond customers. The change in rates are reflected in amendments to the electric and gas franchises, which the City Council adopted as ordinances in May of 2023.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: None.
3. Purchase or sale of an operating unit or system: Sale: None. Purchase: None.
4. Important leaseholds that have been acquired or given, assigned or surrendered: The following leases were extended in Q2 2023: •3065 Gold Camp Drive, Rancho Cordova, CA: Lease term of 07/01/2012 – 06/30/2029 and total minimum lease payments of $18,391,848.12 •3955 Arch Road, Stockton, CA: Lease term of 5/1/2006 – 12/31/28 and total minimum lease payments of $1,267,200
Important extension or reduction of transmission or distribution system: Electric: None. Gas: None.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee: a) Financings: On June 5, 2023, the Utility completed the sale of (i) $850 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.15 billion aggregate principal amount of 6.400% First Mortgage Bonds due 2033 and (iii) $500 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of $375 million aggregate principal amount of 3.25% First Mortgage Bonds due June 15, 2023 and for general corporate purposes, including for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility intends to use the remaining net proceeds to repay the $500 million aggregate principal amount of 4.25% First Mortgage Bonds due August 1, 2023. b) Bank Credit Facilities: On June 9, 2023, the Utility entered into an amendment to the Utility Receivables Securitization Program to, among other things, extend the scheduled termination date from September 30, 2024 to June 9, 2025. On June 22, 2023, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date to June 22, 2028 (subject to two one-year extensions at the option of the Utility), (ii) increase the maximum letter of credit sublimit to $2.0 billion, and (iii) increase the uncommitted incremental facility to up to $1.0 billion. Short-term borrowings were authorized by CPUC Decision No. 09-05-002. c) Surety Bonds and Financial Guarantees Backed by Insurance: From April 1, 2023 to June 30, 2023 $101,025,621.28 in surety bond obligations were issued in conformance with the CPUC Decision No. 12-04-015. As of June 30, 2023, there was a total of $725,735,268.61 in outstanding surety bond obligations. d) Capital Support: CPUC Decision No. 91-12-057 (as modified by Decision No. 99-04-068) authorized the Utility to provide capital support to regulated and unregulated subsidiaries. At June 30, 2023, the Utility has no outstanding future capital commitments to unregulated subsidiaries and affiliates. e) Preferred stock repayments: None.
7. Changes in articles of incorporation or amendments to charter. Explain the nature and purpose of such changes or amendments: None.
8. State the estimated annual effect and nature of any important wage scale changes during the period: None.
9. State briefly the status of any materially important legal proceedings pending at the end of the period and the results of any such proceedings culminated during the period: Refer to Part I, Item 3 in PG&E Corporation and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2022, which describes certain legal proceedings pursuant to Item 103 of Regulation S-K of the Securities Exchange Act of 1934, as amended. Four copies of the Form 10—K report are filed in accordance with Instruction III(c) of Instructions For Filing the FERC Form No. 1. Please also refer to PG&E Corporation and the Utility’s joint quarterly report on Form 10-Q for the quarters ended March 31, 2023 and June 30, 2023, for the status of materially important legal proceedings pending or completed as of the end of each respective period.
10. Describe briefly any materially important transactions of the not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest: “Five Percent Owners” During the second quarter of 2023, numerous beneficial owners of at least 5 percent of PG&E Corporation common stock provided services to, or were involved in transactions with, PG&E Corporation, Pacific Gas and Electric Company (“Utility”), and related entities. These beneficial owners were identified based on a review of Schedule 13Ds/13Gs (or any amendments) filed with the Securities and Exchange Commission (SEC) as of the date of this report. The Vanguard Group (“Vanguard”). Vanguard provided asset management services to the trusts securing benefits in the event of a change in control, and The PG&E Corporation Foundation. In each of these cases, the services are subject to terms comparable to those that could be obtained in arm’s-length dealings with an unrelated third party. PG&E Corporation and the Utility expect that these entities will continue to provide similar services and products in the future, in the normal course of business operations. We expect that the value of payments to Vanguard for such services in 2023 will be similar to the value in 2022, which was below the $120,000 disclosure threshold set forth in SEC Reg S-K Item 404(a). Fidelity Management and Research Company LLC (“FMC”). Affiliates of FMC provide recordkeeper and trustee services for compensation and benefit plans sponsored by PG&E Corporation and the Utility. The terms of the engagements are comparable to those that could be obtained in arm’s-length dealings with an unrelated third party. PG&E Corporation and the Utility expect that these entities will continue to provide similar services and products in the future, in the normal course of business operations. We expect that the value of payments to FMC affiliates in 2023 will be similar to the value in 2022, which was approximately $489,000. BlackRock, Inc. (“BlackRock”). Affiliates of BlackRock provide asset management services to the Utility’s nuclear decommissioning trusts, customer credit trust and various trusts associated with the Companies’ employee benefit plans. The terms of the engagements are comparable to those that could be obtained in arm’s-length dealings with an unrelated third party. PG&E Corporation and the Utility expect that these entities will continue to provide similar services and products in the future, in the normal course of business operations. We expect that the value of payments to BlackRock affiliates in 2023 will be similar to the value in 2022, which was approximately $3.6 million. Fire Victim Trust (Trust) The following arrangements with the Trust have continuing obligations: Share Exchange and Tax Matters Agreement. On July 8, 2021, PG&E Corporation, the Utility, PG&E ShareCo LLC (“ShareCo”), and the Trust entered into an agreement (the “Share Exchange and Tax Matters Agreement”), pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Trust effective retroactively to the inception of the Trust. Under the 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 Trust pursuant to the PG&E Corporation’s and the Utility’s Chapter 11 plan of reorganization (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). When the Trust desires to sell any or all of its Plan Shares, the 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. When the Trust notifies the Utility that it intends to sell shares, ShareCo (on behalf of the Utility) will transfer the New Shares to the Trust, and the Trust will transfer the Plan Shares to the Utility. During the second quarter of 2023, one such exchange was completed for an aggregate of 60,000,000 shares. Amended and Restated Registration Rights Agreement: In addition to various obligations relating to registration of PG&E Corporation common stock (summarized in PG&E Corporation’s current reports on Form 8-K filed on June 24, 2020 and July 9, 2021), PG&E Corporation is required to pay the fees and expenses for one counsel for the Trust (subject to a cap of $100,000 for the initial registration and for each assisted underwritten offering) in connection with the initial registration and each assisted underwritten offering, but excluding any underwriting discounts or commissions or fees and expenses of the Trust. During the second quarter of 2023, no such payments were made.

13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period: Officers The following individuals became officers of the Utility: •David P. Gabbard, Vice President, Pacific Generation •Kristin Manz, Vice President, Finance and Planning •Roderick O. Robinson, Vice President, Electric System Operations •Mary Bianchini, Assistant Corporate Secretary •Gabriel Briggs, Assistant Corporate Secretary The following individuals had title changes: •Ahmad Ababneh, Vice President, Transmission and Substation Operations (formerly Vice President, Electric Operations, Projects and Construction) •Annabelle Louie, Vice President, Enterprise Work Management (formerly Vice President, Operations Support) The following individuals are no longer officers of the Utility: •Aaron A. August, Vice President, Utility Partnerships and Innovation •Jan A. Nimick, Vice President, Power Generation •Michael W. Seitz, Vice President, Vegetation Management Major Security Holders Changes to the major holders of the Utility’s First Preferred Stock are as follows: •Cede & Co., C/O DTCC-Transfer Operation Dept., 570 Washington Blvd Floor 1, Jersey City, NJ 08857, increased its share ownership from 9,823,860 shares as of March 31, 2023 to 9,840,629 shares as of June 30, 2023.(Approximately 95 percent of the total preferred shares outstanding). •George Wing Jr & Siu Ngon Wing JT Ten whom once held 11,500 preferred shares at Box 1283, Piscataway, NJ 08855 are no longer top ten preferred shareholders. •Alice Maude Stelling TR AU Apr 25 12 The Alice Maude Stelling Revocable Trust at 275 Los Ranchitos Rd, Apt 109, San Rafael, CA 94903 became a top ten preferred shareholder with 3,200 preferred shares. Dividend Payments Refer to Note 6, Equity, of the Notes to Financial Statements on pages 122-123 of the FERC Form 3-Q.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio: Not applicable.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	114,969,950,815	110,969,024,721
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	4,296,206,785	4,278,662,042
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		119,266,157,600	115,247,686,763
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	46,970,782,669	45,440,205,751
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		72,295,374,931	69,807,481,012
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	107,273,494	86,475,206
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		304,052,434	301,949,278
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)		2,964,394,529	2,964,394,529
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	3,135,930,621	3,080,422,971
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		239,789,836	272,396,042
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		72,535,164,767	70,079,877,054
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)		119,592,211	119,592,211
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		31,380,687	29,571,217
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)		5,211,950,000	3,245,150,000
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	1,022,786,321	1,021,724,910
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	850,465,540	646,415,350
24	OtherInvestments Other Investments (124)
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		3,999,982,869	4,081,176,046
29	SpecialFunds Special Funds (Non Major Only) (129)		1,009,138,102	997,257,827
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		238,834,357	305,301,298
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		12,364,537,876	10,326,596,648
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		78,791,789	72,198,551
36	SpecialDeposits Special Deposits (132-134)		1,352,844	11,780,009
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)		463,369,547	533,122,157
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		469,406,158	287,627,561
41	OtherAccountsReceivable Other Accounts Receivable (143)		1,661,813,843	2,192,892,372
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		28,732,139	18,324,417
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)		533,733,882	1,526,615,253
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		36,310,389	43,966,385
45	FuelStock Fuel Stock (151)	227	1,386,264	1,586,736
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	833,162,373	751,427,249
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	961,347,566	747,270,576
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	850,465,540	646,415,350
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		53,599,155	89,676,327
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		355,736,260	570,965,644
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		112,498,430	148,663,404
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		534,627,222	549,054,533
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		374,638,074	959,205,737
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		238,834,357	305,301,298
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		5,353,741,760	7,516,011,429
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		228,042,101	193,762,955
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b	21,267,894	27,373,357
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	25,292,265,454	23,721,433,967
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		558	558
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		2,782,617	2,475,764
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	4,674,133,686	4,862,754,112
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		30,865,507	36,721,574
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	11,069,761,077	10,203,179,212
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		41,319,117,778	39,047,700,383
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		131,692,154,392	127,089,777,725

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	1,321,874,045	1,321,874,045
3	PreferredStockIssued Preferred Stock Issued (204)	250	257,994,575	257,994,575
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)		1,805,194,230	1,805,194,230
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	33,282,923,589	30,756,123,589
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254	6,916,899	6,916,899
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	28,951,886	28,951,886
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	3,982,119,486	4,206,590,722
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	838,890,207	838,890,207
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	2,156,511	8,166,262
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		33,486,731,864	30,729,450,877
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	39,422,825,656	35,115,164,559
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256	9,012,361,416	9,093,909,854
21	OtherLongTermDebt Other Long-Term Debt (224)	256
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		4,612,173	4,903,468
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		53,556,777	30,251,169
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		48,386,242,468	44,183,726,712
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		1,472,757,089	1,243,633,044
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		1,624,819,915	2,251,659,254
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		187,189,895	184,604,903
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		2,098,534,554	1,753,706,614
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		163,605,576	176,597,091
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		5,970,610,389	5,912,361,630
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		11,517,517,418	11,522,562,536
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		125,000,000	2,055,000,000
38	AccountsPayable Accounts Payable (232)		3,053,242,424	3,582,839,305
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		107,921,531	226,750,134
41	CustomerDeposits Customer Deposits (235)		124,577,302	116,804,373
42	TaxesAccrued Taxes Accrued (236)	262	496,174,329	504,591,321
43	InterestAccrued Interest Accrued (237)		546,209,282	463,796,034
44	DividendsDeclared Dividends Declared (238)		2,319,380	2,319,382
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		27,258,040	41,016,803
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		1,300,921,106	1,463,562,560
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		136,203,919	232,928,694
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		215,731,805	228,244,869
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		163,605,576	176,597,091
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		5,971,953,542	8,741,256,384
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		310,680,409	288,675,735
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	90,231,296	91,349,274
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	1,711,996,093	1,705,188,018
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	16,207,927,291	16,420,075,785
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)		80,676	150,526
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		10,920,831,923	10,627,816,495
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		3,087,961,412	2,779,525,383
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		32,329,709,100	31,912,781,216
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		131,692,154,392	127,089,777,725

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	(a) 13,671,572,791	12,374,420,391	(c) 5,689,635,306	5,932,919,897	10,013,223,107	9,186,933,246	3,658,349,684	3,187,487,145
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	(b) 7,951,677,974	7,048,216,673	(d) 3,135,065,887	3,642,267,638	5,587,883,189	5,146,912,229	2,363,794,785	1,901,304,444
5	MaintenanceExpense Maintenance Expenses (402)	320	1,949,555,294	1,831,628,982	759,942,608	833,126,273	1,739,024,103	1,574,050,937	210,531,191	257,578,045
6	DepreciationExpense Depreciation Expense (403)	336	1,935,829,638	1,781,788,922	926,041,096	874,597,192	1,515,016,476	1,387,196,212	420,813,162	394,592,710
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	138,362,537	125,517,856	71,549,137	63,699,608	101,150,580	91,740,796	37,211,957	33,777,060
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)		6,698,555	6,698,555	3,349,278	3,349,278	6,698,555	6,698,555
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		6,030,000	6,030,000	3,015,000	3,015,000	6,030,000	6,030,000
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		124,535,818	299,845,576	46,271,649	349,113,429	71,882,523	228,566,667	52,653,295	71,278,909
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	471,834,343	410,609,493	217,835,456	202,369,646	334,054,587	290,212,813	137,779,756	120,396,680
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	4	5	4	5	29,369,548	8,208,227	29,369,544	8,208,232
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	1	1	1	3	13,562,066	3,790,341	13,562,067	3,790,342
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	6,157,154,724	13,035,814,018	4,016,189,472	11,371,303,280	5,103,185,671	12,328,401,243	1,053,969,053	707,412,775
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	6,698,199,057	13,467,639,522	4,288,248,282	11,665,541,921	5,616,389,071	12,712,518,318	1,081,809,986	755,121,204
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		39,898,641	40,999,194	19,756,267	21,489,123	26,321,216	27,500,934	13,577,425	13,498,260
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)		16,573	3,445	17,497	3,445	16,573	3,445
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		11,754,492,973	10,437,823,658	4,778,694,236	4,957,586,895	8,635,502,164	7,850,661,743	3,118,990,809	2,587,161,915
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		1,917,079,818	1,936,596,733	910,941,070	975,333,002	1,377,720,943	1,336,271,503	539,358,875	600,325,230
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		20,278,802	16,222,084	9,085,282	7,441,590
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)
35	NonoperatingRentalIncome Nonoperating Rental Income (418)
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	1,728,568	201,393,055	26,666,544	97,331,143
37	InterestAndDividendIncome Interest and Dividend Income (419)		272,847,826	39,631,361	147,275,103	26,058,147
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		81,933,873	82,263,912	40,621,754	40,600,550
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		1,181,779	3,417,630	1,864,957	9,100,787
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		233,063	1,002,852		886,462
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		378,203,911	343,930,894	172,180,552	163,217,105
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		79,652,099	230,667,626	5,905,639	109,809,833
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		4,193,525	5,327,568	3,469,789	5,327,068
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		229,425	1,690,399	222,224	1,542,632
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		4,144,520	3,945,059	2,170,897	2,151,129
49	OtherDeductions Other Deductions (426.5)		157,810,014	228,181,558	98,304,781	48,050,222
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		246,029,583	469,812,210	110,073,330	166,880,884
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	1	1	1
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	123,576,577	80,798,577	113,972,640	73,174,791
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	219,450,119	111,684,142	159,155,131	53,319,546
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)		1,117,978	2,596,412	527,994	1,298,206
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		96,991,521	33,481,978	45,710,486	18,557,039
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		229,165,849	92,399,338	107,817,708	22,220,818
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		679,721,579	649,133,651	339,309,899	328,659,024
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		25,675,198	29,906,934	12,915,170	14,607,937
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		5,856,067	7,342,575	2,906,133	4,062,709
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)		663,070	663,070	331,535	331,535
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)		69,850	69,850	34,925	34,925
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		215,282,696	38,174,578	107,124,787	32,581,801
68	OtherInterestExpense Other Interest Expense (431)		153,019,818	24,288,067	95,952,023	8,832,323
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		39,006,176	33,549,358	19,825,837	16,983,845
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		1,039,816,262	714,563,527	538,015,715	353,728,843
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		1,106,429,405	1,129,633,868	480,743,063	599,383,341
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		1,106,429,405	1,129,633,868	480,743,063	599,383,341

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OperatingRevenues

Includes interdepartmental operating revenues in Line 2 and operations expenses in Line 4 for the six months ended June 30:


	2023		2022
	Revenues	Expenses	Revenues	Expenses
Electric	27,248,062	44,785,969	23,840,407	42,082,504
Gas	131,489,506	113,951,599	127,567,313	109,325,216
Total	158,737,568	158,737,568	151,407,720	151,407,720

(b) Concept: OperationExpense

See footnote in row 2, column c

Includes interdepartmental operating revenues in Line 2 and operations expenses in Line 4 for the three months ended June 30:


	2023		2022
	Revenues	Expenses	Revenues	Expenses
Electric	14,334,145	21,734,561	13,400,290	21,386,135
Gas	48,879,409	41,478,993	48,446,141	40,460,296
Total	63,213,554	63,213,554	61,846,431	61,846,431

(d) Concept: OperationExpense

See footnote in row 2, column e

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		4,489,190,469	4,874,509,338
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		1,106,429,405	1,129,633,868
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Reserves for excess earnings on FERC hydroelectric
17.2	AppropriationsOfRetainedEarnings project licenses pursuant to Federal Power Act Section 10 (d)	215	1,001,103
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)		1,001,103
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
23.1	DividendsDeclaredPreferredStock Preferred Dividends Declared	238	(a) 6,958,169	(c) 64,942,816
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)		6,958,169	64,942,816
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock	234	(b) 875,000,000	(d) 425,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		875,000,000	425,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		4,263,718,130	4,234,818,286
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
39.1	AppropriatedRetainedEarnings Reserves for excess earnings on FERC hydroelectric
39.2	AppropriatedRetainedEarnings project licenses pursuant to Federal Power Act Section 10 (d)		1,001,103
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)		1,001,103
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)		282,599,747	282,599,748
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		281,598,644	282,599,748
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		3,982,119,486	3,952,218,538
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Other: Stanpac and PEFCO earnings reflected in M&O accounts
52.2	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Other: Dissolution
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: DividendsDeclaredPreferredStock

The following is the detail of dividends declared on Preferred Stock for the six months ended June 30, 2023:


	Class of Stock		Number of shares on which declared	Annual dividends per share	Total Declared
	(a)		(b)	(c)	(d)
First Preferred:
6.00%	Cumulative, Non-Redeemable		4,211,662	1.500	3,158,748
5.50%	Cumulative, Non-Redeemable		1,173,163	1.375	806,552
5.00%	Cumulative, Non-Redeemable		400,000	1.250	250,001
5.00%	Cumulative, Redeemable		1,778,172	1.250	1,111,359
5.00%	Cumulative, Redeemable	- Series A	934,322	1.250	583,953
4.80%	Cumulative, Redeemable		793,031	1.200	475,819
4.50%	Cumulative, Redeemable		611,142	1.125	343,768
4.36%	Cumulative, Redeemable		418,291	1.090	227,969
Total First Preferred					6,958,169

(b) Concept: DividendsDeclaredCommonStock

This represents dividends declared on Common Stock to PG&E Corporation for the six months ended June 30, 2023.

The following is the detail of dividends declared on Preferred Stock for six months ended June 30, 2022:


	Class of Stock		Number of shares on which declared	Annual dividends per share	Total Declared
	(a)		(b)	(c)	(d)
First Preferred:
6.00%	Cumulative, Non-Redeemable		4,211,662	1.500	29,481,627
5.50%	Cumulative, Non-Redeemable		1,173,163	1.375	7,527,797
5.00%	Cumulative, Non-Redeemable		400,000	1.250	2,333,333
5.00%	Cumulative, Redeemable		1,778,172	1.250	10,372,670
5.00%	Cumulative, Redeemable	- Series A	934,322	1.250	5,450,213
4.80%	Cumulative, Redeemable		793,031	1.200	4,440,973
4.50%	Cumulative, Redeemable		611,142	1.125	3,208,496
4.36%	Cumulative, Redeemable		418,291	1.090	2,127,707
Total First Preferred					64,942,816

(d) Concept: DividendsDeclaredCommonStock

This represents dividends declared on Common Stock to PG&E Corporation for the six months ended June 30, 2022.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	1,106,429,405	1,129,633,868
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	2,080,890,730	1,914,005,333
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Disallowed Capital Expenditures	7,339,236
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Unamortized Loss or Gain on Reacquired Debt	5,786,217	6,437,714
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Expenses, Discount and Premium - Long Term Debt	22,842,620	28,458,324
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	278,458,120	89,550,066
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,117,978	2,596,412
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	1,690,023,046	780,362,539
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	45,457,480	92,502,834
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	248,496,991	4,075,045,022
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	2,338,179,895	6,119,660,420
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	408,809,006	4,618,242,661
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	81,933,873	82,263,912
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	1,061,411	200,912,727
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 166,081,258	(d) 651,362,197
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	2,658,327,236	5,313,336,892
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	4,738,649,815	4,601,867,727
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	22,901,444	19,842,397
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	81,933,873	82,263,912
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	4,679,617,386	4,539,446,212
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	25,526,780	16,577,940
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies		18,000,000
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased		145,000,000
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Payments to Assoc. and Subsidiary Companies	385,629,973	33,315,643
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Purchases of customer credit trust investments		485,000,000
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Proceeds from other special trust investment sales	1,054,845,195	1,369,127,941
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Purchases of other special trust investments	802,068,468	1,340,964,477
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	4,786,943,853	4,886,020,451
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	4,689,858,500	4,264,451,997
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other (provide details in footnote):
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)	1,930,000,000	50,000,000
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):	0
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Equity contribution from PG&E Corporation	560,000,000	212,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	3,319,858,500	4,426,451,997
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	375,000,000	4,440,735,897
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Customer Advances for Construction	73,872,438	64,876,210
76.3	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other	(b) 81,742,689	(e) 21,733,186
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock	6,958,169	62,623,441
81	DividendsOnCommonStock Dividends on Common Stock	875,000,000	425,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	2,055,030,080	458,764,317
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	73,586,537	31,447,876
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	617,100,717	172,037,003
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(c) 543,514,180	(f) 140,589,127

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

This consists of the following:


	2023		2022

(Increase) Decrease in Other Working Capital	$	(316,865,337)	$	(459,196,980)
Increase (Decrease) - Other Noncurrent Liabilities	(301,416,119)		(460,039,146)
Others
Nuclear Fuel Lease Amortization	55,507,650		52,265,978
Payment on capital lease obligation	(1,054,706)		(992,101)
Collateral Adjustment	(1,002,874)		(4,025,918)
Kincade settlement expense	—		85,000,000
SB 901 amortization	48,535,622		—
Bad Debt Expense	293,386,949		76,461,436
Tax benefit on stock option exercises (shortfall)	19,422,995		748,263
Other-net	37,404,562		58,416,271

Total	$	(166,081,258)	$	(651,362,197)

(b) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

This consists of the following:


	2023		2022

Increase (Decrease) in customer deposits	$	8,338,666	$	(2,215,212)
Employee taxes paid for withheld shares	(83,805,730)		(18,791,962)


Other debt issuance and exchange fees	(6,275,625)		(726,012)

Total	$	(81,742,689)	$	(21,733,186)

This consists of the following:


	2023		2022

Cash (131)	$	78,791,789	$	38,641,479
Special Deposits (132-134)	1,352,844		21,447,648

Temporary Cash Investment (136)	463,369,547		80,500,000

Total	$	543,514,180	$	140,589,127

Supplemental disclosure of cash flow information (in millions):


Cash paid for:
Interest (net of amounts capitalized)	$	(911)	$	(602)

Supplemental disclosures of noncash investing and financing activities:


Capital expenditures financed through
accounts payable	860	1,380
Operating lease liabilities arising from
obtaining ROU assets	208	274
Forgiveness of DWR loan for
performance-based disbursements earned	67	—
Transfer of accounts receivable to a subsidiary company	—	(755)

(d) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

See footnote in column (b), Line 18.

(e) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

See footnote in column (b), Line 79.

(f) Concept: CashAndCashEquivalents

See footnote in column (b), Line 90.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Commission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

Introduction:

The notes below are excerpts from PG&E Corporation and the Utility’s combined Report on Form 10-Q for the quarter ended June 30, 2023, as filed with the Securities and Exchange Commission (“SEC”) July 26, 2023. The following disclosures contain information in accordance with SEC reporting requirements. As such, due to the differences between FERC and SEC reporting requirements, certain amounts disclosed in the following notes may not agree to balances in the FERC financial statements.

The accompanying financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (“FERC”) as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (“GAAP”). The primary differences from the Utility’s GAAP basis financial statements as presented in the Form 1 are that (1) subsidiaries are not consolidated and are shown under the equity method of accounting, (2) deferred income tax assets and liabilities are not offset against each other but are shown as separate items on the balance sheet, are long-term, and exclude the impact of uncertain temporary tax positions, (3) cost of removal is reported in accumulated depreciation for FERC reporting purposes (GAAP requires that cost of removal be classified as a regulatory liability), (4) there is no current liability classification of the current portion of long-term debt for FERC reporting, (5) there is no reclassification of balancing accounts from current assets to current liabilities for FERC reporting, (6) interdepartmental revenues and expenses between electric and gas operations of the Utility are not eliminated for FERC reporting, (7) penalties and disallowances are reported in other income deductions for FERC reporting, and (8) payments on capital lease obligations are disclosed in operating activities in the statement of cash flows, (9) debt issuance costs are not deducted from the carrying amount of that debt liability for FERC reporting, (10) there is no current liability classification of the current portion of accumulated provision for injuries and damages, in which the estimated losses associated with third-party wildfire claims are recorded, for FERC reporting, (11) FERC reporting does not reclass non-service costs related to pension benefits on the income statement pursuant to ASU 2017-07, and (12) there are no separate reporting categories included on the FERC balance sheet for lease assets and liabilities pursuant to ASU 2016-02.

