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ferc:GasUtilityMember 2018-03-31 C000388 3-14 2017-12-31 C000388 0-6 2018-01-01 2018-03-31 C000388 0-2 2018-01-01 2018-03-31 C000388 3-4 2018-03-31 C000388 2-11 2018-01-01 2018-03-31 C000388 4-2 2018-01-01 2018-03-31 C000388 0-29 2018-03-31 C000388 0-14 2018-01-01 2018-03-31 C000388 4-9 2018-03-31 C000388 3-30 2017-12-31 C000388 0-35 2018-01-01 2018-03-31 C000388 0-37 2017-12-31 C000388 0-5 2018-03-31 C000388 0-25 2018-01-01 2018-03-31 C000388 1-28 2018-03-31 C000388 0-37 2018-03-31 C000388 ferc:ElectricUtilityMember ferc:HydraulicProductionPlantConventionalMember 2018-01-01 2018-03-31 C000388 0-31 2017-12-31 C000388 1-15 2017-12-31 C000388 0-1 2018-03-31 C000388 1-42 2018-01-01 2018-03-31 C000388 0-5 2018-01-01 2018-03-31 C000388 ferc:ElectricUtilityMember ferc:CommonPlantElectricMember 2018-01-01 2018-03-31 C000388 1-9 2018-03-31 C000388 0-18 2018-01-01 2018-03-31 C000388 1-11 2018-01-01 2018-03-31 C000388 0-40 2018-01-01 2018-03-31 C000388 0-34 2018-01-01 2018-03-31 C000388 4-35 2018-03-31 C000388 1-17 2018-03-31 C000388 0-50 2018-01-01 2018-03-31 C000388 0-27 2018-03-31 C000388 0-19 2017-12-31 C000388 4-23 2017-12-31 C000388 4-23 2018-03-31 C000388 4-34 2018-01-01 2018-03-31 C000388 0-19 2018-01-01 2018-03-31 C000388 0-21 2018-01-01 2018-03-31 C000388 4-13 2018-01-01 2018-03-31 C000388 4-25 2018-01-01 2018-03-31 C000388 0-7 2017-01-01 2017-03-31 C000388 3-41 2018-01-01 2018-03-31 C000388 1-29 2018-03-31 C000388 0-7 2018-01-01 2018-03-31 C000388 0-22 2017-12-31 C000388 1-27 2018-01-01 2018-03-31 C000388 3-12 2017-12-31 C000388 1-15 2018-03-31 C000388 ferc:OtherProductionPlantMember ferc:ElectricUtilityMember 2018-01-01 2018-03-31 C000388 1-3 2018-01-01 2018-03-31 C000388 3-3 2018-01-01 2018-03-31 C000388 0-18 2017-12-31 C000388 2-25 2018-01-01 2018-03-31 C000388 3-28 2018-03-31 C000388 1-27 2018-01-01 2018-03-31 C000388 0-23 2018-01-01 2018-03-31 C000388 0-54 2018-01-01 2018-03-31 C000388 1-17 2018-03-31 C000388 3-10 2017-12-31 C000388 0-40 2018-01-01 2018-03-31 C000388 1-23 2018-03-31 C000388 0-5 2018-01-01 2018-03-31 C000388 2-7 2017-12-31 C000388 0-6 2017-01-01 2017-03-31 C000388 1-9 2017-12-31 C000388 0-4 2018-01-01 2018-03-31 C000388 1-40 2017-12-31 C000388 1-3 2017-12-31 C000388 1-21 2017-12-31 C000388 2-41 2018-03-31 C000388 1-34 2018-03-31 C000388 0-25 2018-01-01 2018-03-31 C000388 0-19 2018-01-01 2018-03-31 C000388 0-18 2018-03-31 C000388 2-23 2018-01-01 2018-03-31 C000388 0-17 2017-12-31 C000388 0-25 2018-01-01 2018-03-31 C000388 0-20 2018-03-31 C000388 2-39 2018-01-01 2018-03-31 C000388 0-37 2018-01-01 2018-03-31 C000388 1-13 