Subsequent Events:

On August 10, 2023, Julius Cox, Executive Vice President, People, Shared Services and Supply Chain of PG&E Corporation and Pacific Gas and Electric Company (the “Utility”) informed PG&E Corporation and the Utility that he is resigning from his positions effective September 25, 2023 to pursue another opportunity.

Other than the item above, management has evaluated the impact of events occurring after June 30, 2023 up to July 26, 2023, the date that Pacific Gas and Electric Company’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through August 17, 2023. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information as of December 31, 2022 in the Condensed Consolidated Balance Sheets included in this quarterly report on Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2022 Form 10-K. This quarterly report on Form 10-Q should be read in conjunction with the 2022 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: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

The following table presents the Utility’s revenues disaggregated by type of customer:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Electric
Revenue from contracts with customers
Residential	$	1,404	$	1,213	$	2,693	$	2,707
Commercial	1,283		1,252		2,427		2,425
Industrial	375		322		728		672
Agricultural	314		484		469		700
Public street and highway lighting	20		19		39		37
Other, net (1)	(121)		(77)		(78)		(90)
Total revenue from contracts with customers - electric	3,275		3,213		6,278		6,451
Regulatory balancing accounts (2)	577		477		1,693		1,397
Total electric operating revenue	$	3,852	$	3,690	$	7,971	$	7,848

Natural gas
Revenue from contracts with customers
Residential	$	691	$	388	$	2,574	$	1,851
Commercial	189		197		702		541
Transportation service only	398		356		842		755
Other, net (1)	(257)		(88)		(410)		(267)
Total revenue from contracts with customers - gas	1,021		853		3,708		2,880
Regulatory balancing accounts (2)	417		575		(180)		188
Total natural gas operating revenue	1,438		1,428		3,528		3,068
Total operating revenues	$	5,290	$	5,118	$	11,499	$	10,916

(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.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of June 30, 2023, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

During the three and six months ended June 30, 2023, expected credit losses of $154 million and $293 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. For the three and six months ended June 30, 2022, expected credit losses were $33 million and $76 million, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of June 30, 2023, the RUBA current balancing accounts receivable balance was $228 million, and CPPMA and FERC long-term regulatory asset balances were $4 million and $42 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of June 30, 2023, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the six months ended June 30, 2023. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of Diablo Canyon. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of June 30, 2023, the Condensed Consolidated Financial Statements reflected $245 million in Long-term debt, $15 million in Other current liabilities for income related to eligible costs not yet incurred, and a deduction of $52 million to Operating and maintenance expense for income related to government grants for performance-based disbursements.

U.S. DOE’s Civil Nuclear Credit Program

On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. During the three and six months ended June 30, 2023, the Condensed Consolidated Statements of Income reflected $34 million as a deduction to Operating and maintenance expense and $48 million recorded as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to support the extension of Diablo Canyon including the purchase of nuclear fuel.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Condensed Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the six months ended June 30, 2023 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2023 and December 31, 2022, the SPV had net accounts receivable of $2.4 billion and $3.6 billion, respectively, and outstanding borrowings of $985 million and $1.2 billion, respectively, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the first and second AB 1054 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate Recovery Property.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the six months ended June 30, 2023 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2023 and December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.4 billion and $7.5 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of June 30, 2023, 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 or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of June 30, 2023, it did not consolidate any of them.

The Lakeside Building

BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building which serves as the Utility’s principal administrative headquarters.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property. The Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC as it does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to issued letters of credit as well as the amounts it pays for base rent and certain costs, per the office lease agreement. For more information, see “Oakland Headquarters Lease and Purchase” in Note 11 below.

Contributions to the Wildfire Fund Established Pursuant to AB 1054

PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

PG&E Corporation and the Utility evaluate and, where appropriate, update all assumptions quarterly. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire.

As of June 30, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $939 million in Other non-current liabilities, $460 million in Current assets - Wildfire Fund asset, and $4.6 billion in Non-current assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2023 and 2022, the Utility recorded amortization and accretion expense of $117 million and $117 million, respectively. During the six months ended June 30, 2023 and 2022, the Utility recorded amortization and accretion expense of $234 million and $235 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. As of June 30, 2023, PG&E Corporation and the Utility had recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 10 below.

Pension and Other Post-Retirement Benefits

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2023 and 2022 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2023		2022		2023		2022
Service cost for benefits earned (1)	$	95	$	144	$	9	$	16
Interest cost	229		173		19		14
Expected return on plan assets	(246)		(298)		(33)		(33)
Amortization of prior service cost	(1)		(1)		—		1
Amortization of net actuarial (gain) loss	—		1		(4)		(10)
Net periodic benefit cost	77		19		(9)		(12)
Regulatory account transfer (2)	(6)		64		—		—
Total	$	71	$	83	$	(9)	$	(12)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.


	Pension Benefits				Other Benefits
	Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Service cost for benefits earned (1)	$	190	$	288	$	19	$	31
Interest cost	457		346		37		27
Expected return on plan assets	(491)		(595)		(66)		(65)
Amortization of prior service cost	(2)		(2)		1		3
Amortization of net actuarial (gain) loss	—		1		(9)		(20)
Net periodic benefit cost	154		38		(18)		(24)
Regulatory account transfer (2)	(13)		127		—		—
Total	$	141	$	165	$	(18)	$	(24)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

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


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Three Months Ended June 30, 2023
Beginning balance	$	(12)	$	18	$	(1)	$	5
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $0 and $0, respectively)	—		—		—		—
Amortization of net actuarial gain (net of taxes of $0, $1 and $0, respectively)	—		(3)		—		(3)
Regulatory account transfer (net of taxes of $1, $1 and $0, respectively)	—		3		—		3
Net current period other comprehensive gain	—		—		—		—
Ending balance	$	(12)	$	18	$	(1)	$	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		Customer Credit Trust		Total
(in millions, net of income tax)	Three Months Ended June 30, 2022
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $2, respectively)	—		—		(5)		(5)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0 and $0, respectively)	(1)		1		—		—
Amortization of net actuarial (gain) loss (net of taxes of $0, $3 and $0, respectively)	1		(7)		—		(6)
Regulatory account transfer (net of taxes of $0, $3 and $0, respectively)	—		6		—		6
Net current period other comprehensive loss	—		—		(5)		(5)
Ending balance	$	(33)	$	18	$	(5)	$	(20)


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Six Months Ended June 30, 2023
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0 and $2, respectively)	—		—		5		5
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $0 and $0, respectively)	(1)		1		—		—
Amortization of net actuarial gain (net of taxes of $0, $2 and $0, respectively)	—		(7)		—		(7)
Regulatory account transfer (net of taxes of $1, $2 and $0, respectively)	1		6		—		7
Net current period other comprehensive gain	—		—		5		5
Ending balance	$	(12)	$	18	$	(1)	$	5


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Six Months Ended June 30, 2022
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $2, respectively)	—		—		(5)		(5)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $1 and$0, respectively)	(2)		2		—		—
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $0, $5 and $0, respectively)	1		12		—		13
Net current period other comprehensive loss	—		—		(5)		(5)
Ending balance	$	(33)	$	18	$	(5)	$	(20)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

As of June 30, 2023 and December 31, 2022, the Utility had current regulatory assets of $309 million and $296 million, respectively. As of June 30, 2023, current regulatory assets included approximately $100 million of deferred depreciation, interest, and tax expense related to 2022 rate base that were determined to be probable of recovery through the 2023 GRC.

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:


	Balance at
(in millions)	June 30, 2023		December 31, 2022
Pension benefits (1)	$	109	$	120
Environmental compliance costs	1,204		1,193
Utility retained generation (2)	63		86
Price risk management	164		177
Catastrophic event memorandum account (3)	1,272		1,085
Wildfire expense memorandum account (4)	468		439
Fire hazard prevention memorandum account (5)	86		79
Fire risk mitigation memorandum account (6)	23		65
Wildfire mitigation plan memorandum account (7)	654		756
Deferred income taxes (8)	3,100		2,730
Insurance premium costs (9)	11		99
Wildfire mitigation balancing account (10)	252		327
Vegetation management balancing account (11)	1,652		2,276
COVID-19 pandemic protection memorandum accounts (12)	18		26
Microgrid memorandum account (13)	141		213
Financing costs (14)	203		211
SB 901 securitization (15)	5,296		5,378
AROs in excess of recoveries (16)	—		120
Other	1,247		1,063
Total long-term regulatory assets	$	15,963	$	16,443

(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. The increase in the CEMA regulatory asset from December 31, 2022 to June 30, 2023 is primarily due to costs incurred for repair and restoration work performed related to an increase in declared winter storm events in the Utility’s service area. As of June 30, 2023 and December 31, 2022, $45 million and $44 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.

(6) Includes incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, the 2022 WMP for the period of January 1, 2022 through December 31, 2022, and the 2023 WMP for the period of January 1, 2023 through June 30, 2023. Also includes the noncurrent portion of costs associated with the 2019 WMP that were approved for recovery per the 2020 WMCE final decision. 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 of January 1, 2020 through June 30, 2023. The noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) Includes costs associated with certain vegetation management activities for the period of January 1, 2020 through June 30, 2023. The noncurrent balance represents costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.

(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of June 30, 2023, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $14 millionis associated with program costs and higher accounts receivable financing costs. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.

(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings.

(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds are being paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below.

(16) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 9 below.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:


	Balance at
(in millions)	June 30, 2023		December 31, 2022
Cost of removal obligations (1)	$	8,023	$	7,773
Public purpose programs (2)	1,225		1,062
Employee benefit plans (3)	918		904
Transmission tower wireless licenses (4)	421		430
SFGO sale (5)	224		264
SB 901 securitization (6)	6,127		5,800
Wildfire self-insurance (7)	200		—
Other	1,380		1,397
Total long-term regulatory liabilities	$	18,518	$	17,630

(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 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.

(3) Represents cumulative differences between incurred costs and amounts collected in rates for post-retirement medical, post-retirement life and long-term disability plans.

(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. Of the $421 million, $294 million will be refunded to FERC-jurisdictional customers, and $127 million will be refunded to CPUC-jurisdictional customers.

(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.

(6) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement when the Fire Victim Trust sells additional shares. See Note 5 below.

(7) Represents amounts received from customers designated for wildfire self-insurance. See Note 10 below.

Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:


	Balance at
(in millions)	June 30, 2023		December 31, 2022
Electric distribution (1)	$	1,289	$	448
Electric transmission (2)	117		96
Gas distribution and transmission (3)	62		72
Energy procurement (4)	1,032		684
Public purpose programs (5)	300		358
Fire hazard prevention memorandum account (6)	129		—
Wildfire mitigation plan memorandum account (7)	78		—
Wildfire mitigation balancing account (8)	96		2
Vegetation management balancing account (9)	872		137
Insurance premium costs (10)	268		602
Residential uncollectibles balancing accounts (11)	228		126
Catastrophic event memorandum account (12)	332		144
Other	580		595
Total regulatory balancing accounts receivable	$	5,383	$	3,264


	Balance at
(in millions)	June 30, 2023		December 31, 2022
Electric transmission (2)	$	222	$	228
Gas distribution and transmission (3)	449		66
Energy procurement (4)	8		428
Public purpose programs (5)	257		272
SFGO sale	75		152
Other	306		512
Total regulatory balancing accounts payable	$	1,317	$	1,658

(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.

(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings.

(4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities.

(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(6) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards approved for cost recovery in the 2020 WMCE final decision.

(7) The WMPMA tracks costs associated with the 2019 WMP which were approved for cost recovery in the 2020 WMCE final decision.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery.

(9) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery.

(10) The insurance premium costs track the current portion of incremental excess liability insurance 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. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, as of June 30, 2023, and December 31, 2022 there were $7 million and $48 million, respectively, in insurance premium costs recorded in Current regulatory assets.

(11) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers.

(12) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities approved for cost recovery in the 2018 CEMA and 2020 WMCE final decisions.

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

NOTE 4: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2023:


(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2028	$	4,400	(1)	$	—	$	(697)	$	3,703
Utility Receivables Securitization Program (2)	June 2025	985		(3)	(985)		—		—		(3)
PG&E Corporation revolving credit facility	June 2026	500			—		—		500
Total credit facilities		$	5,885		$	(985)	$	(697)	$	4,203

(1) Includes a $2.0 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(3) 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 limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

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

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

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

PG&E Corporation

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

Long-Term Debt Issuances and Redemptions

Utility

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

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

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

NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. In the context of the customer harm threshold decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 9 below). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating Revenues for the six months ended June 30, 2023.

Upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, and $1.0 billion is required to be contributed in 2024. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the three months ended June 30, 2023, the Utility recorded SB 901 securitization charges, net, of $289 million for tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (see Note 6 below) and $71 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2023, the Utility recorded SB 901 securitization charges, net, of $562 million for tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (see Note 6 below) and $158 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion in total, as the tax benefits described above are recognized and recorded within Deferred income taxes.

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities since December 31, 2022:


SB 901 securitization regulatory asset (in millions)
Balance at December 31, 2022	$	5,378
Amortization	(82)
Balance at June 30, 2023	$5,296


SB 901 securitization regulatory liability (in millions)
Balance at December 31, 2022	$	(5,800)
Amortization	240
Additions(1)	(567)
Balance at June 30, 2023	$	(6,127)

(1) Includes $5 million of expected returns on investments in the customer credit trust to be credited to customers.

NOTE 6: EQUITY

Settlement of Equity Units

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 137 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contract component of each equity unit and is subject to certain adjustments as provided therein. The common stock to be received by these unitholders was originally valued at approximately $1.3 billion and recognized in shareholders’ equity by PG&E Corporation upon the issuance of the equity units. The stated settlement date of each of the equity units’ purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in such purchase contracts. During the three months ended June 30, 2023, certain unitholders accelerated the settlement date for 8 million PG&E Corporation equity units, resulting in the issuance of 67 million shares of PG&E Corporation common stock, valued at approximately $634 million. Subsequently, through July 19, 2023, certain unitholders accelerated the settlement date for an additional 3 million PG&E Corporation equity units, resulting in the issuance of 28 million shares of PG&E Corporation common stock, valued at approximately $270 million. Based on trading prices as of July 19, 2023, the remaining outstanding equity units are expected to convert into 42 million shares during the third quarter of 2023, subject to change based on trading prices for the final measurement period.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,568,984,928 shares outstanding as of July 19, 2023, only 2,023,497,748 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of July 19, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of July 19, 2023 was 3.74% of the outstanding shares. At various dates throughout 2022 and during the six months ended June 30, 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the six months ended June 30, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 120,000,000 shares resulted in an aggregate tax benefit of $527 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Cumulatively through June 30, 2023, the Fire Victim Trust has sold 350,000,000 shares resulting in an aggregate tax benefit of approximately $1.4 billion recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Subsequently, on July 12, 2023, the Fire Victim Trust exchanged an additional 60,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. As of July 19, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 410,000,000 shares of PG&E Corporation common stock in the aggregate and owned 67,743,590 shares.

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Dividends

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

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

On December 20, 2017, the Boards of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation common stock, beginning the fourth quarter of 2017. Subject to the foregoing restrictions, 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. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions, except per share amounts)	2023		2022		2023		2022
Income available for common shareholders	$	406	$	356	$	975	$	831
Weighted average common shares outstanding, basic	2,019		1,987		2,005		1,987
Add incremental shares from assumed conversions:
Employee share-based compensation	6		8		6		8
Equity Units	114		146		126		146
Weighted average common shares outstanding, diluted	2,139		2,141		2,137		2,141
Total income per common share, diluted	$	0.19	$	0.17	$	0.46	$	0.39

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 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 rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:


		Contract Volume at
Underlying Product	Instruments	June 30, 2023	December 31, 2022
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	246,078,190	171,212,813
	Options	44,745,000	27,785,000
Electricity (MWh)	Forwards, Futures and Swaps	9,389,471	10,814,728
	Options	277,200	215,600
	Congestion Revenue Rights (3)	180,123,433	205,743,505

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of June 30, 2023, 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	$	147	$	(11)	$	31	$	167
Other noncurrent assets – other	239		—		—		239
Current liabilities – other	(80)		11		16		(53)
Noncurrent liabilities – other	(164)		—		1		(163)
Total commodity risk	$	142	$	—	$	48	$	190

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

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 derivative instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of June 30, 2023, 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
	At June 30, 2023
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	723	$	—	$	—	$	—	$	723

Nuclear decommissioning trusts
Short-term investments	126		—		—		—		126
Global equity securities	2,035		—		—		—		2,035
Fixed-income securities	1,195		793		—		—		1,988
Assets measured at NAV	—		—		—		—		29
Total nuclear decommissioning trusts (2)	3,356		793		—		—		4,178
Customer credit trust
Short-term investments	7		—		—		—		7
Global equity securities	148		—		—		—		148
Fixed-income securities	85		236		—		—		321
Total customer credit trust	240		236		—		—		476
Price risk management instruments (Note 8)
Electricity	—		28		330		11		369
Gas	—		28		—		9		37
Total price risk management instruments	—		56		330		20		406
Rabbi trusts
Short-term investments	97		—		—		—		97
Global equity securities	5		—		—		—		5

Life insurance contracts	—		65		—		—		65
Total rabbi trusts	102		65		—		—		167
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		117
Total long-term disability trust	7		—		—		—		124
TOTAL ASSETS	$	4,428	$	1,150	$	330	$	20	$	6,074
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	31	$	204	$	(26)	$	209
Gas	—		9		—		(2)		7
TOTAL LIABILITIES	$	—	$	40	$	204	$	(28)	$	216

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

(2) Represents amount before deducting $654 million primarily related to deferred taxes on appreciation of investment value.


	Fair Value Measurements
	December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	658	$	—	$	—	$	—	$658
Fixed-income securities	—		49		—		—		49
Nuclear decommissioning trusts
Short-term investments	117		—		—		—		117
Global equity securities	1,845		—		—		—		1,845
Fixed-income securities	1,094		791		—		—		1,885
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,056		791		—		—		3,872
Customer credit trust
Short-term investments	19		—		—		—		19
Global equity securities	218		—		—		—		218
Fixed-income securities	216		292		—		—		508
Total customer credit trust	453		292		—		—		745
Price risk management instruments (Note 8)
Electricity	—		94		432		40		566
Gas	—		604		—		327		931
Total price risk management instruments	—		698		432		367		1,497
Rabbi trusts
Short-term investments	25		—		—		—		25
Global equity securities	5		—		—		—		5
Fixed-income securities	—		69		—		—		69
Life insurance contracts	—		64		—		—		64
Total rabbi trusts	30		133		—		—		163
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	10		—		—		—		143
TOTAL ASSETS	$	4,207	$	1,963	$	432	$	367	$	7,127
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	10	$	233	$	(20)	$223
Gas	—		172		—		(166)		6
TOTAL LIABILITIES	$	—	$	182	$	233	$	(186)	$	229

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

(2) Represents amount before deducting $575 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 six months ended June 30, 2023 and 2022.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets, customer credit trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds classified as Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.

Fair Value at

(in millions)

At June 30, 2023

Valuation
Technique

Unobservable
Input

Fair Value Measurement

Assets

Liabilities

Range (1)/Weighted-Average Price (2)

Congestion revenue rights

272

121

Market approach

CRR auction prices

$ (145.09) - 843.59 / 0.92

Power purchase agreements

Discounted cash flow

Forward prices

$ (7.91) - 263.13 / 64.94

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Fair Value at

(in millions)

At December 31, 2022

Valuation
Technique

Unobservable
Input

Fair Value Measurement

Assets

Liabilities

Range (1)/Weighted-Average Price (2)

Congestion revenue rights

305

138

Market approach

CRR auction prices

$ (145.09) - 2,724.93 / 0.89

Power purchase agreements

127

Discounted cash flow

Forward prices

$ (6.39) - 286.75 / 78.14

(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 price risk management instruments for the three and six months ended June 30, 2023 and 2022, respectively:


	Price Risk Management Instruments
(in millions)	2023		2022
Asset (Liability) balance as of April 1	$	212	$	(24)
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(86)		35
Asset balance as of June 30	$	126	$	11

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.


	Price Risk Management Instruments
(in millions)	2023		2022
Asset (Liability) balance as of January 1	$	199	$	(34)
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(73)		45
Asset balance as of June 30	$	126	$	11

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of June 30, 2023 and December 31, 2022, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):


	At June 30, 2023				At December 31, 2022
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	4,430	$	4,489	$	4,355	$	4,490
Utility	35,625		30,473		32,847		27,666

Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of June 30, 2023
Nuclear decommissioning trusts
Short-term investments	$	126	$	—	$	—	$	126
Global equity securities	391		1,684		(11)		2,064
Fixed-income securities	2,083		14		(109)		1,988
Total (1)	$	2,600	$	1,698	$	(120)	$	4,178
As of December 31, 2022
Nuclear decommissioning trusts
Short-term investments	$	117	$	—	$	—	$	117
Global equity securities	413		1,468		(11)		1,870
Fixed-income securities	1,991		10		(116)		1,885
Total (1)	$	2,521	$	1,478	$	(127)	$	3,872

(1) Represents amounts before deducting $654 million and $575 million as of June 30, 2023 and December 31, 2022, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:


	As of
(in millions)	June 30, 2023
Less than 1 year	$	22
1–5 years	627
5–10 years	497
More than 10 years	842
Total maturities of fixed-income securities	$	1,988

The following table provides a summary of activity for the fixed-income and equity securities:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2023		2022		2023		2022
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	474	$	948	$	751	$	1,369
Gross realized gains on securities	37		81		42		137
Gross realized losses on securities	(10)		(58)		(18)		(65)

Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of June 30, 2023
Customer credit trust
Short-term investments	$	7	$	—	$	—	$	7
Global equity securities	129		23		(4)		148
Fixed-income securities	323		—		(2)		321
Total	$	459	$	23	$	(6)	$	476
As of December 31, 2022
Customer credit trust
Short-term investments	$	19	$	—	$	—	$	19
Global equity securities	219		13		(14)		218
Fixed-income securities	516		—		(8)		508
Total	$	754	$	13	$	(22)	$	745

The fair value of fixed-income securities by contractual maturity is as follows:


	As of
(in millions)	June 30, 2023
Less than 1 year	$	—
1–5 years	88
5–10 years	80
More than 10 years	153
Total maturities of fixed-income securities	$	321

The following table provides a summary of activity for the fixed-income and equity securities:


	Three Months Ended June 30,			Six Months Ended June 30,
(in millions)	2023		2022	2023		2022
Proceeds from sales and maturities of customer credit trust investments	$	135	$—	$	304	$—
Gross realized gains on securities	6		1	8		1
Gross realized losses on securities (1)	(5)		(8)	(10)		(8)

(1) Includes $4.3 million of impaired debt securities which were written down to their respective fair values during the three and six months ended June 30, 2023.

NOTE 10: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. 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.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

As of July 19, 2023, PG&E Corporation and the Utility are aware of approximately 124 complaints on behalf of at least 2,839 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022.

On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.025 billion as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of June 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022			$650
Accrued Losses			—
Payments			(192)
Balance at June 30, 2023			$458

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of June 30, 2023, the Utility recorded an insurance receivable for the full amount of $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office (“Shasta D.A.”) charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 24, 2023, the Utility filed a motion to set aside 10 of the remaining 11 counts. On April 14, 2023, the court issued a written tentative ruling dismissing nine of the remaining counts and inviting the parties to submit additional briefing on the issues discussed in the tentative ruling. On May 31, 2023, the Utility and the Shasta D.A. filed a civil stipulated judgment (the “Zogg Stipulation”) for the Shasta D.A. to dismiss with prejudice all criminal charges against the Utility in connection with the 2020 Zogg fire. On May 31, 2023, the Shasta County Superior Court granted the Shasta D.A.’s motion to dismiss the pending criminal charges. Subject to the terms and conditions of the Zogg Stipulation, the Utility agreed to (1) pay a total of $50 million, which will not be recoverable through rates; (2) take certain wildfire mitigation actions consistent with its then-applicable wildfire mitigation plan and (3) extend the term of the independent compliance monitor to monitor the Utility’s compliance with certain commitments in Shasta County by approximately one year. After the Zogg Stipulation was entered by the Shasta County Superior Court, the Shasta D.A. moved to dismiss the charges with prejudice, which was granted by the court on June 14, 2023. As of June 30, 2023, PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflected $50 million within Other current liabilities in connection with the Zogg Stipulation.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred. On May 24, 2023, the CPUC issued a resolution granting the joint motion filed by the Utility and the SED and approving the Zogg SED Settlement.

As of July 19, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for September 5, 2023.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $400 million as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of June 30, 2023.

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, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022			$32
Accrued Losses			—
Payments			(13)
Balance at June 30, 2023			$19

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of June 30, 2023, the Utility recorded an insurance receivable for $372 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $32 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

The SED and OEIS have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California also issued a subpoena for documents. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of Butte County, Plumas County, Shasta County, Lassen County and Tehama County, whose potential state criminal prosecution of the Utility is resolved, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million.

As of July 19, 2023, PG&E Corporation and the Utility are aware of approximately 143 complaints on behalf of at least 6,380 individual plaintiffs and a separate putative class complaint related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A trial on individual claims is scheduled to commence on November 8, 2023. Cal Fire also filed a complaint largely repeating the allegations of the earlier Cal Fire Investigation Report and seeking damages for fire suppression and investigation costs.

On March 2, 2023, PG&E Corporation and the Utility entered into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.175 billion as of December 31, 2022 (before available recoveries). The aggregate liability remained unchanged as of June 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, (v) medical monitoring costs, or (vi) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022			$1,131
Accrued Losses			—
Payments			(447)
Balance at June 30, 2023			$684

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of June 30, 2023, the Utility recorded an insurance receivable of $528 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 $372 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of June 30, 2023, the Utility recorded a Wildfire Fund receivable of $175 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $117 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 $411 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. The WEMA regulatory asset increased by $23 million during the six months ended June 30, 2023.

2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. 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 2022 Mosquito fire. This investigation is preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of July 19, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 236 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency, a complaint on behalf of the Middle Fork Project Finance Authority, a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency, and three complaints on behalf of the subrogation insurers. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

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 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 2022 Mosquito fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of June 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. The Utility’s accrued estimated losses also do not include any assumptions regarding offsetting recoveries from third-parties (outside of the Utility’s insurers).

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito 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. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $733 million, with a deductible of $60 million. As of June 30, 2023, the Utility recorded an insurance receivable of $54 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of June 30, 2023, the Utility also recorded a $9 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 $51 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of June 30, 2023 are:


Potential Recovery Source (in millions)	2022 Mosquito fire	2021 Dixie fire
Insurance	$54	$528
FERC TO rates (1)	9	117
WEMA (1)	51	411
Wildfire Fund	—	175
Probable recoveries at June 30, 2023	$114	$1,231

(1) Includes legal costs.

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. In the six months ended June 30, 2023, the Utility commuted $207 million of the $340 million in wildfire liability insurance coverage running from $757 million to $970 million. PG&E Corporation and the Utility did not procure additional wildfire liability insurance in April 2023 as they move to a program of self-insurance. See “Self-Insurance” below.

In April 2023, the Utility purchased approximately $700 million in non-wildfire liability coverage for the period from April 1, 2023 to April 1, 2024 at a cost of approximately $167 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of June 30, 2023, PG&E Corporation and the Utility had prepaid insurance of $204 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 excess liability insurance coverage. For more information about the RTBA, see Note 3 above.

Self-Insurance

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance once all of the Utility’s existing wildfire liability insurance policies expire, which will occur on August 1, 2023. The self-insurance will be funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected in rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. The settlement agreement includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

Insurance Receivable

Through June 30, 2023, PG&E Corporation and the Utility recorded $430 million, $372 million, $528 million, and $54 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:


Insurance Receivable (in millions)	2022 Mosquito fire	2021 Dixie fire	2020 Zogg fire	2019 Kincade fire	Total
Balance at December 31, 2022	$45	$530	$118	$101	$794
Accrued insurance recoveries (1)	8	(1)	1	—	8
Reimbursements	—	(200)	(54)	(101)	(355)
Balance at June 30, 2023	$53	$329	$65	$—	$447

(1) For the six months ended June 30, 2023, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $1 million.

As of June 30, 2023, PG&E Corporation and the Utility resolved property related claims in the amount of $418 million, net of self-insured retention, of which approximately $9 million is reflected in Accounts receivable, other on the Condensed Consolidated Financial Statements (excluded from the table above).

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of June 30, 2023, the Utility recorded reductions of $117 million and $9 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of June 30, 2023, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $411 million and $51 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of June 30, 2023 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.7 billion based on its forecasted 2023 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

As of June 30, 2023, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount but is unable to reasonably estimate the amount because of the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such settlement.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA filed its opening brief on March 6, 2023, the answering brief was filed on May 8, 2023, and PERA filed its reply on May 30, 2023. Oral argument is scheduled for September 13, 2023.

A group of shareholders who also filed proofs of claim in the Chapter 11 cases filed a motion to intervene in the District Court action to, among other things, oppose the lifting of the stay sought by PERA. That motion remains pending. In addition, on March 21, 2023, a sub-set of this group of shareholders filed a separate action in the United States District Court for the Northern District of California against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation. The parties stipulated to a stay and on May 16, 2023, the District Court entered an order staying the action.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and any applicable 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 engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. On March 27, 2023, PG&E Corporation and the Utility filed a joint statement with PERA informing the court that the parties had been unable to successfully negotiate the terms of a settlement agreement that would potentially resolve the matters underlying this appeal and requested that the court place the appeal back on calendar for oral argument. The Ninth Circuit Court of Appeals heard oral argument on May 5, 2023. On May 16, 2023, the Ninth Circuit Court of Appeals issued its decision affirming the District Court. The time for appeal has expired.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated under the heading “Wildfire-Related Derivative Litigation” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K. PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations.

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled with certain of their D&O Insurance carriers the majority of their claims regarding, among other things, the applicability of one year of the D&O Insurance policies to the Wildfire-Related Non-Bankruptcy Securities Claims and the derivative claims described in the 2022 Form 10-K. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims in the amount of $117 million, and PG&E Corporation intends to apply the remaining $155 million of proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally may have 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.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to January 12, 2024.

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 assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in TO rate cases. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

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

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

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

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

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.

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

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

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters totaled $78 million and $69 million as of June 30, 2023 and December 31, 2022, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022.

PG&E Corporation and the Utility are unable to determine the timing and outcome of this proceeding.

Confirmation Order Appeals

PG&E Corporation and the Utility emerged from bankruptcy on July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Trade Committee. The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. On May 22, 2023, the Supreme Court of the United States denied the Utility’s petition.

Based on the information available, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the post-petition interest matter, and that such loss will not be material. Because the Supreme Court of the United States denied the Utility’s petition, the matter is remanded to the Bankruptcy Court to evaluate the rate of interest for each individual contract, the conditions under which the contract rate applies, and whether payment of interest under state law would be warranted for each contract and claimant. PG&E Corporation and the Utility expect that these proceedings likely will require extensive discovery and motion practice before the Bankruptcy Court with respect to each of these claims on a variety of contractual issues and equitable considerations. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings or any further appeals.

Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to the deductibility of approximately $850 million in repair costs for gas transmission and distribution lines and $400 million in customer bill credits, which the Utility incurred in connection with the decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. The Internal Revenue Service is auditing tax years 2015 through 2018.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:


	Balance at
(in millions)	June 30, 2023		December 31, 2022
Topock natural gas compressor station	$	291	$	284
Hinkley natural gas compressor station	106		110
Former MGP sites owned by the Utility or third parties (1)	839		750
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	119		112
Fossil fuel-fired generation facilities and sites (3)	25		26
Total environmental remediation liability	$	1,380	$	1,282

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.

(2) Primarily driven by geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances. The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability as of June 30, 2023, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of June 30, 2023, the Utility expected to recover $1.14 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $231 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A background report was finalized in April 2023. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $126 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. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $561 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $78 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 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 to the site’s spent fuel storage installation. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $5 million. For more information about the Utility’s nuclear insurance coverage, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Purchase Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2022, the Utility had undiscounted future expected obligations of approximately $35 billion. See Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Oakland Headquarters Lease and Purchase

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease began on April 8, 2022. The Lease term will expire 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 is responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease required 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 and the process of subdividing the real estate was completed on February 6, 2023.

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of June 30, 2023, approximately 659,000 rentable square feet of the leased premises has been made available for use by the Utility. The Utility has recorded $735 million in Operating lease right of use assets, $262 million in leasehold improvements, which includes $178 million that was provided to the Utility as lease incentives, and $913 million in noncurrent Operating lease liabilities in the Condensed Consolidated Financial Statements related to the Lease.

On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Property, as modified. Pursuant to the Purchase and Sale and Joint Escrow Instructions, the purchase price will be $906 million, with deposits applicable to such purchase price of $150 million paid on July 11, 2023, $250 million to be paid on July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. The Utility will continue to lease the Lakeside building pursuant to the Lease until closing.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				7,526,997			7,526,997
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				4,672,668			4,672,668
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)				4,672,668			4,672,668	1,129,633,868	1,124,961,200
5	Balance of Account 219 at End of Preceding Quarter/Year				12,199,665			12,199,665
6	Balance of Account 219 at Beginning of Current Year				8,166,262			8,166,262
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				6,009,751			6,009,751
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)				6,009,751			6,009,751	1,106,429,405	1,112,439,156
10	Balance of Account 219 at End of Current Quarter/Year				2,156,511			2,156,511

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	90,570,037,296	65,462,286,300	18,866,307,966				6,241,443,030
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	(a) 1,603,263,985	566,287,761					1,036,976,224
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold	47,859	137,454	314,156				224,561
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	22,796,697,393	14,029,772,359	7,591,753,731				1,175,171,303
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	114,969,950,815	80,058,208,966	26,458,375,853				8,453,365,996
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use
11	ConstructionWorkInProgress Construction Work in Progress	4,296,206,785	3,062,242,463	415,196,572				818,767,750
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	119,266,157,600	83,120,451,429	26,873,572,425				9,272,133,746
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	46,970,782,669	34,231,122,917	9,601,459,703				3,138,200,049
15	UtilityPlantNet Net Utility Plant (13 less 14)	72,295,374,931	48,889,328,512	17,272,112,722				6,133,933,698
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	46,070,145,763	34,134,648,621	9,593,914,412				2,341,582,730
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights	8,623,917		8,623,917
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	892,012,989	96,474,296	1,078,626				796,617,319
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	46,970,782,669	34,231,122,917	9,601,459,703				3,138,200,049
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	46,970,782,669	34,231,122,917	9,601,459,703				3,138,200,049

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

Property Under Capital Lease includes both operating and financing lease net of accumulated amortization in accordance with ASC 842.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	396,806,598	96,474,296
2	Steam Production Plant	769,963,674	346,401,495
3	Nuclear Production Plant	10,158,280,844	8,114,400,077
4	Hydraulic Production - Conventional	4,059,861,351	1,701,106,717
5	Hydraulic Production - Pumped Storage	978,911,960	846,785,715
6	Other Production	1,479,255,407	551,344,824
7	Transmission	17,162,546,918	4,195,967,382
8	Distribution	42,910,400,854	17,586,935,608
9	Regional Transmission and Market Operation
10	General	1,575,893,599	791,706,803
11	TOTAL (Total of lines 1 through 10)	(a) 79,491,921,205	34,231,122,917