2018-01-01 2018-03-31 C000388 0-37 2018-01-01 2018-03-31 C000388 0-33 2018-01-01 2018-03-31 C000388 0-2 2018-01-01 2018-03-31 C000388 1-6 2018-01-01 2018-03-31 C000388 0-32 2018-01-01 2018-03-31 C000388 0-21 2018-03-31 C000388 4-17 2018-01-01 2018-03-31 C000388 4-29 2018-03-31 C000388 0-22 2018-01-01 2018-03-31 C000388 3-15 2018-01-01 2018-03-31 C000388 3-35 2018-01-01 2018-03-31 C000388 3-10 2018-01-01 2018-03-31 C000388 2-11 2017-12-31 C000388 4-9 2018-01-01 2018-03-31 C000388 2-42 2018-01-01 2018-03-31 C000388 2018-01-01 2018-03-31 C000388 3-28 2017-12-31 C000388 1-12 2017-12-31 C000388 0-30 2018-03-31 C000388 3-1 2018-01-01 2018-03-31 C000388 1-32 2018-01-01 2018-03-31 C000388 1-22 2018-01-01 2018-03-31 C000388 1-25 2017-12-31 C000388 3-40 2018-01-01 2018-03-31 C000388 2-26 2018-03-31 C000388 4-31 2018-03-31 C000388 3-2 2018-01-01 2018-03-31 C000388 0-25 2018-03-31 C000388 4-14 2018-01-01 2018-03-31 C000388 3-2 2017-12-31 C000388 0-39 2018-01-01 2018-03-31 C000388 0-16 2018-01-01 2018-03-31 C000388 0-9 2018-03-31 C000388 0-5 2017-12-31 C000388 2-15 2018-01-01 2018-03-31 C000388 2-1 2018-01-01 2018-03-31 C000388 4-21 2017-12-31 C000388 0-5 2018-01-01 2018-03-31 C000388 1-17 2018-01-01 2018-03-31 C000388 1-31 2018-03-31 C000388 4-15 2017-12-31 C000388 0-14 2018-01-01 2018-03-31 C000388 0-32 2018-03-31 C000388 3-14 2018-01-01 2018-03-31 C000388 0-21 2018-01-01 2018-03-31 C000388 2-14 2018-01-01 2018-03-31 C000388 0-48 2018-01-01 2018-03-31 C000388 0-9 2018-01-01 2018-03-31 C000388 0-20 2018-01-01 2018-03-31 C000388 ferc:CommonUtilityMember 2018-03-31 C000388 3-6 2018-03-31 C000388 1-10 2017-12-31 C000388 0-11 2018-01-01 2018-03-31 C000388 4-15 2018-01-01 2018-03-31 C000388 1-25 2018-01-01 2018-03-31 C000388 0-27 2018-01-01 2018-03-31 C000388 0-17 2018-01-01 2018-03-31 C000388 3-18 2018-01-01 2018-03-31 C000388 3-42 2017-12-31 C000388 ferc:ElectricUtilityMember 2018-03-31 C000388 2-27 2018-01-01 2018-03-31 C000388 2-20 2018-03-31 C000388 2-41 2017-12-31 C000388 1-29 2018-01-01 2018-03-31 C000388 3-26 2018-03-31 C000388 0-79 2018-01-01 2018-03-31 C000388 0-40 2018-01-01 2018-03-31 C000388 2-12 2018-01-01 2018-03-31 C000388 4-1 2017-12-31 C000388 4-27 2018-03-31 C000388 0-8 2018-01-01 2018-03-31 C000388 1-16 2018-01-01 2018-03-31 C000388 2-22 2018-01-01 2018-03-31 C000388 4-24 2018-01-01 2018-03-31 C000388 0-10 2018-03-31 C000388 3-32 2018-03-31 C000388 0-15 2017-12-31 C000388 0-33 2018-01-01 2018-03-31 C000388 3-42 2018-03-31 C000388 0-13 2017-12-31 pure utr:MWh utr:MW iso4217:USD
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
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:
2018
/
Q1