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: ElectricPlantInService

Difference to page 200 Utility Plant In Service is due to Operating Leases.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	CP-Martin 115/60 kV Upgrade Project		186		186
3	WL - Tesla Tracy 230kV Line 1 Reloc-FAS		186		186
4	WL -(SIS)Interconnection Merced Irr Dist		186	500	186
5	WL - CA HiSpeed Train Interconnect Study		186		186
6	WG - USE - Cluster Analysis	30,516	186		186
7	WG Gradient Resources Project SIS		186		186
8	WAPA O'Neill Substation - System Impact		186		186
9	WG - BURNS&MCDONNELL-Cluster work	238,640	186		186
10	Ntwrk Eval for Calpine 115kV Geysers Gen		186		186
11	WAPA - Cottonwood Olinda line work		186		186
12	LBNL Capacity Increase		186		186
13	SVP Breaker Replacement		186		186
14	Travis AFB Facility Study		186		186
15	Port of Stockton Load Increase		186	27,434	186
16	2016 Merced ID Load Interconnection Faci		186	19,504	186
17	WAPA SLTP		186		186
18	Port of Stockton FAS		186		186
19	CAISO ISP Panoche		186		186
20	SFPUC - Potrero Interconnection		186		186
21	WG - ISP - Porthos		186		186
22	WAPA Lemoore NAS		186		186
23	Swan Lake Affected Sys. Study		186		186
24	WG - C11 - SM - Project 100		186		186
25	WG - C11 - SM - Project 78		186		186
26	WG # Cluster 10 Phase 2		186		186
27	WG – Quanta Technology DG Study Rule 21	6,882	186		186
28	WG - C12 - SM - Project 01		186		186
29	WG - C12 - SM - Project 02		186		186
30	WG - C12 - SM - Project 03		186		186
31	WG - C12 - SM - Project 04		186		186
32	WG - C12 - SM - Project 05		186		186
33	WG - C12 - SM - Project 06		186		186
34	WG - C12 - SM - Project 07		186		186
35	WG - C12 - SM - Project 08		186		186
36	WG - C12 - SM - Project 09		186		186
37	WG - C12 - SM - Project 10		186		186
38	WG - C12 - SM - Project 11		186		186
39	WG - C12 - SM - Project 12		186		186
40	WG - C12 - SM - Project 13		186		186
41	WG - C12 - SM - Project 14		186		186
42	WG - C12 - SM - Project 15		186		186
43	WG - C12 - SM - Project 16		186		186
44	WG - C12 - SM - Project 17		186		186
45	WG - C12 - SM - Project 18		186		186
46	WG - C12 - SM - Project 19		186		186
47	WG - C12 - SM - Project 20		186		186
48	WG - C12 - SM - Project 21		186		186
49	WG - C12 - SM - Project 22		186		186
50	WG - C12 - SM - Project 23		186		186
51	WG - C12 - SM - Project 24		186		186
52	WG - C12 - SM - Project 25		186		186
53	WG - C12 - SM - Project 26		186		186
54	WG - C12 - SM - Project 27		186		186
55	WG - C12 - SM - Project 28		186		186
56	WG - C12 - SM - Project 29		186		186
57	WG - C12 - SM - Project 30		186		186
58	WG - C12 - SM - Project 31		186		186
59	WG - C12 - SM - Project 32		186		186
60	WG - C12 - SM - Project 33		186		186
61	WG - C12 - SM - Project 34		186		186
62	WG - C12 - SM - Project 35		186		186
63	WG - C12 - SM - Project 37		186		186
64	WG - C12 - SM - Project 38		186		186
65	WG - C12 - SM - Project 39		186		186
66	WG - C12 - SM - Project 40		186		186
67	WG - C12 - SM - Project 41		186		186
68	WG – Cluster 11 Phase 2		186		186
69	WG - C12 - SM - Project 42		186		186
70	WG - C12 - SM - Project 43		186		186
71	WG - C12 - SM - Project 44		186		186
72	WG - C12 - SM - Project 45		186		186
73	WG - C12 - SM - Project 46		186		186
74	WG - C12 - SM - Project 47		186		186
75	WG - C12 - SM - Project 48		186		186
76	WG - C12 - SM - Project 49		186		186
77	WG - C12 - SM - Project 51		186		186
78	WG - C12 - SM - Project 52		186		186
79	WG - C12 - SM - Project 53		186		186
80	WG - C12 - SM - Project 54		186		186
81	WG - C12 - SM - Project 55		186		186
82	WG - C12 - SM - Project 56		186		186
83	WG - C12 - SM - Project 57		186		186
84	WG - C12 - SM - Project 58		186		186
85	WG - C12 - SM - Project 59		186		186
86	WG - C12 - SM - Project 60		186		186
87	WG - C12 - SM - Project 61		186		186
88	WG - C12 - SM - Project 62		186		186
89	WG - C12 - SM - Project 63		186		186
90	WG - C12 - SM - Project 64		186		186
91	WG - C12 - SM - Project 65		186		186
92	WG - C12 - SM - Project 66		186		186
93	WG - C12 - SM - Project 67		186		186
94	WG - C12 - SM - Project 68		186		186
95	WG - C12 - SM - Project 69		186		186
96	WG - C12 - SM - Project 70		186		186
97	WG - C12 - SM - Project 71		186		186
98	WG - C12 - SM - Project 72		186		186
99	WG - C12 - SM - Project 74		186		186
100	Cluster 12 Phase 1		186		186
101	2020 Reassessment		186		186
102	WG –Repowering Oakland Unit 2		186		186
103	WG - C13 - SM - Project 24		186		186
104	WG - C13 - SM - Project 57		186		186
105	WG - C13 - SM - Project 77		186		186
106	Lemoore NAS Facilities Study (Yr 2020)		186		186
107	WG - C12 - Phase II		186		186
108	WDT/ System Impact Study		186		186
109	WG - C13 - Phase I		186		186
110	WG –Repowering Dollar Wind LLC		186		186
111	LLNL FAS for Site 300		186		186
112	WL-FAS-6527 Calaveras		186	30,000	186
113	WDL-FAS-Mission Rock Redevelopment		186		186
114	WG -Oakland ES ISP		186		186
115	WDL-FAS-2 Rankin		186		186
116	WDL-SIS-6527 Calaveras		186		186
117	WDL-SIS-2 Rankin		186		186
118	WDL-SIS-49 S. Van Ness		186	15,186	186
119	WDL-SIS-702 Phelps		186		186
120	WDL-SIS-750 Phelps		186		186
121	2021 Reassessment		186		186
122	WDL-FAS-750 Phelps		186		186
123	WDL-SIS-603 Jamestown/Candlestick		186		186
124	WDL-FAS-603 Jamestown/Candlestick		186		186
125	ISP Midland ES		186		186
126	ISP Valetudo Energy Storage - 40057		186		186
127	WDT-SR-2622WD-Foster Clean Power		186		186
128	WDT-SR-2637WD-Valley’sEdgeCleanPowerA		186		186
129	Panchi Pass Resvr-SIS		186	6,978	186
130	San Jose Interconnection-SIS		186		186
131	1001 Potrero-SIS		186	20,741	186
132	SFO Airport Substation Expansion-SIS	1,842	186		186
133	PG&E Transmission Planning General Cons	37,091	186		186
134	ISP Cascade Energy Storage Expansion		186		186
135	ISP Vineyard -40062		186		186
136	Q1270 - Corby Vaca-Dixon Sub- (RNU)		186		186
137	Q1275 - Tesla Substation - (RNU)		186		186
138	WG - C14 - SM - Project 155		186		186
139	Cluster 13 Phase 2		186		186
140	WDTLoad-SIS-DOE LBNL	205	186		186
141	WDT-SIS-119998837-Dos Palos Clean Power		186		186
142	WDT-SR-121482058-Cedar 1-Queue#2825-WD		186		186
143	WDT Load-SIS-TTC Minna St.		186		186
144	WDT Load-SIS-TTC Natoma St.		186		186
145	Q1539 - Irving Storage Project		186		186
146	Cluster 14 Phase 1	306,134	186		186
147	Q1135 - Scarlet Project		186		186
148	WDT Load- 601 25th St- New Service- SIS	1,403	186	93	186
149	WDT load- 601 25th St- Increase RC- SIS		186	120	186
150	WDT-2814 Great Highway SIS		186		186
151	Shelter Cove Supplemental Solar Study		186		186
152	2022 Reassessment		186	657,414	186
153	WDT - Load-SIS		186	23,786	186
154	EPIC4 Temp Cost Collect Joint Admin Work		186		186
155	EPIC4 Temp Cost Col. Investment Plan Dev	1,000	186		186
156	EPIC4 Temp Cost Col. Impact Report Devel		186		186
157	EPIC4 Temp Cost Col. Benefits Framework		186		186
158	Prepaid License Fee GE Maint		186		186
159	WDT Application: 601 25th St New Service NN 123223073		186	23,083	186
160	WDT-SR-123038102-Confliti Jr. 3057-WD		186		186
161	WDTLoad-Mission Rock (SIS)		186		186
162	WDT - SIS Plan for Balboa Redevelopment NN 123525285		186		186
163	WDT-EIT & SIS 3057-WD Confliti Jr. 12303	1,580	186		186
164	WDT - Load-FAS	1,178	186		186
165	2500 Mariposa St. - IND	1,847	186		186
166	WDT - SIS Plan for 2500 Mariposa Street Mixed NN 123635730	1,752	186		186
167	LBNL Facilities Study (FAS)	34,454	186		186
168	WDT 603 Jamestown-Candlestick Point-SIS	3,008	186		186
169	EPIC 3.41 Construction		186		186
170	Pacheco Reservoir (PREP) FAS	10,772	186		186
171	WDT-SR 3117-WD Piedmont Hillside Clean P		186	1,020	186
172	ISP - Township Expansion		186		186
173	ISP Cuyama Buckhorn Solar - 40071		186		186
174	ISP Cuyama Buckhorn Solar – 40071		186	344	186
175	WL - Midway-Wheeler Ridge Protections	6,027	186		186
176	ISP Malaga BESS 40073	3,317	186		186
177	875 Bayshore Blvd - SIS		186		186
178	SMUD Q11 Juniper Creek (fka Sunridge Sto		186		186
179	WDT-EIT/SIS 123775802 Wunpost Clean Powe	6,045	186		186
180	3500 Great Hwy SIS		186		186
181	1 Sgt John V Young Ln SIS	3,407	186		186
182	Cluster 14 Phase 2	1,702,481	186		186
183	ISP Manzanita Energy Storage P40077	1,439	186		186
184	ISP Salt Flat Energy Storage P40078	7,305	186	7,305	186
185	ISP Feather Energy Storage P40079	1,151	186		186
186	875 Bayshore Blvd SIS	4,363	186	25,000	186
187	2500 Mariposa St - Mixed	574	186	30,000	186
188	2500 Mariposa - IND - FAS		186	30,000	186
189	EPIC4 Temp Cost Collect - Launch Prep	10,216	186		186
190	ISP, Mount Lassen Power Plant P40082	1,057	186		186
191	CCSF WL TO - San Francisco Airport SIS	14,497	186	60,000	186
192	FAS-Bottle Rock Power Plant Repowering P	86	186	15,000	186
193	WL- SIS- Port of Oakland SS-R-10/SS-R-14	1,203	186		186
194	WL-SIS- CCSF - 460 Jessie St	1,948	186		186
20	Total	2,355,474		756,626
21	Generation Studies
22	Estrella Substation - Facilities Study	8,593	186		186
23	R21-Livermore Community Solar Frm-Det St		186		186
24	R21Beldrige Wtr Stor 352165 NEM2 Det Sty		186		186
25	WDT - Chevron USA Prod Co ISP		186		186
26	Shiloh I Wind Project Facilities Study		186		186
27	Exchequer RAS - CAISO Post COD		186		186
28	MMA - Q1158 Slate - ISO 51731		186		186
29	MMA - QF Santa Clara Wind - 51155		186		186
30	MMA - QF Forebay Wind - 51154		186		186
31	Q877 California Flats - Roadway PEIE		186		186
32	Kingsburg Cogen - Facility Study		186		186
33	WDT - CA-17-0097 SB43 Arco - ISP		186		186
34	WDT-CA-17-0101 SB43 Devils Den-Fst Trk		186		186
35	WDT SEPV American Canyon/FT		186		186
36	WDT - DRES Quarry 2.3/FT		186		186
37	WDT - FT - ZGlobal - Eagle 2 Solar		186		186
38	WDT - FT - Morris 385 LLC - Morris 385		186		186
39	WDT - FT - El Pomar Parners - El Pomar		186		186
40	WDT-FT-ET Solar - Midway Towers Comm Sol		186		186
41	WDT-FT-ET Solar - East Bay Community Sol		186		186
42	WDT - SR - Green Light - Eagle 2 Solar		186		186
43	R21-DS-BNB Renewable-Campbell Soup Supp		186		186
44	R21-DIS-Forefront-CDCR-1569-RD		186		186
45	WDT - FT - EPRI - SVUSD Bus Barn Storage		186		186
46	WDT-FT-REP Energy-DRES Quarry 2.4		186		186
47	WDT-FT-Renewable Prop-Palm Drive Solar C		186		186
48	WDT-ISP-Calbio Energy-Bar20 Dairy Biogas		186		186
49	WDT-FT - DG California Solar-Lodi Solar		186		186
50	R21-DIS-Syntech Bioenergy-Carriere Fam F		186	507	186
51	WDT-Wireless Sur-Cenergy-NLH1 Solar-0102		186		186
52	MMA - Collins Pine Repower - ISO 51161		186		186
53	WDT-FT-RenewProp-Silveira Ranch Solar C		186		186
54	WDT-FT-RenewProp-Silveira Ranch Solar D		186		186
55	WDT-FT-RenewProp-Silveira Ranch Solar A		186		186
56	WDT-FT-RenewProp-Silveira Ranch Solar B		186		186
57	WDT-ISP: PG&E CoyoteValleyEnergyStorage		186		186
58	R21-DIS:CupertinoElec-WonderfulOrch33018		186		186
59	WDT-FT: Zero Energy - Fallon Two Rock Rd		186		186
60	WDT-FCDS: Ormat Nevada-Pease Reliability		186		186
61	R21-DIS: EnableEnergy-SpecialtyGran34465		186		186
62	WDT-SR: Apex Energy - Jade Solar 1865-WD		186		186
63	WDT-ISP: Solvida - PutahCreekSolarFarmN		186		186
64	WDT-FCDS: Solvida - PutahCreekSolarFarmN		186		186
65	R21-DS: Daisy Renew - EarlJohn App 37593		186		186
66	R21-DS: TONY MEIRINHO DAIRY AND SONS		186		186
67	WDT-FCDS: Calpine - Cygnus Power Bank		186		186
68	R21-DS: Cupertino E-Wonderful Orch 41293		186		186
69	Repower - Kelly Ridge Powerhouse - SFWPA		186		186
70	WDT-CS: Origis Operating-Vaquero Storage		186		186
71	WDT-FCDS: OrigisOperating-VaqueroStorage		186		186
72	WDT-FT: SFPUC-Starr King PV Installation		186		186
73	R21-DS: BessieDig-HilltopHolsteins 38098		186		186
74	WDT-FCDS: CalpineCorp-PantheraPowerBank		186		186
75	WDT-CS: Capine Corp-Riverrun Power Bank		186		186
76	WDT-FCDS: CapineCorp-Riverrun Power Bank		186		186
77	WDT-FT: Soltage-Bradley Gillett Solar 1		186		186
78	WDT-SIS: RenewableProp-SilveiraRanchSolA		186		186
79	WDT-SIS: RenewableProp-SilveiraRanchSolB		186		186
80	WDT-SIS: RenewableProp-SilveiraRanchSolC		186		186
81	WDT-FT: Engie-Hayward EBCE Array		186		186
82	WDT-SR: Kent Solar, LLC - KS Energy		186		186
83	MMA1-NoQ Moss Landing Unit 6-ISO 51164		186		186
84	MMA - QF FrickSummitRepower - ISO 51135		186		186
85	R21-DS: Google-MFABayviewFacSolar50088		186		186
86	WDT-ISP: ZGlobal - Jade Solar_July 2018		186		186
87	R21-DS: West Biofuels - Hat Creek Bioene		186		186
88	EGI: Forbestown PH - SFWPA - Testing		186		186
89	R21DIS:CityofMaderaRES-BCT (App 54517)		186		186
90	WDT-SIS:Soltage,SanArdoPineValleySolar1		186		186
91	WDT-FT-SolarElectricSolution-SEPVBarbar3		186		186
92	WDT-FT-WildcatRenewableRPSantaCruzSolar1		186		186
93	WDT-FT-WildcatRenewableRPSantaCruzSolar2		186		186
94	Rule21:DS-JKB EnergySierraPacificAP55806		186		186
95	MMA #5 - Q1036 Mustang 2 - ISO 51601		186		186
96	WDT-FT-ReneSolaPowerHoldingsTaylorSolar		186		186
97	Rule21:DSFresnoUnifiedSchoolSunnysideH.S		186		186
98	Rule21DSBerryPetroleumCompy-BerryCogen18		186		186
99	WDT-FastTrack-Calcom Solar-Sycamore-Napa		186		186
100	WDT-SIS- Kent Solar-LLC-KS Energy		186		186
101	WDT-SR-RenewableRPSantaCruzSolar1Q2030WD		186	472	186
102	R21#Detailed Study-Superior Packing Co.		186		186
103	WDT-ISP/FCDS-DGCali-YubaCityEnergyStorag		186		186
104	R21-DS: CH4 Green Energy CDE 4		186		186
105	WDT:FT - Corda II - Cratus Energy Mgmt		186		186
106	WDT:FT - Washoe Ave - FFP CA Com Solar		186		186
107	R21-DS: Wonderful Pistachios & Almonds		186		186
108	MMA2 - Q1106 Fountain Wind - ISO 51770		186		186
109	R21-DS: WonderfulPistachios&Almonds67792		186		186
110	WDT:SR - 2040-WD - Gas Co Road Solar 1		186		186
111	R21:DS - City of San Jose (App 68019)		186		186
112	WDT:ISP - Leo Solar - Apex Energy		186		186
113	R21-DS: MacphersonOil-RoundMountainSolar		186		186
114	WDT–FillInStudyReneSolaPowerTaylorSolar		186		186
115	MMA1 - Q1239 Medeiros Solar - ISO 40030		186		186
116	WDT-SR-SolarElectricSolutionSEPVBarbara3		186		186
117	WDT–SR-Kinet Inc-Murphys Afterbay Hydro		186		186
118	Rule21:DS-GRANITEROCKCOMPANY(App69212)		186		186
119	Rule21-DS-ChicoElectricRoplastApp#4959		186		186
120	Rule21DS-GOLDENSTATEFC-App71807		186		186
121	WDT-FT-UniversalSlAircoupeSolar3((30N27)		186		186
122	MMA1 - Q1010-Dyer - ISO 51539		186		186
123	WDT-SR-FFPCACommunitySolar-WashoeAvenue		186		186
124	WDT–SIS-ApexEnergySolutioGasCoRoadSolar1		186		186
125	WDT-ISP-CES Electron Farm One,LLC		186		186
126	Rule21DS-ATS-KaiserDublinHUBCancerCenter		186		186
127	Rule21-Detailed Study-FIRESTONEWALKERINC		186		186
128	Rule21-DS-7THSTANDARDRA-SunPacific-Lerdo		186		186
129	WDT:FT - Corda III - Cratus Energy Mgmt		186		186
130	WDT-FT-Elie MehrdadTrustsolaparkphaseA		186		186
131	MMA - Q1363-Sandhill C - ISO 53028		186		186
132	WDT-SIS-CratusEnergyManagementCorda2		186		186
133	Rule21:DS-SUNNYGEMLLC(App 84294)NEMExP		186		186
134	WDT-SIS-FFPCACommunitySolarWashoe Avenue		186		186
135	Rule21:DS-CALAMCO		186		186
136	WDT-IS-Cratus Energy MGMT-Corda IV		186		186
137	WDT-FT-RenewableProper-SoscolFerrySolarA		186		186
138	WDT-FT-RenewableProper-SoscolFerrySolarB		186		186
139	WDT-FT-RenewableProp-ByronHotSpringSolar		186		186
140	WDT-IS-JATONLLC-KecksRoadSolarFacility		186		186
141	WDT-FT-RenewableProperti-WilsonHillSolar		186		186
142	Rule21-DetailedStud-SpecialtyGranulesINC		186		186
143	R21:DS - SunWest Bioenergy - 2076-RD		186		186
144	WDT:FT-Gas Co Road Solar 3-Apex Energy		186		186
145	WDT:FT-Gas Co Road Solar 4-Apex Energy		186		186
146	WDT:SIS-Gas Co Road Solar 2-Apex Energy		186		186
147	MMA - Q1143-Alpaugh Storage - ISO 51720		186		186
148	WDT-FTCratusEnergyManagement-Mendoza		186		186
149	WDT-Cluster12-CalPine-CalSunSolar2004-WD		186		186
150	WDT–FullCapacity-VESI11LLC-Eris Storage		186		186
151	WDT-FT-GoldenStateRenewable-HuronStorage		186		186
152	Rule21:DGS-CorcoraIrrigationDistrict-5MW		186		186
153	WDT–SR-ZGlobal-Lara Solar 2 (2142-WD)		186		186
154	WDT-SR-RenewableProperti-WilsonHillSolar		186		186
155	WDT-ISBloomENGSouthpointRanchDairyBiogas		186		186
156	WDT–SR-RenewableProper-SoscolFerrySolarB		186		186
157	EGI:Facilities Study - Santa Clara Wind		186		186
158	EGI:Facilities Study - Forebay Wind		186		186
159	Rule21:DS:MESAWater-BerrendaMWD-StationA		186	49,787	186
160	EGI:Facilities Study - Collins Pine Co.		186		186
161	Rule21:DS-CALIFORNIARESOURCESCORPORATION		186		186
162	Rule21-DS-TIMIRAN INC-Huller Add-On		186		186
163	WDT-Clu12FCDS-Solvida-PutahCreekFarNorth		186		186
164	WDT-IS-ConflittiEnergy-CESElectroFarmOne		186		186
165	MMA - Q1235 Hudson Solar 1 - ISO 51904		186		186
166	Rule21:DetailedStudy-WAL-MART STORES INC		186		186
167	Rule21:DS-WAL-MARTSTORES-WAL-MART#1608		186		186
168	WDT–IS-BorregoSolar-EarthquakeProtection		186		186
169	WDT–SR-ApexEnergySolutionGasCoRoadSolar3		186		186
170	CCSF Warnerville Sub Rehab		186	12,273	186
171	Rule21:DS-FallRiverRCD-McArthurBioenergy	753	186		186
172	NextEra Honey Lake Solar DTT		186		186
173	WDT-FT-RenewableProper-SoscolFerrySolarC		186		186
174	WDT-FT-RenewableProper-SoscolFerrySolarD		186		186
175	WDT–SIS-RenewablePr-ByronHotSpringsSolar		186		186
176	Rule21:DS-RWA/UCMCOGENERATION(App104272)		186		186
177	Rule21:DS-CityofMaderaWWTP-RES-App103889		186		186
178	WDT-SR-Bloom-PasoCreekFamilyDairyBiogas		186		186
179	MMA-Q557-CED White River West2-ISO 50555		186		186
180	Rule21:DS-LionBrotherNewstone(App106347)		186		186
181	WDT-EIT/SIS-ApexEnerg-LaraSolar2-2142-WD		186		186
182	R21-FS-TLT Enterprises-HatCreekBioenergy		186		186
183	WDT-FT-Renewable-HatcheryRoadSolarB		186		186
184	WDT-FT-Renewable-HatcheryRoadSolarA		186		186
185	WDT-SR-Renewable-Soscol Ferry Solar C		186		186
186	WDT-FT-NapaJamiesoCanyon-NapaSelfStorage		186		186
187	WDT-FT-GCLNewEnergyHartleySubstation		186		186
188	WDT-FT-GCLNewEnergyPlumasSubstation		186		186
189	WDT–ISP-ApexEnergySoluti-GasCoRoadSolar3		186		186
190	WDT-ISP-ApexEnergySolutio-GasCoRoadSola4		186		186
191	Rule21:DS-DREYERSNestleBakersfiApp111016		186		186
192	R21-DS-J R SIMPLOT COMPANY INC		186		186
193	WDT-FT-SaltbrushPlainsLLC-SaltbrushPlain		186		186
194	Rule21-DS-CARESOURCESPRODUCTI-CRC-MtPoso		186		186
195	WDT-SR-RenewableProp-HatcheryRdSolarA		186		186
196	WDT-SR-RenewableProp-HatcheryRdSolarB		186		186
197	Rule21-DS-Toma Tek Inc		186		186
198	WDT-FT-GoldenStateRenewEnergy-ColmaSolar		186		186
199	WDT-FT-Vesi14LLC-CeresEnergyStorage		186		186
200	WDT-FT-Dimension CA 1 LLC-Jacobs 1		186		186
201	WDT-FT-Dimension CA 1 LLC-Jacobs 2		186		186
202	WDT-FT-ApexEnergySolutionsLLC-JadeSolar3		186		186
203	WDT-FT-Dimension CA 1 LLC-Henrietta		186		186
204	WDT-FT-Dimension CA 1 LLC-Wellfield		186		186
205	WDT-ISP-Dimension CA 1 LLC-Jorge		186		186
206	WDT-FT-Dimension CA 1 LLC-Mendoza		186		186
207	EGI:FacilitiesStudy-sPowerAltamontMidway		186		186
208	WDT-FT-ApexEnergySolutions-PineFlat1		186		186
209	WDT-FT-ApexEnergySolutions-PineFlat2		186		186
210	Rule21-DS-GILLIG LLC-GILLIG LLC		186		186
211	WDT-SR-GclSysIntegTechnology-BessPlumas		186		186
212	WDT-FT-GclSysIntegTechgy-MarysvilleBESS		186		186
213	WDT-FT-GclSysIntegTechgy-Cotati BESS		186		186
214	WDT-FT-DimensionCA1AlpaughDacSolar1103		186		186
215	Rule21-GoldenStateFcLlc-SCK1 Amazon		186	3,356	186
216	Rule21:DS:SENTINELPEAKRESCA-HopkinsSolar		186		186
217	WDT-EIT--RenewableProp-HatcheryRdSolarB		186		186
218	WDT-EIT--RenewableProp-2296WDByronHwy		186		186
219	WDT-EIT--RenewableProp-HatcheryRdSolarA		186		186
220	Rule21-DS-Chevron-LostHills_Storage		186		186
221	WDT-SR-Hayworth/Fabian-Oakley3#2333-WD		186	1,240	186
222	WDT-ISP-Dimension CA 1 LLC-Mendoza		186		186
223	WDT-ISP-Dimension CA 1 LLC-Henrietta		186		186
224	MMA-Q1117-Aquamarine Westside-ISO51817		186		186
225	MMA-Q1242-Pluot-ISO52008		186		186
226	MMA-Q1391-Sonrisa-ISO53017		186		186
227	MMA-Q779-Wright Solar-ISO50712		186		186
228	MMA-Q1350-Beltran Central Solar-ISO53069		186		186
229	MMA-Q1379-Heartland 1-ISO53048		186		186
230	MMA-Q1380-Hearland 2-ISO53042		186		186
231	MMA-Q1382-Las Camas 1-ISO53030		186		186
232	MMA-Q643W-Re Mustang-ISO50630		186		186
233	MMA-Q643X-Re Tranquility-ISO50647		186		186
234	MMA-Q1129-Luna Valley-ISO51746 (Batch)		186		186
235	MMA-Q1139-Westlands Solar Blue-ISO51815		186		186
236	MMA-Q1456-Las Camas 3-ISO53203		186		186
237	WDT-ISP-Dimension CA 1 LLC-Jacobs 1		186		186
238	WDT-ISP-DimensionCA1-AlpaughDacSolar1003		186		186
239	WDT-ISP-Dimension CA 1 LLC-Jacobs2		186		186
240	WDT-SR-Q#2342-WD BESS Upper Lake		186		186
241	WDT-SR-Q#2343-WD BESS Hopland		186		186
242	WDT-SR-Q#2344-WD BESS Willits		186		186
243	WDT-FT-GldnStRenewEngr-DalyCityStorage		186		186
244	WDT-FT-Borrego-NorthCoastHwySolar2		186		186
245	WDT-SR-Q#2288-WD Saltbrush Plains		186		186
246	Rule21-DS-Wonderful Firebaugh		186		186
247	R21-App141055-Wonderful Kings		186		186
248	R21-DS-App142877-Sunnygem Huller		186		186
249	WDT-FT-Victoria Lane Solar		186		186
250	WDT-FT-River Bar Road Solar A		186		186
251	WDT-FT-River Bar Road Solar B		186		186
252	WDT-FT-TrueLeafInterconnectionExport		186		186
253	R21-DS-2291RD-CalResourcesProductionCorp		186	4,570	186
254	WDT-FT-GSRE Clear Lake Solar		186		186
255	WDT-FT-ApexEnergySolutions-LeoSolar1		186		186
256	WDT-FT-ApexEnergySolutions-LeoSolar2		186		186
257	R21-DS-152525-CaResrcesPrdn-SW 24 28 27		186		186
258	R21-DS-153273-SCIF- Vacaville Carports		186	7,053	186
259	WDT-IS-2299WD-BESS Luchetti		186		186
260	WDT-ISP-Vesi11 LLC-Eris Storage		186		186
261	WDT-SR-2417WD-TrueLeafIntconnectionExpt		186		186
262	WDT-ISP-2313WD-BessPlumas		186		186
263	WDT-ISP-Saltbrush 10	176	186		186
264	WDT-ISP-2343WD-BESS Hopland		186		186
265	WDT-ISP-2342WD-BESS Upper Lake		186		186
266	WDT-C13 FCDS-Eris Storage		186		186
267	WDT-C13 FCDS-Saltbrush 10		186		186
268	WDT-FT-Humboldt Community Solar		186		186
269	WDT-ISP-Hatchery Road Solar C		186		186
270	WDT-FT-Stockdale Dairy Biogas		186		186
271	WDT-ISP-Hatchery Road Solar D		186		186
272	MMA-Q1540-Plano Storage-ISO40047		186		186
273	WDT-SR-2434WD-Leo Solar 1		186		186
274	WDT-C13 FCDS-Stodola BESS		186		186
275	WDT-ISP-Callisto2Storage50MW		186		186
276	WDT-C13 FCDS-Callisto2Storage50MW		186		186
277	R21-DS-Rodeo Solar-NextEraEnergy	7,496	186		186
278	WDT-C13 FCDS-CliftonCourtSolar		186	45,906	186
279	R21-DS-2404RD-Lindt&SprungliNorthAmerica		186		186
280	MMA-Q1129-Luna Valley-ISO51746 (COD)		186		186
281	EGI:TO-FS-LSPGCGatesInterconnection	42,112	186		186
282	WDT-C13 FCDS-2226WD-CesElectronFarmOne		186		186
283	WDT-C13 FCDS-2322WD-CeresEnergyStorage		186		186
284	WDT-FT-Freedom Pass Storage	25	186		186
285	WDT-C13 FCDS-Freedom Pass Storage		186		186
286	MMA-Q267-Lodi Energy Center-ISO50204		186		186
287	WDT-SR-2472WD-Electra SES 1		186		186
288	R21-DS-10695 DECKER AVE		186		186
289	R21-DS-Bakersfield College		186		186
290	R21-DS-168920-WonderfulPomBeverage		186	4,303	186
291	R21-DS-174317-WonderfulPomJuice		186	7,490	186
292	R21-DS-118550964-Crimson PV		186		186
293	MMA-Q1103-Central40(Modification)-ISO518		186		186
294	WDT-FT-Bar20 Biogas Fuel Cell		186		186
295	R21-DS-175509-LegacyPackingDetailedStudy		186		186
296	WDT-ISP-119057258-County Road 18		186		186
297	WDT-ISP-119057480-Woodland Gravel Mine		186		186
298	WDT-ISP-2434WD-Leo Solar 1		186		186
299	R21-DS-178632-CrainWalnutCWS2 NEMA		186		186
300	WDT-ISP-2533WD-Madena Solar 3		186		186
301	R21-DS-178840-TaftEnergyProjects-NEMMT		186		186
302	R21-DS-182177-Madera WWTP-NEMExp		186		186
303	R21-DS-179034-SierraPacificInd-ChinCamp		186		186
304	R21-DS-177618-BerkeleyLabPSPS-EmgPwr		186		186
305	EGI:TO-FS-LS Power-Round Mountain	64,407	186		186
306	WDT-ISP-119339344-Apex-Pine Flat 1		186		186
307	WDT-ISP-119340651-Apex-Pine Flat 2		186		186
308	WDT-FT-119294847-RailroadWintersCleanPwr		186		186
309	R21-DS-198456-SE SURFACE WTP NEMMT		186		186
310	R21-DS-198470-Clovis Regional WWTP NEMPS		186		186
311	WDT-ISP-119563843-Pine Flat 3		186		186
312	WDT-ISP-119563984-Pine Flat 4		186		186
313	WDT-ISP-2469WD-GSRE Clear Lake Solar		186		186
314	WDT-ISP-119626368-Gibson Solar Project		186		186
315	WDT-ISP-119068517-AlamedaGrantLineSolar1		186		186
316	R21-DS-2521RD-WCW Parlier Generator 1		186		186
317	R21-DS-201102-VerweyHanfordPhase2NEMExp		186		186
318	WDT-FT-119670387-DiscoveryBaySouthClnPwr	710	186		186
319	WDT-FT-119303619-RanchSerenoCleanPower		186		186
320	WDT-ISP-119699805-Merced 2		186		186
321	R21-DS-2546RD-Engeman SVRC Energy		186		186
322	WDT-FT-119687890-Mantova Clean Power		186		186
323	MMA-Q1454-Hummingbird-ISO53156		186		186
324	MMA-Q1391-Sonrisa-AddBattryEngy-ISO53017		186		186
325	MMA-Q643X-TranquilityLLC-ISO50647		186		186
326	EGI:TO-FS-VistraEnergy-Oakland ES Unit 2		186		186
327	WDT-SR-2590WD-RailroadWintersCleanPwr		186		186
328	MMA-Q1374-Elkhorn Energy Storage-ISO5308		186		186
329	MMA-Q1117-Aquamarine-ISO51817		186		186
330	R21-DS-210197-TomaTek-Microgrid NEMMT		186		186
331	WDT-ISP-119916059-Alpaugh Dac Solar	88	186		186
332	WDT-ISP-119712090-Wellfield Dac Solar		186		186
333	WDT-ISP-119916434-Henrietta Dac Solar		186		186
334	Q1010-FS-Altamonts wind-Wind Study		186		186
335	R21-DS-220326-Amazon DUR3 NEMPS		186		186
336	WDT-ISP-119926766-Riosa Solar		186	4,897	186
337	MMA-Q539-Frontier Solar 1-ISO60070		186		186
338	R21-DS-228039-SonomaValleyHospital		186		186
339	MMA-Q1459-MulqueeneyRanch2Prjts-ISO53184		186		186
340	WDT-SR-2598WD-DiscoveryBaySouthCleanPwr	1,041	186		186
341	WDT-SR-2609WD-Mantova Clean Power		186		186
342	R21-DS-205844-AllanHancockCollege-NEMPS		186		186
343	MMA-OaklandPwrPlantUnit#2Repower-ISO5117		186		186
344	WDT-SR-2605WD-Applegate Clean Power 1		186		186
345	R21-DS-120090412-LibertyPackingPowerGen		186		186
346	R21-DS232235-BellanaveRanch-SunnyCowNEMA		186		186
347	WDT-SR-2621WD-Oroville Dam Clean Power		186		186
348	WDT-FT-120150141-West Tambo Clean Power		186		186
349	R21-DS-120146229-CITY OF FRESNO-NEMMT		186		186
350	MMA-Q643W-Mustang Solar Project-ISO50630		186		186
351	WDT-ISP-2590WD-RailroadWintersCleanPower		186		186
352	R21-DS-120239758-HighRollerDairy-NEMA		186		186
353	WDT-ISP-120403503-County Road 80 Solar	5,611	186	3,515	186
354	WDT-SIS-120238371-TierraBuenaES		186		186
355	R21-DS-245314-AeraEnergySA Solar1-NEMMT		186	7,700	186
356	R21-DS-238742-Belridge Solar-NEMMT		186		186
357	WDT-ISP-120457996-Madena Solar 4		186		186
358	R21-DS-2610RD-SteamanKimberlinaBioMass		186		186
359	Q1097 - Bear Canyon - NU Liability		186		186
360	RNU PM for the Q1349 - Aramis P		186		186
361	Q1391 Sonrisa Project Liability		186		186
362	Q1363 Sand Hill C Project Liability		186		186
363	Q1109 - North Central Valley Liability		186		186
364	WDT-ISP-120461724-TastefulSelectionsExpt		186		186
365	Q1455 – Janus		186		186
366	Q1244 – Proxima Solar		186		186
367	Q1499 - Jasmine		186		186
368	WDT-SR-2670WD-West Tambo Clean Power		186		186
369	R21-DS-253985-RoundMountainSolar1-NEMExp		186		186
370	WDT-ISP-120601459-BH Solar Phase 2		186		186
371	WDT-FT-120576600-Konabos Clean Power		186		186
372	WDT-C14FCDS-2533WD-MadenaSolar3	166	186		186
373	WDT-C14FCDS-2568WD-ElectraSES1	166	186		186
374	WDT-C14FCDS-2569WD-MercedBESS	709	186		186
375	WDT-C14FCDS-2589WD-AlamedaGrantLineSol1	166	186		186
376	WDT-C14FCDS-2595WD-GibsonSolarProject	165	186		186
377	WDT-C14FCDS-2596WD-Merced 2	166	186		186
378	WDT-C14FCDS-2599WD-WestsideSolarProject		186		186
379	WDT-C14FCDS-2601WD-Byron PV		186	46,692	186
380	WDT-C14FCDS-2624WD-Riosa Solar		186		186
381	MMA2-Q1117-Aquamarine Westside-ISO51817		186		186
382	WDT-FCDS-120601459-BH Solar Phase 2		186		186
383	Q1272 - Cascade Energy Storage Project		186		186
384	WDT-ISP-120685223-Sunny Solar		186	14,946	186
385	WDT-ISP-120658687-Bloomfield		186		186
386	WDT-FCDS-120658687-Bloomfield		186		186
387	WDT-ISP-120695587-Oakport Energy Storage	666	186		186
388	WDT-FCDS-120695587-OakportEnergyStorage	1,849	186		186
389	WDT-ISP-120709622-Soscol Ferry Storage		186		186
390	WDT-FCDS-120709622-Soscol Ferry Storage	331	186		186
391	WDT-FCDS-120709623-Lake Herman Storage	596	186		186
392	WDT-ISP-120719906-IndustrialPkwyStorage		186		186
393	WDT-FCDS-120719906-IndustrialPkwyStorage	165	186		186
394	WDT-CS-120716451-Isabella Storage		186	65,909	186
395	WDT-FCDS-120716451-Isabella Storage		186		186
396	WDT-FT-120746442-Orchard Road Solar		186		186
397	R21-DS-265773-CollegeOfTheRedwoodsNEMPS		186		186
398	WDT-FT-120823806-Billy Wright Road Solar		186		186
399	WDT-ISP-121423142-Altamont LFGTE		186		186
400	WDT-ISP-120885792-KingsDacSpringSolar		186		186
401	WDT-ISP-120886724-AvenalCutoffDacSpring	1,506	186		186
402	WDT-FT-121322856-East Cleveland Rd Solar		186		186
403	R21-DS-121191139-CITY OF BAKERSFIELD_WT3		186		186
404	R21-DS-121191864-CITY OF BAKERSFIELD_WF		186	3,979	186
405	R21-DS-121334398-FRESNO_SE Surface WTP		186		186
406	WDT-FT-121350601-Moscone West Solar		186		186
407	R21-DS-121322443-Western Sky Dairy LLC		186	6,587	186
408	R21-DS-121346000-UCSC - BESS		186		186
409	WDT-FCDS-121368198-Freesia Hybrid Solar	663	186		186
410	WDT-ISP-121368198-Freesia Hybrid Solar	935	186		186
411	R21-DS-121325832-BAKERSFIELD Ice Center		186		186
412	WDT-SR-120823806-Billy Wright Road Solar		186		186
413	MMA3-Q1350- Paulsell-ISO5311		186		186
414	MMA-Q1397- Sandrini Sol 1-ISO4211		186		186
415	MMAKingsRiverConservationDistrctISO51182		186		186
416	WDT-FT-121482058-Cedar 1		186		186
417	WDT-SR-120746442-Orchard Road Solar		186		186
418	WDT-FT-121491941-South Moraga Road Solar		186		186
419	WDT-SR-121322856-East Cleveland Road		186		186
420	WDT-FT-121417106-Flying Goose Solar		186		186
421	WDT-ISP-121548107-Sutro Reservoir		186		186
422	R21-DS-121554184-Wonderful Orchards-West		186		186
423	WDT-ISP-121543000-Cademo	436	186		186
424	WDT-FCDS-121543000-Cademo	829	186		186
425	WDT-ISP-121548310-Unvsty Mound Reservoir		186		186
426	Rule21-DS-BritishAMBurney(120531348)BIOM		186		186
427	WDT-FT-Gardenia2(121575310)ApexEngSoluti		186		186
428	WDT-FT-Gardenia1(121574987)ApexEngSoluti		186	104	186
429	Rule21-DS-TULARE-(271674)NEMPS#121600524		186		186
430	Q1394 - Driftwood Stella Solar Project:		186		186
431	Q1495 - Chalan Solar Project		186		186
432	EGI:TO-FS-DollarWind-InternationTurbine		186		186
433	WDT-FT-121644536-West Tambo Clean Power		186		186
434	WDT-ISP-121643658-Theta		186		186
435	WDT-ISP-121643450-Blanco		186	56,497	186
436	WDT-FT-121645938-Ranch Sereno Clean Powr		186		186
437	WDT-FT-121645733-DiscoveryBaySouthClean		186		186
438	R21-DS-120612553-Placer County RES-BCT		186		186
439	WDT-ISP-120823806-Billy Wright Rd Solar		186		186
440	WDT-FT-121694123-North Bank Clean Power		186		186
441	WDT-ISP-121731160-Redwood Highway Solar		186		186
442	WDT-FT-121734676-Buzzelle expansion		186		186
443	WDT-ISP-121743682-Bodega Avenue Solar		186		186
444	WDT-FT-121767146-Upper Valley Disposal S		186		186
445	WDT-ISP-121322856-East Cleveland Road So	44	186		186
446	WDT-FT-121795513-Oroville Dam Clean Powe		186		186
447	R21-DS-302094-JACK DE JONG EXPNEMA		186		186
448	R21-DS-301071-MFA - Bayview Facility Sol		186		186
449	MMA - Hanford Peaker Plant-ISO51187	25,131	186	30,080	186
450	R21-DS-120597306-COASTAL PACIFIC FOOD DI		186		186
451	R21-DS-294287-SIERRA JOINT COMMUNITY COL		186		186
452	R21-DS-121845137-AERA ENERGY LLC (298673	41,651	186		186
453	WDT-SR-121417106 -Flying Goose Solar-283		186		186
454	R21-DS-120662541-HGST INC A WESTERN DIGI		186		186
455	WDT-SR-121644536-West Tambo Clean Power		186		186
456	WDT-SR-121795513-Oroville Dam Clean Powe		186		186
457	WDT-ISP-121951120-Morgan Valley Wind	1,199	186		186
458	WDT-SR-121575310-Gardenia 2-2853-WD		186		186
459	WDT-ISP-121955097-Moon Valley Energy Sto	7,118	186		186
460	R21-DS-121955755-North Kern Water Storag		186		186
461	R21-DS-121967208-Wheeler Ridge 2 (304645		186		186
462	WDT-SR-121574987-Gardenia 1 Q-2852-WD		186		186
463	Q1557 Noosa Energy Storage Project:		186	173,580	186
464	WDT-SR-Rancho Sereno Clean Energy-2866-W		186		186
465	WDT-ISP-121974730-Thorntree Drive Solar		186		186
466	R21-DS-121978170-ANDY ZONNEVELD (321144)		186	6,512	186
467	WDT-SIS-121417106-Flying Goose Solar-283		186		186
468	MMA -Q1135-Scarlet Project ISO51732		186	7,015	186
469	MMA2-Q1391-Sonrisa Solar Project ISO5317		186	5,633	186
470	R21-DS-121391712-BOSCHMA AND SONS DAIRY		186		186
471	WDT-ISP-Cedar 1- 122047425		186	9,441	186
472	WDT-ISP-Avenue 26 Solar (122065226)		186		186
473	R21-DS-122064947-HANFORD GRAIN COMPANY,		186		186
474	WDT-SR-121736818-Jarvis Expansion 2875-W		186		186
475	WDT-C14 FCDS-121951120-Morgan Valley Win	1,467	186		186
476	WDT-C14 FCDS-121955097-Moon Valley Energ	1,068	186		186
477	WDT-SR-121734676-Buzzelle expansion 2874		186		186
478	R21-DS-122077732-OPEN SKY RANCH INC (366		186		186
479	R21-DS-122125257-GALLO CATTLE COMPANY A		186		186
480	R21-DS-122135614-FedEx Ground (321110)	1,262	186		186
481	WDT-ISP-121767146-Upper Valley Disposal		186		186
482	WDT-SR-121694123-North Bank Clean Power		186		186
483	R21-DS-122157522-Kirschenmann Farms Inc		186		186
484	R21-DS-122160727-COSTA VIEW FARMS #2 (41		186		186
485	WDT-ISP-122156933-Fuji battery storage	3,168	186		186
486	R21-DS-122169001-Maas Energy (415301) EX	180	186		186
487	R21-DS-122169882-Maas Energy-Merced(4189		186	2,993	186
488	WDT-ISP-122215225-Billy Wright Road Sola		186		186
489	WDT-FT-122213129-Pyramid Hills Solar		186		186
490	R21-DS-122206225-SUTTER GOULD MEDICAL FO		186		186
491	R21-DS-122240372-Hansen Ranches (454272)		186		186
492	WDT-ISP-122268416-Gardenia 1	496	186		186
493	R21-DS-120842473-Amazon Stockton SCK4 Mt		186		186
494	R21-DS-Amazon Stockton SCK4(2781-RD) Mtr		186		186
495	R21-DS-122260210-City of Fresno-New Term		186		186
496	R21-DS-122240568-City of Fresno - Airpor		186		186
497	MMA 2 -Q625-EE K Battery 1 ISO60113-FC	20,347	186		186
498	MMA3-Q539-CrowCreekSolar1 FrontSol 60070	35,067	186		186
499	MMA 2-Q678-Excelsior(FivePointsSol)50710	1,717	186		186
500	MMA 1-AlgonquinPwr Sanger2 Project 51189	529	186		186
501	MMA 1- Q1591 Carthage ISO53600	270	186		186
502	R21-DS-122319919-Maas Lakeside (496664)		186	4,953	186
503	R21-DS-122319511-Google LLC 1450 Bayhill		186		186
504	WDT-FT-122316848-Pittsburg RV & Boat Sto		186		186
505	Q1565 Dynamo Solar Tulucay Sub		186		186
506	WDT-ISP-122369696-Rio Vista Executive Bo		186		186
507	WDT-ISP-122375253-Stella	2,163	186		186
508	R21-DS-121754384-Del Oro		186		186
509	Q1479 Key Storage 1 Project.		186		186
510	Q1460 – Pinto Pass		186		186
511	WDT-ISP-122412363 Utica Avenue Solar	165	186		186
512	MMA 1-Int Turbine Research ISO 51179	83	186		186
513	WDT-ISP-122426692-La Porte Road Solar	86	186		186
514	Q1596 Buttonbush Solar Hybrid Energy Cen		186		186
515	MMA 1- Q1120 Chestnut Westside ISO51818		186		186
516	MMA 3- Q1139 WestlandsSolarBlue ISO51815		186		186
517	R21-DS-122455602 WONDERFUL PISTACHIOS &		186		186
518	WDT-SR-122213129-Pyramid Hills Solar2946		186		186
519	R21-DS-122461346 JACKSON FAMILY WINES IN		186		186
520	R21-DS-122503044 COUNTY OF SANTA CLARA -		186		186
521	WDT-FAS- 2764-WD Industrial Parkway Stor		186		186
522	R21-DS-122481562 Camino Diablo PV1A EXPO	5,524	186		186
523	R21-DS-122496088 MOORETOWN RANCHERIA COR		186		186
524	R21-DS-122509819 Kraft Heinz NEMPS		186		186
525	R21-DS-122514366 COUNTY OF SANTA CLARA_S		186		186
526	WDT-FAS-2603-WD Bethel Island Clean Powe		186	15,000	186
527	R21-DS-122492038 Plug Project Holding Co		186		186
528	MMA 1- Q1275 Kola ISO51917	1,048	186		186
529	Q1443 – Angela project.		186		186
530	R21-DS-121907680-Electrify America LLC,		186	8,530	186
531	WDT-ISP- 2864-WD -West Tambo Clean Power		186		186
532	WDT-ISP-122607302 Shain Solar	42	186		186
533	R21-DS-121822650-Atascadero State Hospit		186		186
534	MMA 1- Q81 BOTTLE ROCK POWER Project ISO	2,131	186		186
535	WDT-SR-2966-WD Pittsburg RV & Boat Stora		186		186
536	R21-DS-122605312 Lakeside Power Gen EXPO		186		186
537	R21-DS-122786258 LIFE TECHNOLOGIES CORP		186		186
538	WDT-FT-122786538 Berrenda Mesa C		186		186
539	WDT-FT-122602630 Berrenda Mesa A		186		186
540	WDT-FT-122786531 Berrenda Mesa B		186		186
541	R21-DS-122627081 SUTTER HOME WINERY INC		186		186
542	R21-DS-122789304 Joseph Wilson - Shafter		186		186
543	R21-DS-122877254 Avalon Dairy Farm NEMA		186		186
544	R21-DS-122891582 CRIMSON RESOURCE MANAGE		186	3,662	186
545	WDT-ISP-122798592 Kings Dac Fall Solar		186		186
546	R21-DS-122561159 CALMAT CO NEMPS Project	13,274	186		186
547	R21-DS-122547162 FARMINGTON FRESH INC N	383	186		186
548	R21-DS-122613176 BARBOSA CABINETS INC N		186	9,660	186
549	MMA 1-Q653EASouthKernSolarPVPlant60175C	336	186	15,991	186
550	MMA 3- Q954 Fifth Standard Solar ISO514	165	186		186
551	MMA 3-Q1027 Blackbriar Projects ISO51565	83	186		186
552	R21-DS-122893231 TERRACORE OPERATING COM		186		186
553	WDT-FAS-121974730 Thorntree Drive Solar		186		186
554	WDT-FT-122945705 Alameda Creek Watershed		186		186
555	WDT-FT-122947855 South East Health Cente		186		186
556	MMA - Q222 Montezuma II Wind ISO50145-C	7,579	186		186
557	R21-DS-122891306 MILLS - PENINSULA HEAL		186	4,005	186
558	WDT-FT-122987074 Kings CSG B 1102		186		186
559	WDT-FT-122984544 Kings CSG 1 LLC		186		186
560	WDT-ISP-122990232- Avenue 26 Solar Phase	44	186		186
561	R21-DS-122949548-SUTTER BAY MEDICAL FOUN		186		186
562	R21-DS-122020675-City of Fortuna-Kenmar		186		186
563	R21-DS-122969974-United States Cold Stor	360	186	50,525	186
564	R21-DS-122393897-HARRIS-WOOLF ALMOND HUL		186		186