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

GENERAL INFORMATION

  1. 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.
  2. Who Must Submit

    Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees 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).
  3. What and Where to Submit

    1. Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site: http://www.ferc.gov/docs-filing/forms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet.
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
    3. 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
    4. 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:
      1. 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
      2. 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
    5. 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 for the year ended on which we have reported separately under date of , we have also reviewed 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.
    6. Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission’s website at http://www.ferc.gov/help/how-to.asp.
    7. 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 http://www.ferc.gov/docs-filing/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .
  4. 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).
  5. 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

  1. 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.
  2. 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.
  3. 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.
  4. 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.
  5. 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).
  6. 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.
  7. For any resubmissions, submit the electronic filing using the form submission software only. Please explain the reason for the resubmission in a footnote to the data field.
  8. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  9. 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.
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
  1. 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.
  2. 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:

  1. ’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;
  2. 'Person' means an individual or a corporation;
  3. '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;
  1. '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; ......
  1. "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
  1. '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.
  1. Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be 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 salt 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.
  1. 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:
2,018
/
Q1
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)

77 BEALE STREET, P.O. BOX 770000, SAN FRANCISCO, CA 94177
05 Name of Contact Person

SUSAN HUNTER
06 Title of Contact Person

SR. DIRECTOR, CORP ACCOUNTING
07 Address of Contact Person (Street, City, State, Zip Code)

77 BEALE STREET, P.O. BOX 770000, SAN FRANCISCO, CA 94177
08 Telephone of Contact Person, Including Area Code

(415) 973-5072
09 This Report is An Original / A Resubmission

(1)
An Original

(2)
A Resubmission
10 Date of Report (Mo, Da, Yr)

05/03/2018
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

DAVID THOMASON
02 Title

VP, CONTROLLER, UTILITY CFO
03 Signature

04 Date Signed (Mo, Da, Yr)

05/03/2018
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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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.

  1. 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.
  2. 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.
  3. 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.
  4. 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.
  5. 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.
  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 a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
  7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
  8. State the estimated annual effect and nature of any important wage scale changes during the year.
  9. 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.
  10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 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.
  11. (Reserved.)
  12. 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.
  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.
  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.

PACIFIC GAS AND ELECTRIC COMPANY

IMPORTANT CHANGES DURING THE YEAR

 

For the Quarter Ended March 31, 2018

 

 

 

1. Changes in and important additions to franchise rights:

There are no changes in or additions to PG&E’s franchise rights.

 

  1. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies:

 

None.

 

  1. Purchase or sale of an operating unit or system:

 

Sale:

 

None.

 

Purchase:

 

None.

  1. Important leaseholds that have been acquired or given, assigned or surrendered:

None.

 

  1. Important extension or reduction of transmission or distribution system:

 

Electric:

 

On February 15, 2018, the Midway Fault Duty Mitigation Project was released to operations. This project, located in Kern County, installed 9 ohm series reactors at the 230 kV side of Midway 500/230 kV Transformer Banks 11, 12, and 13. This project was built to mitigate excessive fault duty, which was projected to increase beyond the specified sale limits as a result of various generation interconnection projects at Midway Substation.

Gas:

 

None.

 

 

  1. 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:

 

 

  1. Financings:

 

None.

 

  1. Bank Credit Facilities:

 

At March 31, 2018, the Utility had $48 million of letters of credit outstanding, $97 million of commercial paper outstanding, and no borrowings under its $3 billion revolving credit facility.

On February 23, 2018, the Utility closed a $250 million 364-day term loan.

Short-term borrowings are authorized by CPUC Decision No. 09-05-002.

  1. Surety Bonds and Financial Guarantees Backed by Insurance:

 

From January 1, 2018 to March 31, 2018, $35,383,247.48 in surety bond obligations were issued in conformance with the CPUC Decision No. 12-04-015. As of March 31, 2018, there was a total of $117,554,151.68 in long-term surety bond obligations outstanding.

 

  1. 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 March 31, 2018, the Utility has no outstanding future capital commitments to unregulated subsidiaries and affiliates.

  1. Preferred stock repayments:

 

None.

  1. Changes in articles of incorporation or amendments to charter. Explain the nature and purpose of such changes or amendments:

 

None.

 

 

  1. State the estimated annual effect and nature of any important wage scale changes during the period:

 

As provided for in labor agreements with the International Brotherhood of Electrical Workers (“IBEW”), Local 1245, representing a majority of the Utility’s employees in physical and clerical classifications; the Engineers and Scientists of California (“ESC”), representing certain Utility employees in the technical and engineering classifications; and the Service Employees International Union (“SEIU”), representing certain Utility security officers at Diablo Canyon Nuclear Power Plant, the following general wage increases were granted effective January 1, 2018:

IBEW Clerical classifications                          3.25%

IBEW Physical classifications                          3.25%

ESC non-exempt and some exempt classifications         3.50%

ESC other exempt classifications                       3.50%

SEIU classifications                                   3.25%

The full annual cost of the above general wage increase is approximately $50 million.

  1. 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 Note 9 of the Notes to the Financial Statements on page 123 of the FERC Form 3-Q, which discusses materially important pending legal matters.