565	WDT-ISP-122999678-Canyon Road Solar	166	186		186
566	MMA 3- Q1244 Proxima SOlar ISO51980		186		186
567	R21-DS-122227723 City of Atwater (2950-R	2,002	186	7,595	186
568	R21-DS-121538276 Seaboard Energy Export		186	5,526	186
569	R21-DS-123008654-SYSTEM SERVICES OF AMER	452	186		186
570	WDT-ISP-123059761-Twin Pine Circle Solar	702	186		186
571	R21-DS-123052687 E & J GALLO WINERY - Fr	5,421	186		186
572	WDT-SR-122602630 Berrenda Mesa A 3009-WD		186		186
573	R21-DS-123151899 CITY OF PETALUMA_Ellis	382	186		186
574	WDT-ISP-123103659 Tubbs Island Solar 1	750	186		186
575	WDT-FT-123038102 Confliti Jr		186		186
576	WDT-ISP-123145123 Fox 3	88	186		186
577	MMA1-Q1593 Pelicans Jaw Hybrid Solar Prj		186	6,956	186
578	R21-DS-122561656- MICHAEL STORES		186		186
579	R21-DS-123219019 MARIANI NUT CO - Buckey	3,286	186		186
580	R21-DS-122359708 SAVACA LLC		186	7,276	186
581	R21-DS-122530703 Stamoules Produce - met	1,438	186		186
582	R21-DS-122530575 Stamoules Produce - met		186		186
583	WDT-FT-123193210 Storage Star Rio Vista		186		186
584	R21-DS-123388479 COUNTY OF FRESNO_Juveni		186		186
585	MMA - NoQ Vasco Wind ISO51192	35,953	186		186
586	GIP (2017)--121694123-North Mad River Cl		186		186
587	WDT-ISP-122316848 Pittsburg RV and Boat		186	10,000	186
588	MMA1-Q1730 Austin Energy StorageISO40049	248	186		186
589	WDT-ISP-123387517 Redemeyer Road Solar	88	186		186
590	WDT-SR-122987074 Kings CSG B 1102-3039-W		186		186
591	MMA3-Q1109NorthCentralValleyProject51779	1,843	186		186
592	R21-DS-122460636 J & D FOOD SERVICE 2977		186		186
593	MMA1-PSTCOD-RussellCityEnergyCenter51193		186	29,480	186
594	Q1470 - Caballero Storage Project		186		186
595	WDT-ISP 123587936 TESORO COMMONS LLC	569	186		186
596	GIP (2017)-FT-SR-123085902-Fox 1		186		186
597	GIP (2017)-FT-SR-123141427-Fox 2		186		186
598	R21-DS 123018864 MORI SEIKI USA INC		186		186
599	MMA 1-Q1242Pluot Project ISO52008		186	3,866	186
600	MMA 2-Q1243 Pomegranat Project ISO52009		186	2,681	186
601	R21-DS 122888528 FARMERS WATER DISTRICT		186		186
602	R21-DS 122607062 NATURAL SELECTION FOODS		186		186
603	WDT-FT 123490340 2158 Stroing Expansion		186		186
604	R21-DS 122621167 J.D. HIESKELL HOLDINGS		186		186
605	MMA 2-Q900 Rio Bravo Solar1	3,648	186		186
606	MMA 2-Q972 Rio Bravo Solar2 ISO51454	4,022	186		186
607	MMA 1-Q654 Wildwood I ISO60197-C	851	186		186
608	MMA 1-Q901 Wildwood I ISO51236	855	186		186
609	WDT-ISP 123733970 Tasteful Selections Mi	4,392	186		186
610	WDT-FT 123775802 Wunpost Clean Power		186		186
611	MMA1Q1398 SandriniSol 2 Project ISO53071	6,086	186		186
612	WDT-FT 123842029 Piedmont Hillside Clean		186	40	186
613	WDT-FT 123855205 Chaboya Clean Power		186	264	186
614	WDT-ISP 123860277 North Belridge Clean P	7,258	186		186
615	MMA 1-Q1106 Fountain Wind ISO51770	331	186		186
616	Q946 - Northern Orchard Project:		186		186
617	R21-DS 123937474 Ranger Northbay LLC NE	682	186		186
618	R21-DS 124004714 Hanford Grain Company,		186		186
619	R21-DS 123996601 North Kern WSD Wright F		186	4,106	186
620	WDT-ISP 124026678 Dudley Ridge Solar Fac		186		186
621	R21-DS 123965650 Hat Creek Bioenergy - E	844	186	3,884	186
622	WDT-ISP 124065191 Fox 2	234	186		186
623	WDT-ISP 124064790 Fox 1	1,058	186		186
624	R21-DS 124083485 VALERO REFINING CO CALI	3,036	186		186
625	WDT-SR 3109-WD 2158 Stroing Expansion 12	41	186		186
626	R21-DS 124144183 North Kern WSD - Lerdo	1,417	186	5,287	186
627	R21-DS 124082822 Marin Sanitary Service	475	186		186
628	WDT-ISP 124245342 Oroville Dam Clean Pow	3,126	186	6,010	186
629	WDT-FAS 121694123 North Mad River Clean		186		186
630	MMA 1-Q1540 Plano Storage ISO40047	5,975	186		186
631	GIP (2017)-FT-SR-123775802-Wunpost Clean		186		186
632	R21-DS 123840982 CoRedwoods	1,341	186		186
633	R21-DS 123032010 NUSTAR ENERGY LP dba SH		186		186
634	PostCodMod1-Q22Montezumawind I ISO51193	19,974	186		186
635	R21-DS 122785546 BEST BUY CO INC. - DINU	3,855	186		186
636	Post Cod Mod - Columbia Solar ISO 50732	26,328	186		186
637	R21-DS 124202531 Imerys Minerals Califor	2,578	186		186
638	ModRev-GWFHenriettaPeakerPlantUnit 51195	23,414	186		186
639	MMA 2 -NoQ AlgonquinPowerSanger ISO51189	3,299	186		186
640	MMA1-Q1484Panoche/UnicornEnergyCent53175		186	3,388	186
641	WDT-ISP 124509963 Althea Avenue Solar Ph	2,475	186		186
642	MMA4-Q272AmericanKingsSolarProjec50212-C	19,341	186		186
643	MMA 4 - Q643W Mustang Solar ISO 50630	13,987	186	13,013	186
644	WDT_ISP 124510627 Althea Avenue Solar P	3,747	186		186
645	WDT_ISP 124570705 Little Gem Solar	4,617	186		186
646	WDT_ISP 124570778 Big Gem Solar		186	9,501	186
647	WDT_ISP 124570937 Serpentine Solar		186	8,582	186
648	WDT_ISP 1124570967 Tourmaline Solar		186	7,785	186
649	R21-DS 123102839 City of Chico RESBCT 31	1,264	186		186
650	R21-DS 122965777 - FETZER VINEYARDS		186		186
651	R21-DS 123670438-Lytton Rancheria (1640	2,634	186		186
652	R21-DS 124459552 Solano Community Colleg	2,769	186		186
653	WDT-ISP 124690960 Fox 4	5,397	186		186
654	Q1593 Pelicans Jaw Project.		186	108,115	186
655	WDT-ISP 124729515 King Kettle Clean II	4,393	186		186
656	WDT-ISP 124729056 King Kettle Clean I	13,516	186		186
657	MMA 1- Q1380 Heartland 2 ISO 53042	165	186		186
658	MMA 1- Q1379 Heartland 1 ISO 53048	83	186		186
659	MMA4-Q1443AngelaAngiola East LLCISO53205	1,607	186		186
660	MMA3-Q1136Westlands Almond SolarISO51828	3,122	186	2,037	186
661	R21-DS 124083512 - Kaiser Permanente - S		186		186
662	WDT- FT 124820632 AFTW Storage, LLC	1,169	186		186
663	R21-DS 123814705 -VULCAN MATERIALS CO	1,878	186		186
664	WDT-ISP 124826865 Gardenia 1	3,498	186		186
665	WDT-ISP 124827314 Cuyama	891	186		186
666	WDT-ISP 124543813 Berrenda Mesa Solar	4,742	186		186
667	R21-DS 122892093 SONOMA CUTRER	468	186		186
668	WDT-FT 124830125 CA PLD PGE RFO - SFO 6	1,911	186		186
669	WDT-FT 124830425 PLD SolarChoice Stktn 1	180	186		186
670	WDT-FT 124830607 PLD SolarChoice Stktn 4	180	186		186
671	WDT-FT 124830707 PLD SolarChoice Stktn 9	180	186		186
672	WDT-FT 124846126 CA PLD RFO -Lathrop 7	291	186	560	186
673	WDT-FT 124846199 CA PLD RFO Stockton 3	1,174	186		186
674	WDT-FT 124846153 CA PLD RFO Stockton 2	937	186		186
675	WDT-FT 124846108 CA PLD RFO Oakland 2	498	186		186
676	WDT-FT 124846155 CA PLD RFO Oak LC 1	869	186		186
677	WDT-FT 124846156 CA PLD RFO Stktn 11	1,132	186		186
678	WDT-FT 124846203 CA PLD RFO San Lean 9	1,322	186		186
679	WDT-FT 124846255 CA PLD RFO Stockton 10	1,216	186		186
680	WDT-FT 124846205 CA PLD RFO San Lean 10	1,699	186		186
681	WDT-CLUSTER 124849455 E & J Gallo Winery	1,505	186		186
682	124890581 Wonderful Orchards- 4220 EXPN	4,112	186		186
683	124897811 Wonderful Orchards- 4260 EXPN	383	186		186
684	124897989 Wonderful Orchards-Blankenship	2,736	186		186
685	124898078 WONDERFUL ORCHARDS CORCORAN	941	186		186
686	R21-DS 124396191 MACHADO DAIRY AND FARMI	959	186	10,000	186
687	124900838 Wonderful Orchards- Inland Emp	1,800	186		186
688	124901460 Wonderful Orchards-Lerdo East	1,555	186		186
689	124901774 Wonderful Orchards- Lerdo Mid	744	186		186
690	124903922 Wonderful Orchards- Rosedale	361	186		186
691	124904078 Wonderful Orchards- Scofield	13,306	186		186
692	124904178 Wonderful Orchards- Wingmaster	548	186		186
693	124903510 Wonderful Orchards- NKWSD	1,691	186		186
694	MMA 3- Q1097 Bear Canyon ISO 51783	265	186		186
695	MMA 2- Q1389 Redux Solar ISO 53064	720	186		186
696	R21-DS 124131970 Mariposa Bioenergy Faci		186		186
697	MMA 3- Q1378 Gonzaga wind Farm ISO 53004	3,072	186		186
698	MMA 2- Q1270 Corby ISO 51915	5,015	186		186
699	MMA 5- Q720_Q1002 Lassen Lodge Hydroele	1,439	186	2,070	186
700	MMA 1- Q1713 Bia BESS 1 ISO 53831	8,018	186	8,112	186
701	MMA5-Q954_Q1027LassenLodgeHydroelec51565	1,451	186		186
702	R21-DS 124311575 LOS GATOS TOMATO PRODUC	1,124	186		186
703	R21-DS 124344683 ELECTRIFY AMERICA LLC	719	186		186
704	WDT-ISP 124967843 Battle Creek Bottom Ro	3,713	186		186
705	WDT-SR 124820632 AFTW Storage 3197-WD	84	186		186
706	WDT-FAS 123103659 Tubbs Island Solar 1	336	186		186
707	WDT-ISP 114150951 Terry 1818-WD	5,135	186		186
708	MMA 4- Q1120 Chestnut Westside ISO 51818	2,472	186		186
709	MMA 2- NoQ ITR – Dollar Wond ISO 51179	2,307	186		186
710	WDT-ISP 124985587 Raven Road Solar	5,727	186		186
711	WDT-ISP 124570644 Hartley LLC	7,254	186	62,000	186
712	R21-DS 123863079 Humboldt Bay Municipal	1,591	186	10,000	186
713	R21-DS 124528789 FIVE CROWNS TRACY HOLDI		186	10,000	186
714	WDT-ISP 125263388 Shafter	3,667	186	10,000	186
715	MMA4-Q1143LakeAlpaughBatteryStorage51720	1,237	186		186
716	PTA1-Q1116UltrapowerChineseStation51707	684	186		186
717	GIP (2017)-FT-SR-124846108-CA - PLD RFO	1,644	186	5,000	186
718	GIP (2017)-FT-SR-124846156-CA - PLD RFO		186	2,500	186
719	GIP (2017)-FT-SR-124846153-CA - PLD RFO	1,255	186	2,500	186
720	GIP (2017)-FT-SR-124846255-CA - PLD RFO		186	2,500	186
721	GIP (2017)-FT-SR-124846199-CA - PLD RFO		186	2,500	186
722	WDT-FT 125027131 Westridge	1,612	186	1,076	186
723	WDT-FT 125031830 Emeline	3,049	186	1,000	186
724	WDT-FT 125031911 Ocean	2,377	186	1,000	186
725	R21-DS 124519178-FREI BROTHERS	3,836	186	10,000	186
726	R21-DS 125025354 Wonderful Orchards-3461		186	10,000	186
727	WDT-ISP 125304280 Foster Clean Power B	1,950	186	10,000	186
728	R21-DS 124358055 SAN LUIS OBISPO FC&WCD		186	10,000	186
729	WDT-ISP 125304474 Ridge Drive Solar	3,308	186	10,000	186
730	WDT-ISP 125324034 North Mad River Clean	2,181	186	10,000	186
731	WDT-FT 125263721 Flynn	2,396	186	1,000	186
732	MMA 2- Q1495 Chalan Solar ISO 53194	5,918	186		186
733	LOS- Q1540_Q1027 Plano Storage ISO 40047	62,121	186		186
734	LOS-Q1139 Westlands Solar Blue ISO 51815	1,017	186		186
735	MMA4-Q1139 Westlands Solar Blue ISO51815	10,423	186		186
736	GIP (2017)-FT-SR-124846205-CA - PLD RFO	1,774	186	2,500	186
737	WDT-ISP 125422392 San Joaquin DIDF	4,227	186	10,000	186
738	WDT-SR 3204-WD PLD Solar Choice STKN 1	1,529	186	2,500	186
739	WDT-SR 3205-WD PLD Solar Choice STKN 4	1,710	186	2,500	186
740	WDT-SR 3206-WD PLD Solar Choice STKN 9	626	186	2,500	186
741	GIP (2017)-FT-SR-124846203-CA - PLD RFO	1,840	186	2,500	186
742	GIP (2017)-FT-SR-124846126-CA - PLD RFO	2,137	186	2,500	186
743	GIP (2017)-FT-SR-124830425-PLD - SolarCh		186	2,500	186
744	WDT-FT 124948365 EcoBlock-Microgird WDT	542	186	1,000	186
745	WDT-FT 125392852 Roy Wilson Yard	1,263	186	1,000	186
746	GIP (2017)-ISP-EIT-124820632-AFTW Storag	529	186	10,000	186
747	GIP (2017)-FT-SR-124846155-CA - PLD RFO	1,349	186	2,500	186
748	R21-DS 125445739 Niagara Bottling LLC	1,119	186	56,000	186
749	WDT-FT 125447454 Stroud DIDF		186	1,000	186
750	WDT-ISP 125440315 American Power Company	2,483	186	10,000	186
751	WDT-ISP 125427289 Hillcrest Digester	959	186	10,000	186
752	WDT-FT 125485408 PLD -PGE 23 CSGT-Stockt	383	186	1,000	186
753	GIP (2017)-FT-SR-124830125-CA - PLD PGE	1,869	186	2,500	186
754	WDT-FT 125496857 Prologis(EBCE Tracy 8)-	604	186	1,000	186
755	WDT-FT 125510763 Prologis(EBCE OAKLAND 1	784	186	1,000	186
756	WDT-FT 125512453 EBCE -PLD - San Lean 10	1,044	186	1,000	186
757	WDT-FT 125511972 EBCE -PLD - Hayward CC	397	186	1,000	186
758	WDT-FT 125504866 EBCE - PLD - Newark 11	309	186	1,000	186
759	R21-DS 125453459 Kings CSG 1	1,288	186	60,000	186
760	R21-DS 125521393 Godinho Dairy	972	186	10,000	186
761	R21-DS 125545494 Tracy Lane DG Solar	1,067	186	10,000	186
762	MMA3-Q1454HummingbirdEnergyStorage53156	799	186		186
763	R21-DS 124202904 FIRESTONE WALKER INC		186	10,000	186
764	R21-DS 125567905 Valley Ag	383	186	60,000	186
765	R21-DS 125563457 Vignolo Farms	383	186	60,000	186
766	R21-DS 125564279 Schuh		186	60,000	186
767	R21-DS 125413937 Blue Mines 1	684	186	60,000	186
768	R21-DS 125563076 Blue Mines 2	588	186	60,000	186
769	GIP (2017)-FT-SR-125027131-Westridge	1,927	186	2,500	186
770	WDT-Cluster 15 FCDS 3241-WD Lakeport Sto	88	186	50,000	186
771	WDT-DGSP 125618544 Stroud DIDF	88	186	88	186
772	R21-DS 125509658 SYAR INDUSTRIES INC - N	360	186	10,000	186
773	WDT-CLUSTER 15 FCDS 124827314 Cuyama	413	186	50,000	186
774	R21-DS 125523039 CA4	383	186	10,000	186
775	R21-DS 125524663 Antonio Brasil Dairy	972	186	10,000	186
776	WDT-125566523 CA-PLD-SFO 33-SanFran	1,383	186	1,000	186
777	WDT-ISP 125637948 Irvington Energy Stora	834	186	65,000	186
778	WDT-ISP 125636015 Hickory Energy Storage	834	186	65,000	186
779	R21-DS 125608039 Davis Diversified Farms	2,312	186	60,000	186
780	R21-DS 125608943 Melcat 1	580	186	60,000	186
781	GIP (2017)-FT-SR-125031911-Ocean	1,055	186	2,500	186
782	GIP (2017)-FT-SR-125031830-Emeline	1,099	186	2,500	186
783	GIP (2017)-FT-SR-125263721-Flynn	215	186	133	186
784	GIP (2017)-FT-SR-125392852-Roy Wilson Ya	1,364	186	2,500	186
785	R21-DS 125576414 Eden Medical Center A S		186	10,000	186
786	R21-DS 3238-RD Gateway Solar RV & Boat S	3,453	186	10,000	186
787	WDT-FT 125564478 Jersey Avenue Solar	840	186	1,000	186
788	WDT-ISP 125562165 Pleasant Valley Road S	759	186	10,000	186
789	WDT-ISP 125435475 PP-Lake Storage	788	186	64,000	186
790	WDT-ISP 125437298 PP - SLO Storage	353	186	63,000	186
791	WDT-ISP 125437523 PP- Mendocino Storage	744	186	64,000	186
792	WDT-ISP 125471284 PP- Tuolumne Storage	706	186	63,000	186
793	WDT-ISP 125481728 PP- Calaveras	2,971	186	64,000	186
794	WDT-ISP 125589983 Baker Road Solar	1,009	186	1,009	186
795	WDT-ISP 125589790 River Crest Drive Sola	817	186	10,000	186
796	R21-DS 125578562 Roberts	767	186	60,000	186
797	MMA 4- Q1244 Proxima Solar ISO 51980	380	186		186
798	MMA1-Q1391 SonrisaSolarProject ISO 53017	6,452	186		186
799	MMA3-NoQMalagaPowerHybrid(96MWBESS51182	1,193	186		186
800	MMA2-NoQNorthOrchard/Northern51400 51918	973	186		186
801	MMA 2- Q1444 Sundown ISO 53234	1,320	186		186
802	R21-DS 125579496 RPAC LLC - NEMExp	767	186	10,000	186
803	R21-DS 125579476 PARREIRA ALMOND PROCESS		186	10,000	186
804	WDT-DGSP Energy Only 125646257 Blackwell	288	186	10,000	186
805	WDT-SIS 124846199 - 3213-WD Stockton 3	603	186	10,000	186
806	WDT-SIS 124846255 - 3208-WD Stockton 10	559	186	10,000	186
807	WDT-SIS 124846156 - 3210-WD Stockton 11	559	186	10,000	186
808	R21-DS 125659990 Superior Almond Hulling		186	10,000	186
809	MMA 4 - Q1097 Bear Canyon ISO 51783	1,266	186		186
810	MMA1-Q1367WestFordFlatEnergyStorage53078	3,851	186		186
811	WDT-Cluster 125720495 Kern ES2	611	186	58,000	186
812	WDT-Cluster 125709894 Kern ES1	611	186	58,000	186
813	WDT-DGSP 125717891 Big Gem	580	186	10,000	186
814	WDT-DGSP 125650772 Easy Rider	455	186	10,000	186
815	WDT-DGSP 125725265 Water Solar	580	186	10,000	186
816	GIP (2017)-ISP-EIT-124830607-PLD - Sola		186	10,000	186
817	R21-DS 124743441 LINEAGE LOGISTICS ICM L		186	10,000	186
818	MMA 3- Q1260 Northern Orchard 3 Project	799	186		186
819	WDT-Cluster 125738115 Lakeside BioGen Ex	662	186	53,000	186
820	WDT-Cluster 125749128 Atardece Storage	176	186	150,000	186
821	WDT-Cluster 125664009 Madrugada Solar	176	186	110,000	186
822	WDT-Cluster 125729142 San Joaquin ES1	353	186	68,000	186
823	WDT-DGSP 125756199 Suzie Almonds	308	186	10,000	186
824	R21-DS 125670657 GOOGLE LLC - NEMPS	383	186	10,000	186
825	R21-DS 125716906 Unti	1,917	186	60,000	186
826	GIP (2017)-FT-SR-125510763-Prologis(EBCE	309	186	2,500	186
827	GIP (2017)-FT-SR-125512453-EBCE - PLD -	1,426	186	2,500	186
828	R21-DS 125718323 Rianda Family Partnersh		186	10,000	186
829	WDT-ISP 125760540 Twin Pine Circle Solar	1,379	186	10,000	186
830	WDT-ISP 125653758 Golden Poppy Storage	1,998	186	70,000	186
831	WDT-ISP 125701286 Bald Rock Energy	2,359	186	70,000	186
832	WDT-ISP 125650660 Oro Energy Center	661	186	70,000	186
833	GIP (2017)-FT-SR-124948365-EcoBlock-Micr	1,534	186	2,500	186
834	R21-DS 125770956 Melcat 2	271	186	60,000	186
835	R21-DS 125760860 Vignolo Burbank	220	186	60,000	186
836	R21-DS 125771313 Anderson Coalinga	220	186	60,000	186
837	R21-DS 125771989 Vignolo Dresser	359	186	60,000	186
838	R21-DS 125772243 Vignolo Merced	359	186	60,000	186
839	R21-DS 125772653 Hundal Merced	353	186	60,000	186
840	R21-DS 125735569 INTERNATIONAL PAPER COM	192	186	10,000	186
841	R21-DS 125735770 INTERNATIONAL PAPER COM	220	186	82	186
842	R21-DS 125716239 INTERNATIONAL PAPER COM	456	186	10,000	186
843	R21-DS 125781634 Treasury Wine Estates A		186	10,000	186
844	MMA4-Q1350PaulsellSolarEnergyCenter53069	903	186		186
845	R21-DS 125785493 Treasury Wine Estates A		186	10,000	186
846	R21-DS 125785540 Diageo Chateau and Esta		186	10,000	186
847	R21-DS 125742498 Niagara Bottlink LLC	507	186	370	186
848	WDT-Cluster 125937916 Wagon Wheel Solar	485	186	72,000	186
849	WDT-ISP 125860460 BPP CA Fresno BESS III	484	186	10,000	186
850	WDT-ISP 125851254 BPP CA Fresno BESS I	265	186	10,000	186
851	R21-DS 125220105-JOHN LAYOUS & JOE LANE	205	186	10,000	186
852	R21-DS 125923536 Harbor Distributing, LL		186	10,000	186
853	GIP (2017)-FT-SR-125566523-CA - PLD - SF	573	186	2,500	186
854	R21-DS 125872413 GODINHO DAIRY - NEMExp-		186	10,000	186
855	R21-DS 124493787 GOLDEN STATE VINTNERS		186	10,000	186
856	R21-DS 125752539 VITRO FLAT GLASS LLC		186	58,000	186
857	R21-DS 125899760 BAKERSFIELD RENEWABLE F	1,978	186	66,000	186
858	R21-DS 125913478 CARDINAL CT COMPANY - N		186	10,000	186
859	MMA 1- NoQ Manganese BESS ISO 51199	1,829	186		186
860	MMA 1- NoQ Iron BESS ISO 51198	3,157	186		186
861	GIP (2017)-FT-SR-125496857-Prologis(EBCE	175	186	2,500	186
862	R21-DS 125925083 DOLE FRESH VEGETABLES I		186	10,000	186
863	R21-DS 126001610 Lupine DG Solar	176	186	10,000	186
864	WDT-FT 125946792 Copperopolis Road Solar	824	186	1,000	186
865	GIP (2017)-FT-SR-125485408-PLD - 23 CSGT		186	2,500	186
866	MMA 5- Q356 Cuyama Solar ISO 50297-C	220	186		186
867	R21-DS 126131996 Sierra Road DG Solar		186	10,000	186
868	WDT-ISP 126162379 Flying Goose Deuce	196	186	10,000	186
869	WDT-ISP 126135369 Copperopolis Rd Solar	196	186	10,000	186
870	MMA 1- Q54 Magnesium BESS ISO 50083	88	186		186
871	WDT-ISP 126169753 Thorntree Drive Solar	221	186	10,000	186
872	WDT-ISP 126166660 River Crest Drive Sola	88	186	10,000	186
873	WDT-ISP 126165871 Jersey Avenue Solar Ph		186	10,000	186
874	WDT-ISP 126165301 La Porte Road Solar Ph	44	186	10,000	186
875	WDT-ISP 126155599 Baker Road Solar Phase	88	186	10,000	186
876	WDT-ISP 126155165 Pleasant Valley Road S		186	10,000	186
877	WDT-CS 15FCDS 3086-WD Redemeyer Road Sol	44	186	50,000	186
878	WDT-FT 126073932 Noria Solar Farm 1		186	1,000	186
879	R21-DS 126206827 ERIKSSON LLC - NEMA		186	10,000	186
880	GIP (2017)-FT-SR-125564478-Jersey Avenue		186	2,500	186
881	MMA 2-Q1463 Solano Renewables 1 ISO53151	198	186		186
882	R21-DS 126307220 ENGEMAN SVRC GREEN ENER	169	186	10,000	186
39	Total	897,658		3,385,515
40	Grand Total	3,253,132		4,142,141

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	CORE BROKERAGE FEE	1,201,847	1,315,462	400	1,097,321	983,706
2	CORE BROKERAGE FEE Amortization : < 12 MONTHS
3	PURCHASED GAS BALANCING ACCOUNT	57,517,583	649,259,947	400	532,893,411	58,848,953
4	PURCHASED GAS BALANCING ACCOUNT Amortization : < 12 MONTHS
5	BCA CHARGE ACCOUNT	8,026,485	1,137,209	400	4,177,324	11,066,600
6	BCA CHARGE ACCOUNT Amortization : < 12 MONTHS
7	CA ALTERNATE RATES FOR ENERGY PROGRAM-ELECTRIC	145,621,487	171,047,691	400	236,947,685	79,721,493
8	CA ALTERNATE RATES FOR ENERGY PROGRAM-ELECTRIC Amortization : < 12 MONTHS
9	CA ALTERNATE RATES FOR ENERGY PROGRAM-GAS	67,143,074	31,578,192	400	49,717,975	49,003,291
10	CA ALTERNATE RATES FOR ENERGY PROGRAM-GAS Amortization : < 12 MONTHS
11	ELECTRIC HAZARDOUS SUBSTANCE BALANCING ACCOUNT	43,720,403	8,880,243	182	8,337,337	44,263,309
12	ELECTRIC HAZARDOUS SUBSTANCE BALANCING ACCOUNT Amortization : < 12 MONTHS
13	GAS HAZARDOUS SUBSTANCE BALANCING ACCOUNT	102,014,272	20,720,568	182	19,453,785	103,281,055
14	GAS HAZARDOUS SUBSTANCE BALANCING ACCOUNT Amortization : < 12 MONTHS
15	CORE FIXED COST GAS BALANCING ACCOUNT	522,461,233	758,015,815	400	632,833,573	397,278,991
16	CORE FIXED COST GAS BALANCING ACCOUNT Amortization : < 12 MONTHS
17	TRANSITION COST - NONCORE BALANCING ACCOUNT	9,480,491	53,100,868	400	53,491,617	9,871,240
18	TRANSITION COST - NONCORE BALANCING ACCOUNT Amortization : < 12 MONTHS
19	CORE PIPELINE DEMAND CHARGE ACCOUNT	20,407,904	137,992,333	400	124,001,495	6,417,066
20	CORE PIPELINE DEMAND CHARGE ACCOUNT Amortization : < 12 MONTHS
21	CEE INCENTIVE ELECTRIC BALANCING ACCOUNT	549,688		400	171,276	378,412
22	CEE INCENTIVE ELECTRIC BALANCING ACCOUNT Amortization : < 12 MONTHS
23	GAS CORE FIRM STORAGE ACCOUNT	6,690,775	32,971,515	400	22,991,602	3,289,138
24	GAS CORE FIRM STORAGE ACCOUNT Amortization : < 12 MONTHS
25	ENERGY RESOURCE RECOVERY ACCOUNT	290,028,322	609,034,606	400	793,653,262	105,409,666
26	ENERGY RESOURCE RECOVERY ACCOUNT Amortization : < 12 MONTHS
27	ENERGY RECOVERY BONDS BALANCING ACCOUNT	47,346,357	14,177,806	400	616,921	33,785,472
28	ENERGY RECOVERY BONDS BALANCING ACCOUNT Amortization : < 12 MONTHS
29	ELECTRIC PRICE RISK MANAGEMENT - REG ASSET CURRENT	59,705,255	61,030,564	555	59,705,255	61,030,564
30	ELECTRIC PRICE RISK MANAGEMENT - REG ASSET CURRENT Amortization : NO STATED
31	ENVIRONMENTAL COMPLIANCE NON-HSM	18,493,036	344,259	228	1,125,271	17,712,024
32	ENVIRONMENTAL COMPLIANCE NON-HSM Amortization : 32 YEARS
33	ENVIRONMENTAL COMPLIANCE	261,569,118	41,611,873	182	10,366,211	292,814,780
34	ENVIRONMENTAL COMPLIANCE Amortization : 32 YEARS
35	DISTRIBUTION REVENUE ADJUSTMENT MECHANISM	1,002,218,642	1,829,317,302	400	1,541,826,289	1,289,709,655
36	DISTRIBUTION REVENUE ADJUSTMENT MECHANISM Amortization : < 12 MONTHS
37	DEFERRED DEBIT - GAS RESERVES (CONTRA BALANCING AC	134,465,215	406,857	400	9,406,592	143,464,950
38	DEFERRED DEBIT - GAS RESERVES (CONTRA BALANCING AC Amortization : < 12 MONTHS
39	TRANSMISSION REVENUE BALANCING ACCOUNT	210,051,450	88,790,922	400	99,544,744	220,805,272
40	TRANSMISSION REVENUE BALANCING ACCOUNT Amortization : < 12 MONTHS
41	RELIABILITY SERVICES BALANCING ACCOUNT	11,125,811	4,527,123	400	8,094,556	7,558,378
42	RELIABILITY SERVICES BALANCING ACCOUNT Amortization : < 12 MONTHS
43	ELECTRIC BALANCING ACCOUNT RESERVE ACCOUNT	3,750,500,067	28,070,697	400	33,871,199	3,756,300,569
44	ELECTRIC BALANCING ACCOUNT RESERVE ACCOUNT Amortization : < 12 MONTHS
45	GAS PRICE RISK MANAGEMENT - REG ASSET CURRENT	3,756,664	7,554,468	244	3,756,664	7,554,468
46	GAS PRICE RISK MANAGEMENT - REG ASSET CURRENT Amortization : NO STATED
47	TRANSMISSION ACCESS CHARGE BALANCING ACCOUNT	104,893,974	103,358,970	400	98,357,106	109,895,838
48	TRANSMISSION ACCESS CHARGE BALANCING ACCOUNT Amortization : < 12 MONTHS
49	PUBLIC PURPOSE PROGRAMS REVENUE ADJUSTMENT MECH.	123,938,448	68,225,448	400	43,139,810	98,852,810
50	PUBLIC PURPOSE PROGRAMS REVENUE ADJUSTMENT MECH. Amortization : < 12 MONTHS
51	MODIFIED TRANSITION COST BALANCING ACCOUNT	56,266,789	44,262,986	400	27,656,910	72,872,865
52	MODIFIED TRANSITION COST BALANCING ACCOUNT Amortization : < 12 MONTHS
53	END-USE CUSTOMER REFUND ADJUSTMENT	900,569	996	400	16,980	916,553
54	END-USE CUSTOMER REFUND ADJUSTMENT Amortization : < 12 MONTHS
55	CATASTROPHIC EVENT MEMORANDUM ACCOUNT	161,058,778	243,461,110	182	84,160,915	320,358,973
56	CATASTROPHIC EVENT MEMORANDUM ACCOUNT Amortization : < 12 MONTHS
57	GAS PUBLIC PURPOSE PROGRAM SURCHARGE MEMO ACCT	2,543,365	139,332,112	186	138,193,379	3,682,098
58	GAS PUBLIC PURPOSE PROGRAM SURCHARGE MEMO ACCT Amortization : < 12 MONTHS
59	PROCUREMENT ENERGY EFFICIENCY REV. ADJ. MECHANISM	74,465,244	66,659,257	400	67,286,447	73,838,054
60	PROCUREMENT ENERGY EFFICIENCY REV. ADJ. MECHANISM Amortization : < 12 MONTHS
61	FAMILY ELECTRIC RATE ASSISTANCE BALANCING ACCT	4,645,802	4,546,255	400		9,192,057
62	FAMILY ELECTRIC RATE ASSISTANCE BALANCING ACCT Amortization : < 12 MONTHS
63	NEGATIVE ONGOING COMPETITION TRANSITION CHRG BA	3,411,358,565	18,960,577	182		3,430,319,142
64	NEGATIVE ONGOING COMPETITION TRANSITION CHRG BA Amortization : < 12 MONTHS
65	LAND CONSERV. PLAN ENV. REMEDIATION MEMO ACCT.	9,064	331,777	182		340,841
66	LAND CONSERV. PLAN ENV. REMEDIATION MEMO ACCT. Amortization : < 12 MONTHS
67	CA SOLAR INITIATIVE THERMAL PROGRAM MEMO ACCOUNT	4,581,278	1,330,056	400	956,432	4,954,902
68	CA SOLAR INITIATIVE THERMAL PROGRAM MEMO ACCOUNT Amortization : < 12 MONTHS
69	SMART GRID MEMORANDUM ACCOUNT		731,356	182	16,828	714,528
70	SMART GRID MEMORANDUM ACCOUNT Amortization : < 12 MONTHS
71	GAS HAZARDOUS SUBSTANCE REGULATORY ASSET	610,327,939	97,094,369	182	24,187,826	683,234,482
72	GAS HAZARDOUS SUBSTANCE REGULATORY ASSET Amortization : 32 YEARS
73	GAS NON-HAZARDOUS SUBSTANCE REGULATORY ASSET	142,669,803	3,581,719	228	373,054	145,878,468
74	GAS NON-HAZARDOUS SUBSTANCE REGULATORY ASSET Amortization : 32 YEARS
75	NON CURRENT HSM BA ELEC	8,706,790	20,907,567	182	10,366,291	19,248,066
76	NON CURRENT HSM BA ELEC Amortization : > 12 MONTHS
77	NON CURRENT HSM BA GAS	20,315,845	48,784,324	182	24,188,013	44,912,156
78	NON CURRENT HSM BA GAS Amortization : > 12 MONTHS
79	FIRE HAZARD PREVENTION MEMO ACCT - NON CURRENT	117,758,793	1,321,753	182	33,437,788	85,642,758
80	FIRE HAZARD PREVENTION MEMO ACCT - NON CURRENT Amortization : < 12 MONTHS
81	ELECTRIC PRICE RISK MANAGEMENT - REG ASSET NONCURRENT	158,832,919	164,446,267	555	158,832,920	164,446,266
82	ELECTRIC PRICE RISK MANAGEMENT - REG ASSET NONCURRENT Amortization : NO STATED
83	FASB 109 REGULATORY ASSET	8,399,008,918	210,445,957	282	41,861,025	8,567,593,850
84	FASB 109 REGULATORY ASSET Amortization : 1-45 YEARS
85	GAS TRANSMISSION AND STORAGE REVENUE SHARING MECH.	19,142,841	113,482,370	400	146,096,935	51,757,406
86	GAS TRANSMISSION AND STORAGE REVENUE SHARING MECH. Amortization : < 12 MONTHS
87	NUCLEAR DECOMMISSIONING ADJUSTMENT MECHANISM	2,953,065	31,882,370	400	23,976,492	4,952,813
88	NUCLEAR DECOMMISSIONING ADJUSTMENT MECHANISM Amortization : 2 YEARS
89	DEPARTMENT OF ENERGY LITIGATION BALANCING ACCOUNT	21,926	44,172	182	10,135,279	10,113,033
90	DEPARTMENT OF ENERGY LITIGATION BALANCING ACCOUNT Amortization : > 12 MONTHS
91	DEMAND RESPONSE EXPENDITURES BALANCING ACCOUNT (DREBA)	4,672,160	6,172,638	400	9,877,758	8,377,280
92	DEMAND RESPONSE EXPENDITURES BALANCING ACCOUNT (DREBA) Amortization : < 12 MONTHS
93	AMCDOP-COST ADUST MECHANISM-OTHER PROCEEDINGS	25,571,790	136,131,589	400	99,304,336	62,399,043
94	AMCDOP-COST ADUST MECHANISM-OTHER PROCEEDINGS Amortization : <12 MONTHS
95	NEW SYSTEM GENERATION BA	49,738,316	112,594,727	400	89,609,936	72,723,107
96	NEW SYSTEM GENERATION BA Amortization : < 12 MONTHS
97	ELECTRIC PROGRAM INVESTMENT CHARGE	6,000,931	23,519,771	400	20,011,035	9,509,667
98	ELECTRIC PROGRAM INVESTMENT CHARGE Amortization : < 12 MONTHS
99	GREENHOUSE GAS EXPENSE MEMO ACCOUNT	763,069	116,289	400	8,563	655,343
100	GREENHOUSE GAS EXPENSE MEMO ACCOUNT Amortization : NO STATED
101	GAS PROGRAM BALANCING ACCOUNT	80,807,644	88,661,615	400	80,920,413	73,066,442
102	GAS PROGRAM BALANCING ACCOUNT Amortization : < 12 MONTHS
103	GAS TRANSMISSION & STORAGE MEMO ACCOUNT (GTSMA)	61,403,158	22,799,594	400	22,099,221	62,103,531
104	GAS TRANSMISSION & STORAGE MEMO ACCOUNT (GTSMA) Amortization : < 12 MONTHS
105	GREEN TARIFF SHARED RENEWABLES MEMORANDUM ACCOUNT	6,413,402	157,729	400	190,886	6,380,245
106	GREEN TARIFF SHARED RENEWABLES MEMORANDUM ACCOUNT Amortization : < 12 MONTHS
107	RESIDENTIAL RATE REFORM MEMORANDUM ACCOUNT (RRRMA)	5,066,339	39,724,922	400	42,224,663	7,566,080
108	RESIDENTIAL RATE REFORM MEMORANDUM ACCOUNT (RRRMA) Amortization : > 12 MONTHS
109	GPBA - GHG OPERATIONAL COSTS SUBACCOUNT	6,844,742	10,056,973	400	2,455,986	14,445,729
110	GPBA - GHG OPERATIONAL COSTS SUBACCOUNT Amortization : <12 MONTHS
111	GREEN TARIFF SHARED RENEWABLES BALANCING ACCOUNT	3,725,465	17,545,663	400	16,789,147	4,481,981
112	GREEN TARIFF SHARED RENEWABLES BALANCING ACCOUNT Amortization : <12 MONTHS
113	GTSMA - NONCURRENT	129,839,291	9,542,643	400	15,005,939	124,375,995
114	GTSMA - NONCURRENT Amortization : > 12 MONTHS
115	AVOIDED COST CALC UPDATE MEMO ACCOUNT	607,786	7,547	400		615,333
116	AVOIDED COST CALC UPDATE MEMO ACCOUNT Amortization : > 12 MONTHS
117	DISTRIBUTED RESOURCES PLAN MEMORANDUM ACCT	17,487,523	1,418,899	400	1,031	18,905,391
118	DISTRIBUTED RESOURCES PLAN MEMORANDUM ACCT Amortization : > 12 MONTHS
119	TRANSMISSION INTEGRITY MGMT BALACCT-CURR	8,219,261		400	8,000,752	16,220,013
120	TRANSMISSION INTEGRITY MGMT BALACCT-CURR Amortization : < 12 MONTHS
121	BA - PORTFOLIO ALLOCATION BAL ACCOUNT	192,498,750	3,125,080,712	400	2,595,040,080	722,539,382
122	BA - PORTFOLIO ALLOCATION BAL ACCOUNT Amortization : < 12 MONTHS
123	HLBA - CURRENT	5,202,459		182	64,603	5,267,062
124	HLBA - CURRENT Amortization : < 12 MONTHS
125	NRCRBA - CURRENT	2,733,415	33,943	182		2,767,358
126	NRCRBA - CURRENT Amortization : < 12 MONTHS
127	FIRE RISK MITIGATION MEMO ACCT	25,179,911	851,372	182	376,358	25,654,925
128	FIRE RISK MITIGATION MEMO ACCT Amortization : < 12 MONTHS
129	CALI CONSUMER PRIVACY ACT MEMO ACCT-ELEC	24,033,547	1,202,421	182	5,195,770	20,040,198
130	CALI CONSUMER PRIVACY ACT MEMO ACCT-ELEC Amortization : > 12 MONTHS
131	CALI CONSUMER PRIVACY ACT MEMO ACCT-GAS	19,663,809	988,004	182	2,272,193	18,379,620
132	CALI CONSUMER PRIVACY ACT MEMO ACCT-GAS Amortization : > 12 MONTHS
133	Gas Storage Balancing Account	7,150,330	7,146,610	400	4,204,930	10,092,010
134	Gas Storage Balancing Account Amortization : > 12 MONTHS
135	Measurement and Control Ovr-Pressure Prot	5,269,371	655,367	400	173,539	5,751,199
136	Measurement and Control Ovr-Pressure Prot Amortization : > 12 MONTHS
137	In-Line Inspection mem account	266,670,858	15,854,938	400	22,788	282,503,008
138	In-Line Inspection mem account Amortization : > 12 MONTHS
139	Gas Statues Rules Reg Memo Acct	40,958,090	3,423,729	400		44,381,819
140	Gas Statues Rules Reg Memo Acct Amortization : > 12 MONTHS
141	Internal Corrosion Direct Assessment Memo Acct	16,012,226	333,479	400		16,345,705
142	Internal Corrosion Direct Assessment Memo Acct Amortization : > 12 MONTHS
143	Integrated Resource Planning Cost Memorandum Account	355,635	227,438	400		583,073
144	Integrated Resource Planning Cost Memorandum Account Amortization : < 12 months
145	Wildfire Mitigation Bal Acct - Electric Curr	5,530,032	119,412,303	400	28,799,603	96,142,732
146	Wildfire Mitigation Bal Acct - Electric Curr Amortization : < 12 months
147	Wildfire Mitigation Bal Acct - Gas Curr	20,313,326	4,580,386	400	7,190,267	22,923,207
148	Wildfire Mitigation Bal Acct - Gas Curr Amortization : < 12 months
149	Microgrid Memorandum Account - Noncurrent	226,371,396	5,136,967	400	77,290,578	154,217,785
150	Microgrid Memorandum Account - Noncurrent Amortization : > 12 months
151	Transmission Rev Req Reclass Memo Acct	290,303,747	17,290,317	407	11,133,423	296,460,641
152	Transmission Rev Req Reclass Memo Acct Amortization : > 12 months
153	RUBA-E Current	59,208,750	82,530,834	400		141,739,584
154	RUBA-E Current Amortization : < 12 months
155	RUBA-G Current	44,614,211	41,636,559	400		86,250,770
156	RUBA-G Current Amortization : < 12 months			—
157	LINE 407 MEMO ACCT NC	1,924,447	139,986	182	477	2,063,956
158	LINE 407 MEMO ACCT NC Amortization : >12 MONTHS
159	CRTICAL DOCS PROGRAM MEMO ACCT NC	18,779,936	299,495	182		19,079,431
160	CRTICAL DOCS PROGRAM MEMO ACCT NC Amortization : >12 MONTHS
161	TRANSMISSION INTEGRITY MGMT BAL ACCT	44,725,990	59,763,053	182	47,677,770	32,640,707
162	TRANSMISSION INTEGRITY MGMT BAL ACCT Amortization : >12 MONTHS
163	TRANSMISSION INTEGRITY MGMT MEMO ACCT	620,064	30,612	182		650,676
164	TRANSMISSION INTEGRITY MGMT MEMO ACCT Amortization : >12 MONTHS
165	INTEGRATED DISTRIBUTION ENERGY RESOURCES ACCOUNT	3,022,617	322,936	400		3,345,553
166	INTEGRATED DISTRIBUTION ENERGY RESOURCES ACCOUNT Amortization : > 12 MONTHS
167	CATASTROPHIC EVENT MEMORANDUM ACCOUNT - GAS	9,078,926	10,220,317	400	3,029,566	16,269,677
168	CATASTROPHIC EVENT MEMORANDUM ACCOUNT - GAS Amortization : < 12 MONTHS
169	TREE MORTAILITY NON-BYPASSABLE CHARGE BAL ACCT	21,800,234	15,582,079	400	7,355,016	13,573,171
170	TREE MORTAILITY NON-BYPASSABLE CHARGE BAL ACCT Amortization : < 12 MONTHS
171	Wildfire Mitigation Plan Memo Acct	627,347,335	156,997,503	182	109,007,878	675,336,960
172	Wildfire Mitigation Plan Memo Acct Amortization : < 12 MONTHS
173	CA Distri Generation Statistics Website Memo Acct	190,644	2,367	501		193,011
174	CA Distri Generation Statistics Website Memo Acct Amortization : > 12 months
175	Dairy Biomethane Pilot Memo Account	299,236	40,857	400	21,628	318,465
176	Dairy Biomethane Pilot Memo Account Amortization : > 12 months
177	Regional Plan Memorandum Account - Electric	8,048,916	1,797,308	400	201,122	9,645,102
178	Regional Plan Memorandum Account - Electric Amortization : > 12 months
179	Regional Plan Memorandum Account - Gas	3,817,391	852,619	400		4,670,010
180	Regional Plan Memorandum Account - Gas Amortization : > 12 months
181	General Office Sale BA-E Current	24,703,898		400	24,561,010	49,264,908
182	General Office Sale BA-E Current Amortization : < 12 MONTHS
183	General Office Sale BA-G Current	12,920,282		400	12,857,993	25,778,275
184	General Office Sale BA-G Current Amortization : < 12 MONTHS
185	Voluntary Allocation & Market Offer Memo Acct	757,184	184,134	400		941,318
186	Voluntary Allocation & Market Offer Memo Acct Amortization : < 12 MONTHS
187	Incremental RA Procurement Memo Account		286,697	400	286,697
188	Incremental RA Procurement Memo Account Amortization : < 12 MONTHS			—
189	BA - Biomethane Procurement Program-Admin		122,447	400		122,447
190	BA - Biomethane Procurement Program-Admin Amortization : < 12 MONTHS
191	MISCELLANEOUS GAS REG ASSET - CURRENT	49,287,562	48,645,117	(a) VARIOUS	55,771,377	42,161,302
192	MISCELLANEOUS GAS REG ASSET - CURRENT Amortization : < 12 MONTHS
193	MISCELLANEOUS ELECTRIC REG ASSET - CURRENT	85,608,799	98,153,963	(b) VARIOUS	90,553,149	93,209,613
194	MISCELLANEOUS ELECTRIC REG ASSET - CURRENT Amortization : < 12 MONTHS
195	ACCUM AMORT - URG PLANT REG ASSET	3,520,575		405		3,520,575
196	ACCUM AMORT - URG PLANT REG ASSET Amortization : < 12 MONTHS
197	MOBILE HOME PARK BA ELECTRIC NC	28,002,320	698,650	597	2,429,651	26,271,319
198	MOBILE HOME PARK BA ELECTRIC NC Amortization : > 12 MONTHS
199	MOBILE HOME PARK BA GAS NC	29,308,234	1,049,399	893	1,516,206	28,841,427
200	MOBILE HOME PARK BA GAS NC Amortization : > 12 MONTHS
201	MOBILE HOME PARK BA ELECTRIC CURRENT	4,869,187	1,380,252	597	1,338,176	4,911,263
202	MOBILE HOME PARK BA ELECTRIC CURRENT Amortization : < 12 MONTHS
203	MOBILE HOME PARK BA GAS CURRENT	5,358,633	1,516,206	893	1,471,572	5,403,267
204	MOBILE HOME PARK BA GAS CURRENT Amortization : < 12 MONTHS
205	REG ASSET - MISCELLANEOUS GAS - NON-CURRENT	19,341,126	22,044,612	400	16,467,096	24,918,642
206	REG ASSET - MISCELLANEOUS GAS - NON-CURRENT Amortization : > 12 MONTHS
207	MISCELLANEOUS ELECTRIC REG ASSET - NONCURRENT	479,543,577	474,248,320	549	434,741,219	519,050,678
208	MISCELLANEOUS ELECTRIC REG ASSET - NONCURRENT Amortization : 25 YEARS
209	REG ASSET - ABANDONED CAPITAL PROJECTS	142,308	7,339,236	400		7,481,544
210	REG ASSET - ABANDONED CAPITAL PROJECTS Amortization : < 12 MONTHS
211	REGULATORY ASSET-CEMA-ELEC-NONCURRENT	1,415,206,081	180,842,203	588	300,340,966	1,295,707,318
212	REGULATORY ASSET-CEMA-ELEC-NONCURRENT Amortization : > 12 MONTHS
213	CEMA GAS NONCURRENT	31,332,132	14,743,683	400	10,291,291	35,784,524
214	CEMA GAS NONCURRENT Amortization : > 12 MONTHS
215	Regulatory Asset-CEMA-Other-NonCurrent	10,611,584		880	4,880,307	15,491,891
216	Regulatory Asset-CEMA-Other-NonCurrent Amortization : > 12 MONTHS
217	MOBILE HOME PARK BALANCING ACCOUNT - ELECTRIC	6,895,514	7,256,704	182	61,938	14,090,280
218	MOBILE HOME PARK BALANCING ACCOUNT - ELECTRIC Amortization : <12 MONTHS
219	Regulatory Asset-DCPP M&S Inventory Non Current	9,045,000		400	3,015,000	6,030,000
220	Regulatory Asset-DCPP M&S Inventory Non Current Amortization : > 12 months
221	Regulatory Asset-DCPP M&S Inventory Current	12,060,000	3,015,000	400	3,015,000	12,060,000
222	Regulatory Asset-DCPP M&S Inventory Current Amortization : < 12 months
223	Yield Spread Adjustment Memorandum Account - Elec	19,020,956	101,611,228	501	81,259,727	39,372,457
224	Yield Spread Adjustment Memorandum Account - Elec Amortization : > 12 months
225	Yield Spread Adjustment Memorandum Account - Gas	3,244,930	13,628,498	501	11,750,091	5,123,337
226	Yield Spread Adjustment Memorandum Account - Gas Amortization : > 12 months
227	MOBILE HOME PARK BALANCING ACCOUNT - GAS	7,107,831	7,315,228	182		14,423,059
228	MOBILE HOME PARK BALANCING ACCOUNT - GAS Amortization : <12 MONTHS
229	WILDFIRES CUSTOMER PROTECTIONS MEMO ACCT - E		1,035,753	400		1,035,753
230	WILDFIRES CUSTOMER PROTECTIONS MEMO ACCT - E Amortization : > 12 MONTHS
231	WILDFIRES CUSTOMER PROTECTIONS MEMO ACCT- G		847,820	400		847,820
232	WILDFIRES CUSTOMER PROTECTIONS MEMO ACCT- G Amortization : > 12 MONTHS
233	FIRE HAZARD PREVENTION MEMO ACCT - CURRENT	127,373,361	45,702,587	400	44,345,691	128,730,257
234	FIRE HAZARD PREVENTION MEMO ACCT - CURRENT Amortization : < 12 MONTHS
235	Fire Risk & Wildfire Mitigation Memo Acct	84,485,484	30,296,782	400	29,355,857	85,426,409
236	Fire Risk & Wildfire Mitigation Memo Acct Amortization : < 12 MONTHS
237	Risk Transfer Bal Acct - Electric Curr	68,316,665	658,625,787	400	564,820,072	162,122,380
238	Risk Transfer Bal Acct - Electric Curr Amortization : < 12 months
239	Risk Transfer Bal Acct - Gas Curr	24,062,958	246,650,992	400	199,423,888	71,290,062
240	Risk Transfer Bal Acct - Gas Curr Amortization : < 12 months			—
241	Risk Transfer Bal Acct - Electric NonCurrent	87,249,281	87,072,360	400	352,432,922	178,111,281
242	Risk Transfer Bal Acct - Electric NonCurrent Amortization : > 12 months
243	Risk Transfer Bal Acct - Gas NonCurrent	30,731,530	30,729,251	400	53,750,990	7,709,791
244	Risk Transfer Bal Acct - Gas NonCurrent Amortization : > 12 months
245	BioMAT Non-Bypassable Charge	8,855,590	3,530,462	400	2,297,255	7,622,383
246	BioMAT Non-Bypassable Charge Amortization : < 12 months
247	Modified Cost Alloc Mechanism Bal Acct	1,831,201	1,817,402	501	1,180,545	2,468,058
248	Modified Cost Alloc Mechanism Bal Acct Amortization : < 12 MONTHS
249	Microgrids Balancing Account Non-Current	421,204	263,443	501		684,647
250	Microgrids Balancing Account Non-Current Amortization : > 12 MONTHS
251	Dynamic and Real-Time Pricing Memorandum Account	709,081	380,370	501		1,089,451
252	Dynamic and Real-Time Pricing Memorandum Account Amortization : > 12 MONTHS
253	Emergency Consumer Protections MA NC - E	8,503,993	124,018	501	1,035,753	7,592,258
254	Emergency Consumer Protections MA NC - E Amortization : > 12 MONTHS
255	Emergency Consumer Protections MA NC - G	6,957,806	101,468	501	847,820	6,211,454
256	Emergency Consumer Protections MA NC - G Amortization : > 12 MONTHS
257	Percentage of Income Payment Plan Bal Acct-E	1,611	180,525	400		182,136
258	Percentage of Income Payment Plan Bal Acct-E Amortization : < 12 MONTHS
259	Percentage of Income Payment Plan Memo Acct-E	2,145,816	595,052	501	595,052	2,145,816
260	Percentage of Income Payment Plan Memo Acct-E Amortization : > 12 MONTHS
261	Percentage of Income Payment Plan Memo Acct-G	536,459	148,763	501	148,763	536,459
262	Percentage of Income Payment Plan Memo Acct-G Amortization : > 12 MONTHS
263	ClimateAdaptationVulnerabilityAssessment NC - E	2,127,465	205,445	501	306,344	2,026,566
264	ClimateAdaptationVulnerabilityAssessment NC - E Amortization : > 12 MONTHS
265	ClimateAdaptationVulnerabilityAssessment NC - G	1,740,654	168,624	501		1,909,278
266	ClimateAdaptationVulnerabilityAssessment NC - G Amortization : > 12 MONTHS
267	SB901 Regulatory Asset Non-Current	5,329,234,810		925	33,317,947	5,295,916,863
268	SB901 Regulatory Asset Non-Current Amortization : > 12 MONTHS
269	Microgrid Memorandum Account - Current		76,008,763	501		76,008,763
270	Microgrid Memorandum Account - Current Amortization : > 12 months
271	COVID-19 Pandemic Protections MA-Curr-E		7,172,034	501		7,172,034
272	COVID-19 Pandemic Protections MA-Curr-E Amortization : < 12 MONTHS
273	COVID-19 Pandemic Protections MA-Curr-G		2,408,252	501		2,408,252
274	COVID-19 Pandemic Protections MA-Curr-G Amortization : < 12 MONTHS
275	CA Consumer Privacy Act Memo Account-Elec Curr		5,206,811	501		5,206,811
276	CA Consumer Privacy Act Memo Account-Elec Curr Amortization : < 12 MONTHS
277	CA Consumer Privacy Act Memo Account-Gas Curr		2,277,021	501		2,277,021
278	CA Consumer Privacy Act Memo Account-Gas Curr Amortization : < 12 MONTHS
279	COVID-19 Pandemic Protection Memorandum Account -	20,840,431	1,776,889	400	8,139,587	14,477,733
280	COVID-19 Pandemic Protection Memorandum Account - Amortization : > 12 MONTHS
281	COVID-19 Pandemic Protection Memo Account -Gas -NC	6,096,276	543,526	400	2,627,787	4,012,015
282	COVID-19 Pandemic Protection Memo Account -Gas -NC Amortization : > 12 MONTHS
283	ML-CDMMA-E NonCurrent	1,169,127	16,655	400	519,051	666,731
284	ML-CDMMA-E NonCurrent Amortization : > 12 MONTHS
285	General Office Sale MA-E	38,742,828	15,079,728	407	6,353,669	47,468,887
286	General Office Sale MA-E Amortization : > 12 months
287	General Office Sale MA-G	18,374,713	7,151,922	407	115,196	25,411,439
288	General Office Sale MA-G Amortization : > 12 months
289	Wildfire and Natural Disaster RR BA	3,511,567	42,269	400	200,719	3,353,117
290	Wildfire and Natural Disaster RR BA Amortization : < 12 MONTHS
291	FINANCING COSTS REGULATORY ASSET	206,887,181	186,196	428	4,007,111	203,066,266
292	FINANCING COSTS REGULATORY ASSET Amortization : 20 YEARS
293	URG PLANT REGULATORY ASSET - NONCURRENT	943,696,000		407		943,696,000
294	URG PLANT REGULATORY ASSET - NONCURRENT Amortization : 22 YEARS
295	URG PLANT REGULATORY ASSET - TAX	183,010,953		182		183,010,953
296	URG PLANT REGULATORY ASSET - TAX Amortization : 11 YEARS
297	ACCUM AMORT - URG PLANT REG ASSET NON CURRENT	871,858,477		405	10,836,750	882,695,227
298	ACCUM AMORT - URG PLANT REG ASSET NON CURRENT Amortization : 12 YEARS
299	ACC AMT - PLANT RA TAX	180,370,484		405	880,143	181,250,627
300	ACC AMT - PLANT RA TAX Amortization : 11 YEARS
301	UNAMORTIZED FINANCIAL HEDGING COST	8,389,821		428	209,049	8,180,772
302	UNAMORTIZED FINANCIAL HEDGING COST Amortization : 20 YEARS
303	PENSION REGULATORY ASSET	114,575,753	598,868	926	6,372,510	108,802,111
304	PENSION REGULATORY ASSET Amortization : INDEFINITE
305	URG PLANT REGULATORY ASSET - CURRENT	43,348,000		407		43,348,000
306	URG PLANT REGULATORY ASSET - CURRENT Amortization : < 12 MONTHS
307	MAJOR EMERGENCY BALANCING ACCOUNT	51,386,675	11,032,772	182	37,923,482	24,495,965
308	MAJOR EMERGENCY BALANCING ACCOUNT Amortization : <12 MONTHS
309	FIN 47 - REGULATORY ASSET	16,890,937	1,558,916	101		18,449,853
310	FIN 47 - REGULATORY ASSET Amortization : NO STATED
311	HYDRO LICENSING BALANCING ACCOUNT	2,600,145	14,836,040	182	13,544,222	1,308,327
312	HYDRO LICENSING BALANCING ACCOUNT Amortization : >12 MONTHS
313	NUCLEAR REGULATORY COMMISSION RULEMAKING COSTS BALANCING ACC	197,771	543,862	182	456,781	284,852
314	NUCLEAR REGULATORY COMMISSION RULEMAKING COSTS BALANCING ACC Amortization : >12 MONTHS
315	REGULATORY ASSET - HYRDO NONCURRENT	11,521,705	84,012	400		11,605,717
316	REGULATORY ASSET - HYRDO NONCURRENT Amortization : > 12 MONTHS
317	FINANCING COSTS - CURRENT	14,441,887		428	545,343	13,896,544
318	FINANCING COSTS - CURRENT Amortization : < 12 MONTHS
319	UNAMORTIZED FINANCIAL HEDGING COST CURRENT	836,195		428		836,195
320	UNAMORTIZED FINANCIAL HEDGING COST CURRENT Amortization : < 12 MONTHS
321	NEW ENVIRONMENTAL REGULATIONS BALANCING ACCOUNT	997,821	1,831,924	400	2,549,264	1,715,161
322	NEW ENVIRONMENTAL REGULATIONS BALANCING ACCOUNT Amortization : > 12 MONTHS
323	DIABLO CANYON RETIREMENT BAL ACCT (DEPR) - CURRENT	6,465,620	6,658,422	400	1	13,124,043
324	DIABLO CANYON RETIREMENT BAL ACCT (DEPR) - CURRENT Amortization : < 12 MONTHS
325	DCRBA - DCPP EMPLOYEE RETENTION PROGRAM	41,638,625	12,944,984	400	13,005,498	41,578,111
326	DCRBA - DCPP EMPLOYEE RETENTION PROGRAM Amortization : > 12 MONTHS
327	San Joaq. Valley Disadv. Comm. Pilot BA	19,002,528	1,507,681	400	226,873	17,721,720
328	San Joaq. Valley Disadv. Comm. Pilot BA Amortization : < 12 MONTHS			—
329	PPCBA Pub Pol Ch Prg Subacct - current	85,474,362	4,088,985	400	20,194,095	69,369,252
330	PPCBA Pub Pol Ch Prg Subacct - current Amortization : < 12 MONTHS			—
331	Disadv Comm Green Tariff Program Bal Acct	103,250	4,279,420	400	3,737,693	644,977
332	Disadv Comm Green Tariff Program Bal Acct Amortization : < 12 MONTHS			—
333	Net Energy Metering Balancing Account	644,703	3,839,458	400	11,933	4,472,228
334	Net Energy Metering Balancing Account Amortization : > 12 MONTHS			—
335	Community Solar Green Tariff Balance Account	6,288,697	54,471	182	701,548	6,935,774
336	Community Solar Green Tariff Balance Account Amortization : < 12 MONTHS			—
337	PCIA Undercollection Balancing Account	74,272,666	820,359	400	19,243,596	55,849,429
338	PCIA Undercollection Balancing Account Amortization : < 12 MONTHS			—
339	Disconnections Memorandum Account - Gas NC	6,239,013	1,277,729	400	3,966,133	3,550,609
340	Disconnections Memorandum Account - Gas NC Amortization : > 12 MONTHS			—
341	Disconnections Memorandum Account - Electric NC	7,625,247	1,568,475	400	3,245,018	5,948,704
342	Disconnections Memorandum Account - Electric NC Amortization : > 12 MONTHS			—
343	WMBA - Electric Reason Review (Non-Curr)	309,910,821	4,794,019	501	88,721,818	225,983,022
344	WMBA - Electric Reason Review (Non-Curr) Amortization : > 12 MONTHS			—
345	WMBA - Gas Reason Review (Non-Curr)	23,609,351	2,744,892	501		26,354,243
346	WMBA - Gas Reason Review (Non-Curr) Amortization : > 12 MONTHS			—
347	Vegetation Management Balancing Acct (VMBA) - Curr	52,221,113	1,003,632,973	400	183,630,650	872,223,436
348	Vegetation Management Balancing Acct (VMBA) - Curr Amortization : < 12 MONTHS			—
349	Vegetation Management Balancing Acct (VMBA) - NC	2,317,118,453	27,301,049	410	692,818,131	1,651,601,371
350	Vegetation Management Balancing Acct (VMBA) - NC Amortization : > 12 MONTHS			—
351	Adj Mechanism for Costs in Other Proceedings - NC	14,945,129	14,944,021	182	26,139,782	3,749,368
352	Adj Mechanism for Costs in Other Proceedings - NC Amortization : > 12 MONTHS			—
353	Public Policy Charge Procurement Subacct (PPCBA)	496,897	2,704,605	400	1,521,031	686,677
354	Public Policy Charge Procurement Subacct (PPCBA) Amortization : < 12 MONTHS			—
355	Disconnections Memorandum Account-Curr-E		3,966,133	501		3,966,133
356	Disconnections Memorandum Account-Curr-E Amortization : < 12 MONTHS			—
357	Disconnections Memorandum Account-Curr-G		3,245,018	501		3,245,018
358	Disconnections Memorandum Account-Curr-G Amortization : < 12 MONTHS			—
359	Miscellaneous minor items	382,973	81,231	(c) VARIOUS	248,698	215,506
44	TOTAL	23,855,972,965	13,416,332,064		11,980,039,575	25,292,265,454

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Offset to 182.3 - Other Regulatory Assets, 232 - Accounts Payable, 400 - Revenue, 500 - Regulatory Credits, 501 - Expense and 925 - Injuries and Damages.

(b) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Offset to 232 - Accounts Payable, 500 - FASB842 Rent Expense Clearing, 501 - Expense and 925 - Injuries and Damages.

Offset to 400 - Revenue, 501 - Expense and 244 - Liabilities

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	SB901 Reg Liab Shareholders - NonCurrent	5,937,394,856	925	105,319,659	289,431,109	6,121,506,306
2	SB901 Reg Liab Shareholders - NonCurrent Amortization : > 12 MONTHS
3	FAS 143 Regulatory Liability-Nuclear Decom	3,496,800,303	108	114,694,546	228,483,603	3,610,589,360
4	FAS 143 Regulatory Liability-Nuclear Decom Amortization : NO STATED
5	MISCELLANEOUS ELECTRIC REG LIAB - NONCURRENT	1,144,600,272	549	118,364,803	12,077,445	1,038,312,914
6	MISCELLANEOUS ELECTRIC REG LIAB - NONCURRENT Amortization : NO STATED
7	REGULATORY LIABILITY RETIREM	910,729,397	520	4,166,751	11,256,502	917,819,148
8	REGULATORY LIABILITY RETIREM Amortization : INDEFINITE
9	End-Use Customer Refund Adj - NonCurrent	304,487,805	400		5,709,146	310,196,951
10	End-Use Customer Refund Adj - NonCurrent Amortization : > 12 MONTHS
11	Regulatory Liability TO - Current	237,953,763	400	695,569,621	719,603,526	261,987,668
12	Regulatory Liability TO - Current Amortization : < 12 months
13	SOLAR ON MULTIFAMILY AFFORDABLE HOUSING BAL ACCT	238,542,908	400	2,104,591	12,988,972	249,427,289
14	SOLAR ON MULTIFAMILY AFFORDABLE HOUSING BAL ACCT Amortization : < 12 MONTHS
15	SELF GENERATION PROGRAM - ELECTRIC	240,523,835	400	19,923,515	18,679,516	239,279,836
16	SELF GENERATION PROGRAM - ELECTRIC Amortization : NO STATED
17	FAS 109 REGULATORY LIABILITY	5,467,985,280	400			5,467,985,280
18	FAS 109 REGULATORY LIABILITY Amortization : > 12 MONTHS
19	ELECTRIC PRICE RISK MANAGEMENT - NONCURRENT	325,424,467	555	325,424,467	237,941,422	237,941,422
20	ELECTRIC PRICE RISK MANAGEMENT - NONCURRENT Amortization : NO STATED
21	ELECTRIC PROGRAM INVESTMENT CHARGE BALANCING ACCOUNT	196,713,401	400	12,747,162	25,671,995	209,638,234
22	ELECTRIC PROGRAM INVESTMENT CHARGE BALANCING ACCOUNT Amortization : NO STATED
23	GHGRBA-LCFS Non-Current	150,941,720	400		20,480,766	171,422,486
24	GHGRBA-LCFS Non-Current Amortization : > 12 MONTHS
25	FAS 143 Regulatory Liability-Fossil Decom	167,719,671	228	11,983	413,250	168,120,938
26	FAS 143 Regulatory Liability-Fossil Decom Amortization : NO STATED
27	DemandResponse-Emerg Ld Reduc Prog Subac	98,614,790	400	2,060,848	29,390,612	125,944,554
28	DemandResponse-Emerg Ld Reduc Prog Subac Amortization : > 12 months
29	DEMAND RESPONSE EXPENDITURES BALANCING ACCOUNT	113,034,026	400	8,502,081	15,319,609	119,851,554
30	DEMAND RESPONSE EXPENDITURES BALANCING ACCOUNT Amortization : NO STATED
31	ELECTRIC PRICE RISK MANAGEMENT - CURRENT	140,264,940	555	140,264,940	111,487,045	111,487,045
32	ELECTRIC PRICE RISK MANAGEMENT - CURRENT Amortization : NO STATED
33	FAS143 REGLIAB GUS LM AND PC	75,490,200	228		4,440,600	79,930,800
34	FAS143 REGLIAB GUS LM AND PC Amortization : AMORTIZATION : NO STATED
35	MISCELLANEOUS GAS REG LIAB - NONCURRENT	85,109,116	549	10,266,473		74,842,643
36	MISCELLANEOUS GAS REG LIAB - NONCURRENT Amortization : 2 YEARS
37	MISCELLANEOUS ELECTRIC REG LIAB - CURRENT	70,741,703	449		262,191	71,003,894
38	MISCELLANEOUS ELECTRIC REG LIAB - CURRENT Amortization : < 12 MONTHS
39	CALIFORNIA SOLAR INITIATIVE	62,223,547	400	522,997	767,577	62,468,127
40	CALIFORNIA SOLAR INITIATIVE Amortization : 5 YEARS
41	ON BILL FINANCING BALANCING ELECTRIC	54,283,441	930	2,907,514	9,240,603	60,616,530
42	ON BILL FINANCING BALANCING ELECTRIC Amortization : NO STATED
43	SELF GENERATION PROGARM-GAS	47,850,102	400	8,677,455	8,342,941	47,515,588
44	SELF GENERATION PROGARM-GAS Amortization : NO STATED
45	FAS Regulatory Liability - Hydro	41,915,250	228	1,915,438	3,224,250	43,224,062
46	FAS Regulatory Liability - Hydro Amortization : Not Stated
47	GHGRBA - LOW CARBON FUELS STANDARD REVENUE SUBACCOUNT	50,142,701	400	21,210,990	14,038,363	42,970,074
48	GHGRBA - LOW CARBON FUELS STANDARD REVENUE SUBACCOUNT Amortization : < 12 MONTHS
49	PPP (PPPLIBA)-ELECTRIC	57,751,360	400	40,179,853	23,433,476	41,004,983
50	PPP (PPPLIBA)-ELECTRIC Amortization : < 12 MONTHS
51	PROCUREMENT ENERGY EFFICIENCY	32,281,611	400	7,842,824	11,834,046	36,272,833
52	PROCUREMENT ENERGY EFFICIENCY Amortization : NO STATED
53	NON CURRENT REG LIAB-CC8 SETTLEMENT	35,284,199	108	542,382		34,741,817
54	NON CURRENT REG LIAB-CC8 SETTLEMENT Amortization : 25YEARS
55	Hydrostatic Testing Bal Account	44,563,090	400	14,891,704	1,284,524	30,955,910
56	Hydrostatic Testing Bal Account Amortization : >12 MONTHS
57	Hydrostatic Testing Bal Account - current	14,667,719	400	377,859	15,163,208	29,453,068
58	Hydrostatic Testing Bal Account - current Amortization : < 12 MONTHS
59	MISCELLANEOUS GAS REG LIAB - CURRENT	27,437,161	495			27,437,161
60	MISCELLANEOUS GAS REG LIAB - CURRENT Amortization : <12 MONTHS
61	STATEWIDE ENERGY EFFICIENCY BALANCING ACCOUNT - ELECTRIC	23,406,152	400	21,711,697	24,498,217	26,192,672
62	STATEWIDE ENERGY EFFICIENCY BALANCING ACCOUNT - ELECTRIC Amortization : AMORTIZATION : < 12 MONTHS
63	RULE 20A BALANCING ACCOUNT (RBA) NONCURRENT	23,189,763	400	4,589,806	6,369,396	24,969,353
64	RULE 20A BALANCING ACCOUNT (RBA) NONCURRENT Amortization : > 12 MONTHS
65	GAS PRICE RISK MANAGEMENT - CURRENT	3,705,304	175	3,705,303	24,316,672	24,316,673
66	GAS PRICE RISK MANAGEMENT - CURRENT Amortization : NO STATED
67	FAS Regulatory Liability - Other Electric	20,559,500	228		1,581,500	22,141,000
68	FAS Regulatory Liability - Other Electric Amortization : Not Stated
69	DREBA - Dem Resp Auct Mech non-current	18,936,021	400	525,808	1,740,768	20,150,981
70	DREBA - Dem Resp Auct Mech non-current Amortization : > 12 months
71	GPBA-Biomethane Procurement Pilot Projects Subacct	17,312,002	400		215,231	17,527,233
72	GPBA-Biomethane Procurement Pilot Projects Subacct Amortization : > 12 MONTHS
73	ELECT VEHICLE PRGM BA CURRENT	6,786,904	400	2,698,666	10,690,711	14,778,949
74	ELECT VEHICLE PRGM BA CURRENT Amortization : < 12 MONTHS
75	PPP SURCHARGE LOW INCOME - GAS	14,560,721	400	20,884,807	20,277,363	13,953,277
76	PPP SURCHARGE LOW INCOME - GAS Amortization : < 12 MONTHS
77	PPP (PPPLIBA)-GAS	9,761,903	400	20,203,552	43,885,555	13,920,100
78	PPP (PPPLIBA)-GAS Amortization : < 12 MONTHS
79	SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA - ELECTRIC	13,323,053	400	2,491,811	2,646,271	13,477,513
80	SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA - ELECTRIC Amortization : < 12 MONTHS
81	ON BILL FINANCING BALANCING GAS	10,891,523	930	673,187	2,089,353	12,307,689
82	ON BILL FINANCING BALANCING GAS Amortization : NO STATED
83	AB841 School Energy Efficiency - Electric current	224,305	400	10,767,736	21,561,139	11,017,708
84	AB841 School Energy Efficiency - Electric current Amortization : < 12 MONTHS
85	GPBA-Renewable Gas Interconnections Incentives PRG	10,777,281	400	5,000,000	2,203,449	7,980,730
86	GPBA-Renewable Gas Interconnections Incentives PRG Amortization : < 12 MONTHS
87	PUBL PURP PROG ENERGY EFFICIENCY BAL ACCT - CURRENT	9,781,630	400	18,700,935	16,714,514	7,795,209
88	PUBL PURP PROG ENERGY EFFICIENCY BAL ACCT - CURRENT Amortization : <12 MONTHS
89	PPCBA-Dis Com Sgl Family Slr Hme non cur	7,021,497	400	557,052	83,398	6,547,843
90	PPCBA-Dis Com Sgl Family Slr Hme non cur Amortization : > 12 months
91	Wildfire Hardening Fixed Rcvry Chrg B/A	1,560,547	400	368,672	7,633,938	5,704,719
92	Wildfire Hardening Fixed Rcvry Chrg B/A Amortization : < 12 MONTHS
93	SB901 Reg Liab Customer Credit Trust-NC		504		5,466,993	5,466,993
94	SB901 Reg Liab Customer Credit Trust-NC Amortization : > 12 months
95	PROCUREMENT ENERGY EFFICIENCY BALANCING ACCT - CURRENT	19,270,282	400	80,321,057	66,483,993	5,433,218
96	PROCUREMENT ENERGY EFFICIENCY BALANCING ACCT - CURRENT Amortization : <12 MONTHS
97	STATEWIDE ENERGY EFFICIENCY BALANCING ACCOUNT - GAS	4,302,535	400	5,475,342	4,812,695	3,639,888
98	STATEWIDE ENERGY EFFICIENCY BALANCING ACCOUNT - GAS Amortization : AMORTIZATION : < 12 MONTHS
99	PPP SURCHARGE ENERGY EFFICIENCY - GAS	4,550,147	400	22,067,944	20,708,766	3,190,969
100	PPP SURCHARGE ENERGY EFFICIENCY - GAS Amortization : < 12 MONTHS
101	PPP SURCHARGE RDD - CURRENT	4,481,791	182	4,006,769	2,708,912	3,183,934
102	PPP SURCHARGE RDD - CURRENT Amortization : < 12 MONTHS
103	Rate Base Adjustments Memo Acct	1,506,008	400		1,526,337	3,032,345
104	Rate Base Adjustments Memo Acct Amortization : < 12 MONTHS
105	Casing Program Bal Acct	1,335,577	400		1,433,368	2,768,945
106	Casing Program Bal Acct Amortization : < 12 MONTHS
107	AB841 School Energy Efficiency - Gas current	48,547	400	2,691,934	5,390,191	2,746,804
108	AB841 School Energy Efficiency - Gas current Amortization : < 12 MONTHS
109	Internal Corrosion Bal acct	1,007,391	400		1,081,153	2,088,544
110	Internal Corrosion Bal acct Amortization : < 12 MONTHS
111	GPBA-BIOMETHANE ENVIRONMENTAL PROCEEDS SUBACCOUNT	1,147,898	400		410,841	1,558,739
112	GPBA-BIOMETHANE ENVIRONMENTAL PROCEEDS SUBACCOUNT Amortization : > 12 MONTHS
113	PPP ENERGY EFFICIENCY-GAS	1,407,455	400	34,722	149,612	1,522,345
114	PPP ENERGY EFFICIENCY-GAS Amortization : NO STATED
115	Alternating Curr Interference Bal Acct	719,893	400		772,602	1,492,495
116	Alternating Curr Interference Bal Acct Amortization : < 12 MONTHS
117	SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA - GAS	1,406,556	400		17,560	1,424,116
118	SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA - GAS Amortization : < 12 MONTHS
119	Dairy Biomethane Pilot Balancing Account	960,439	400	2,500,000	2,511,926	972,365
120	Dairy Biomethane Pilot Balancing Account Amortization : < 12 months
121	Physical Security Bal Acct	447,937	400		480,735	928,672
122	Physical Security Bal Acct Amortization : < 12 MONTHS
123	REG LIABILITY GAS RISK MGMT - NONCURRENT		175		892,935	892,935
124	REG LIABILITY GAS RISK MGMT - NONCURRENT Amortization : N/A
125	DemandResponse-Critical Peak Pric Subac	492,917	400		6,121	499,038
126	DemandResponse-Critical Peak Pric Subac Amortization : > 12 months
127	AB841 Shool EE Stimulus Program BA-Elec	6,400,231	400	27,739,940	34,619,800	479,629
128	AB841 Shool EE Stimulus Program BA-Elec Amortization : > 12 months
129	ENGINEERING CRTICIAL ASSESSMENT BAL NC	582,807	182	290,359	5,612	298,060
130	ENGINEERING CRTICIAL ASSESSMENT BAL NC Amortization : >12 MONTHS
131	ENGINEERING CRITICAL ASSESSMENT BAL ACCT-CURRENT		400		291,984	291,984
132	ENGINEERING CRITICAL ASSESSMENT BAL ACCT-CURRENT Amortization : < 12 MONTHS
133	NON-TARIFFED PRODUCTS AND SVCS BA-ELECTRIC	73,837	182	346,971	486,214	213,080
134	NON-TARIFFED PRODUCTS AND SVCS BA-ELECTRIC Amortization : < 12 MONTHS
135	NON-TARIFFED PRODUCTS AND SVCS BA-GAS	60,402	182	5	113,905	174,312
136	NON-TARIFFED PRODUCTS AND SVCS BA-GAS Amortization : < 12 MONTHS
137	AB841 Shool EE Stimulus Program BA-Gas	671,823	400	6,936,183	7,727,860	119,854
138	AB841 Shool EE Stimulus Program BA-Gas Amortization : > 12 months
139	CCA’s DAC-GT and CS-GT Programs BA	547,826	930	910,166	127,817	234,523
140	CCA’s DAC-GT and CS-GT Programs BA Amortization : < 12 MONTHS
141	GHGRBA - GREENHOUSE GAS REVENUE SUBACCOUNT	78,224,400	400	53,953,370	125,033,757	7,144,013
142	GHGRBA - GREENHOUSE GAS REVENUE SUBACCOUNT Amortization : < 12 MONTHS
143	TAMA - GAS	106,113,774	182			106,113,774
144	TAMA - GAS Amortization : 2 YEARS
145	GPBA - GREENHOUSE GAS REVENUE SUBACCOUNT	189,005,701	400	13,663,151	73,923,221	128,745,631
146	GPBA - GREENHOUSE GAS REVENUE SUBACCOUNT Amortization : < 12 MONTHS
147	FAS 143 Regulatory Liability - Fossil	153,392,293	(a) VARIOUS	313,391		153,705,684
148	FAS 143 Regulatory Liability - Fossil Amortization : NO STATED
149	FIN 47 REGULATORY LIABILITY	965,201,686	(b) VARIOUS	25,953,632	1,915,438	989,239,880
150	FIN 47 REGULATORY LIABILITY Amortization : NO STATED
151	FAS 143 Regulatory Liability - Nuclear	2,684,121,906	(c) VARIOUS	54,762,876	2,929,370	2,735,955,412
152	FAS 143 Regulatory Liability - Nuclear Amortization : NO STATED
153	Miscellanous minor items	323,748	(d) VARIOUS	263,413,450	263,006,522	83,180
41	TOTAL	15,902,168,019		2,336,750,740	2,642,510,012	16,207,927,291

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Offset to account 108 - Accumulated Depreciation and 230 - ARO - Liability.

(b) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Offset to account 108 - Accumulated Depreciation, 182.3 - Other Regulatory Assets, 254 - Other Regulatory Liabilities and 230 - ARO - Liability.

Offset to account 108 - Accumulated Depreciation, 143 - Accounts Receivable, 254 - Other Regulatory Liabilities and 230 - ARO - Liability.

(d) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Activity primarily related to Recovery Bond Tracking and Recovery Bond Tracking Offset with offset to 254 - Other Regulatory Liabilities

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	2,693,152,337		12,419,180		4,985,481
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	(a) 2,896,380,655		15,149,923		638,792
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	(b) 728,336,764		6,650,334		1,216
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	33,298,340		138,149		37,976
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	166,547		586		3
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways	6,007,469		192,650		29
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	27,248,062		140,405
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	(c) 6,384,590,174		34,691,227		5,663,497
11	SalesForResaleAbstract (447) Sales for Resale	1,964,177,709
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	8,348,767,883		34,691,227		5,663,497
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	698,012
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	8,348,069,871		34,691,227		5,663,497
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	125,879
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(d) 3,834,348
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power	1,619,373
19	RentFromElectricProperty (454) Rent from Electric Property	30,101,284
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(e) 115,180,436
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	1,737,987
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
25.1	OtherMiscellaneousOperatingRevenues (400) Balancing Accounts	1,692,526,691
25.2	OtherMiscellaneousOperatingRevenues (414) Other Utility Operating Income	50,388,110
26	OtherOperatingRevenues TOTAL Other Operating Revenues	1,665,153,236
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	10,013,223,107
Line12, column (b) includes $ 61,903,247 of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: SmallOrCommercialSalesElectricOperatingRevenue

Line 4 includes all other commercial and industrial customers including irrigation pumping.

(b) Concept: LargeOrIndustrialSalesElectricOperatingRevenue

Line 5 includes commercial and industrial customers with demands of 1,000 kWh or greater.

Column (b) includes California Department of Water Resources ("DWR") revenues of $178,598,010 which was deducted from Line 21 below.

(d) Concept: MiscellaneousServiceRevenues


This consists of :
NSF fees and rent charges to customers' refundable deposits			877,168
Misc Elec Svs RevPro			—
NRD Revenue			293,430
MLX billings to electric residential customers			1,866,376
MLX billings to electric non-residential customers			360,865
Reimbursable third-party labor requested on behalf of customers			436,509

Total			3,834,348

(e) Concept: OtherElectricRevenue


This consists of :
Unbilled revenues			(61,903,247)
Reimbursement to the Utility for costs spent on customer projects			30,354,312
Reimbursement to the Utility for costs spent on customer billing			7,594,602
Reimbursement fees paid to the CPUC based on sales			(44,914,980)
Employee transfer fees			—
Other revenue-damage claim			768,888
Recreational Facilities Revenue			457,428
Revenue assigned - base			(17,661,529)
Leasing of utility towers			19,002,865
Pass-through franchise fees and uncollectible revenue			17,661,743
Transition Cost Revenue Account for non-bypassable charges			23,688,741
Fees for utility energy service contracts			27,633,128
Other electric revenues not classified elsewhere			60,395,137
MCI rights of way			290,661
DWR			(178,598,010)
Miscellaneous (items under $250,000)			49,825
Total			(115,180,436)

The DWR revenues of $178,598,010 represents amount passed through to the DWR. The Utility acts as a pass-through entity for DWR charges collected from the Utility's customers. Although charges for the DWR are included in total electric revenues, the Utility deducts pass through amounts from electric revenues. These pass-through revenues are excluded from the Utility's electric revenues in its Statement of Income.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	NONE
46	TOTAL

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

ELECTRIC PRODUCTION, OTHER POWER SUPPLY EXPENSES, TRANSMISSION AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)	418,472,782
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)	9,150,122
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	427,622,904
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)	134,203,846
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)	89,373,268
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power	223,577,114
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)	63,082,715
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)	43,073,975
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power	106,156,690
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)	11,473,295
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)	12,988,147
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	24,461,442
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	2,641,826,060
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	2,429,393
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	67,890,587
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	2,707,287,254
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	3,489,105,404
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	1,262,142
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	24,756,575
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	8,012,589
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development
29	TransmissionServiceStudies (561.6) Transmission Service Studies
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	3,502,333
32	StationExpensesTransmissionExpense (562) Station Expenses	5,079,588
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	41,315,535
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	238,276
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	400,811
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	112,834,152
37	RentsTransmissionElectricExpense (567) Rents
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	197,402,001
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	321,977
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	1,486,412
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	25,773,782
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	110,754,291
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	1,386,725
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	221,809
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	139,301,042
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	336,703,043
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services	5,705,653
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)	5,705,653
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)	5,705,653
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	(a) 48,358,363
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	(b) 1,444,168,589
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	1,395,810,226

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: DistributionOperationExpensesElectric

Of the quarter end balance, $0 relates to energy storage operation per FERC Order 784.

(b) Concept: DistributionMaintenanceExpenseElectric

Of the quarter end balance, $93,599 relates to energy storage operation per FERC Order 784.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	284,524,535
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	180,070,471
3	SalesExpenses (911-917) Sales Expenses	880,782
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	220,509,811
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	46,265,170
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	23,124,668
9	OutsideServicesEmployed (923) Outside Services Employed	238,928,553
10	PropertyInsurance (924) Property Insurance	9,203,847
11	InjuriesAndDamages (925) Injuries and Damages	1,005,495,642
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	(a) 168,289,942
13	FranchiseRequirements (927) Franchise Requirements	50,964,886
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	9,135,377
18	RentsAdministrativeAndGeneralExpense (931) Rents
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	1,633,138,220
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	968,958
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	1,634,107,178

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: EmployeePensionsAndBenefits

Of the quarter end balance, $0 relates to energy storage operation per FERC Order 784.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(a)

TRANSMISSION AGENCY OF NORTHERN CALIFORNIA (TANC)

Various

LFP

143

Midway

Various

233

172,910

169,640

1,737,987

TOTAL

233

172,910

169,640

1,737,987

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Other Charges represent booking estimate adjustments. In September 2003, the Utility changed the billing methodology using energy as billing determinants rather than contract demand. The change was pursuant to the TO6 Settlement Agreement under FERC Docket No. ER03-666-000.

Transmission is provided under the Midway Transmission Service.

Recorded here are the Midway Transmission Service data for TANC members which include Modesto Irrigation District, Sacramento Municipal Utility District, City of Redding, and the Turlock Irrigation District.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1	NONE
40	TOTAL

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	CALIFORNIA-OREGON
2	TRANSMISSION PROJECT	OS			(a) 13,450		(c) 184,518	197,968
3	PACIFICORP	OS					(d) 73,530	73,530
4	SACRAMENTO MUNICIPAL
5	UTILITY DISTRICT	OS
6	WESTERN AREA POWER
7	ADMINISTRATION	OS			(b) 68,574			68,574
8	INTERTIE	OS					(e) 60,739	60,739
9	OTHER	OS
	TOTAL		0	0	82,024	0	318,787	400,811

FOOTNOTE DATA

(a) Concept: DemandChargesTransmissionOfElectricityByOthers

Represents payments for lease of transmission capacity.

(b) Concept: DemandChargesTransmissionOfElectricityByOthers

Represents payments for lease of transmission capacity.

Represents payments for operations and maintenance costs.

(d) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for operations and maintenance costs.

(e) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for administrative costs of scheduling services provided by the California Independent Systems Operator (CAISO).

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			7,030,930		7,030,930
2	Steam Production Plant	13,632,082				13,632,082
3	Nuclear Production Plant	204,332,904			19,365,786	223,698,690
4	Hydraulic Production Plant-Conventional	60,628,920			1,692,000	62,320,920
5	Hydraulic Production Plant-Pumped Storage	13,260,093			2,376,000	15,636,093
6	Other Production Plant	31,561,079				31,561,079
7	Transmission Plant	237,390,426				237,390,426
8	Distribution Plant	821,937,055				821,937,055
9	General Plant	32,821,771				32,821,771
10	Common Plant-Electric	99,452,145		70,685,864		170,138,009
11	TOTAL	1,515,016,476		77,716,794	23,433,786	1,616,167,056

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	81,865,452	75,340,712
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	596,706,832	106,412,998
4	Transmission Rights
5	Ancillary Services	2,601,852	535,275
6	Other Items (list separately)
7	Grid Management Charges	9,475,453	8,326,126
8	FERC Fees	666,220	614,480
9	ISO Congestion
10	Unaccounted for Energy	37,850,048	36,309,959
11	Congestion Revenue Rights-Hedge	18,754,636	32,098,420
12	Congestion Revenue Rights-Auction
13	Convergence Bidding
14	Other ISO-related charges:
15	Minimum Load
16	Neutrality	82,732	664,495
17	Voltage Support
18	Other	933,850	829,743
19	Cost Recovery	16,301,643	3,113,552
20	Inter Day Ahead SC Trade
21	Inter Real Time SC Trade
22	Interest	528,489	1,061,274
23	Capacity - Other	3,097,158	2,007,545
24	DA IFM Credit Allocation	16,203,807	6,863,718
25	RT Offset/Allocation	11,231,751	7,701,855
26	Net Purchases for Energy Storage	487,595	2,429,393
46	TOTAL	582,893,008	91,806,021

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Monthly Peak Loads and Energy Output
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: 0
1	January	7,180,116		12,051	18	19
2	February	6,287,392		12,278	27	19
3	March	(a) 6,780,613		(c) 12,615	9	(f)(g) 19
4	Total for Quarter 1	20,248,121
5	April	6,044,243		12,363	27	21
6	May	6,669,349		12,775	22	20
7	June	(b) 7,193,955		(d) 15,582	(e) 30	(h) 20
8	Total for Quarter 2	19,907,547
9	July
10	August
11	September
12	Total for Quarter 3
41	Total

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: EnergyActivity

This is a revision of the preliminary data previously submitted.

(b) Concept: EnergyActivity

Based on preliminary data at time of filing.

This is a revision of the preliminary data previously submitted.

(d) Concept: MonthlyPeakLoad

Based on preliminary data at time of filing.

(e) Concept: DayOfMonthlyPeak

Based on preliminary data at time of filing.

(f) Concept: HourOfMonthlyPeak

This is a revision of the preliminary data previously submitted.

(g) Concept: HourOfMonthlyPeak

This is a revision of the preliminary data previously submitted.

(h) Concept: HourOfMonthlyPeak

Based on preliminary data at time of filing.

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	12,947	18	19	3,514	0	0	85	0	9,348
2	February	13,202	27	19	4,111	0	0	100	0	8,991
3	March	13,629	9	19	4,065	0	0	100	0	9,464
4	Total for Quarter 1				11,690	0	0	285	0	27,803
5	April	13,380	27	21	4,878	0	0	100	0	8,402
6	May	13,899	22	20	5,691	0	0	125	0	8,083
7	June	16,761	30	20	(a) 5,285	0	0	175	0	11,301
8	Total for Quarter 2				15,854	0	0	400	0	27,786
9	July				0	0	0	0	0	0
10	August				0	0	0	0	0	0
11	September				0	0	0	0	0	0
12	Total for Quarter 3				0	0	0	0	0	0
13	October				0	0	0	0	0	0
14	November				0	0	0	0	0	0
15	December				0	0	0	0	0	0
16	Total for Quarter 4				0	0	0	0	0	0
17	Total				27,544	0	0	(b) 685	0	(c) 55,589

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: FirmNetworkServiceForSelf

Actual data is not available at time of filing. Entry reflects estimated data.

(b) Concept: OtherLongTermFirmService

Represent transmission service to the following Existing Transmission Contract customers:

Transmission Agency of Northern California.

Transmission services utilizing the Utility's transmission system are also sold by the California Independent System Operator ("ISO") to other wholesale entities. The ISO tracks this data and reports it separately to the FERC. The Utility does not have access to this data. The ISO numbers reported in this column were derived by subtracting columns (e)-(i) from column (b).

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/17/2023

Year/Period of Report

End of:

2023

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report