Further, 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, 2017, 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 quarter ended March 31, 2018, for the status of materially important legal proceedings pending or completed as of the end of the period.

 

  1. 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 first quarter of 2018, three beneficial owners of at least 5 percent of PG&E Corporation common stock as of December 31, 2017 provided asset management services to PG&E Corporation, Pacific Gas and Electric Company (“Utility”), and related entities: BlackRock, Inc. ("BlackRock"), T. Rowe Price Associates Inc. (“Price Associates”), and the Vanguard Group (“Vanguard”). Specifically, these entities provided asset management services to various trusts associated with PG&E Corporation’s and the Utility’s employee benefit plans, to the Utility's nuclear decommissioning trusts, to the trusts securing benefits in the event of a change in control, and the PG&E Corporation Foundation. In each of these cases (with the exception of Vanguard), the services were initiated before the entity became a 5 percent shareholder. 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.

During 2018, each of these parties is expected to provide services in excess of the $120,000 disclosure threshold set forth in SEC Reg. S-K, Item 404(a).

“Immediate Family Members”

Kathy Thomason is employed by the Utility as a Business Finance Analyst, Expert. She is the wife of David Thomason, who is Vice President, Chief Financial Officer, and Controller of the Utility and an executive officer of the Utility. Ms. Thomason is, therefore, an “immediate family member” for purposes of SEC related person transaction disclosure rules. While Ms. Thomason is employed with the Utility, she will receive salary, short-term incentive awards, and other cash compensation and benefits consistent with the Utility’s standard compensation practices and policies.

We expect that the value of payments to Ms. Thomason for the period January 2018 through March 2019 (assuming she remains employed with the Utility during that period) will be close to the $120,000 disclosure threshold set forth in SEC Reg S-K. Item 404(a).

  1. (Reserved)

 

  1. 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 to 1 to 11 above, such notes may be included on this page.

 

Not applicable.

 

  1. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period:

 

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 9,556,157 shares as of December 31, 2017 to 9,578,384 shares as of March 31, 2018. (Approximately 93 percent of the total preferred shares outstanding).

 

Dividend Payments

Refer to Note 5, Equity, of the Notes to Financial Statements on page 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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
81,810,282,198
81,000,792,691
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200
2,562,191,365
2,470,588,868
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Enter Total of lines 2 and 3)
84,372,473,563
83,471,381,559
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
200
36,139,391,382
35,680,789,356
6
UtilityPlantNet
Net Utility Plant (Enter Total of line 4 less 5)
48,233,082,181
47,790,592,203
7
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
202
165,239,458
261,763,030
8
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9
NuclearFuelAssembliesInReactorMajorOnly
Nuclear Fuel Assemblies in Reactor (120.3)
425,140,996
416,084,176
10
SpentNuclearFuelMajorOnly
Spent Nuclear Fuel (120.4)
2,359,998,526
2,265,141,307
11
NuclearFuelUnderCapitalLeases
Nuclear Fuel Under Capital Leases (120.6)
12
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
202
2,529,206,782
2,505,050,242
13
NuclearFuelNet
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
421,172,198
437,938,271
14
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Enter Total of lines 6 and 13)
48,654,254,379
48,228,530,474
15
OtherElectricPlantAdjustments
Utility Plant Adjustments (116)
16
GasStoredUndergroundNoncurrent
Gas Stored Underground - Noncurrent (117)
55,907,325
55,907,325
17
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
18
NonutilityProperty
Nonutility Property (121)
30,957,020
30,929,381
19
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Prov. for Depr. and Amort. (122)
20
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
21
InvestmentInSubsidiaryCompanies
Investment in Subsidiary Companies (123.1)
224
48,461,233
48,859,887
23
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
228
(a)
304,420,902
(e)
195,017,512
24
OtherInvestments
Other Investments (124)
10,942
10,942
25
SinkingFunds
Sinking Funds (125)
26
DepreciationFund
Depreciation Fund (126)
27
AmortizationFundFederal
Amortization Fund - Federal (127)
28
OtherSpecialFunds
Other Special Funds (128)
2,842,039,266
2,863,247,030
29
SpecialFunds
Special Funds (Non Major Only) (129)
552,231,522
553,022,543
30
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
(b)
97,370,694
(f)
102,130,395
31
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
32
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
3,875,491,579
3,793,217,690
33
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
34
CashAndWorkingFunds
Cash and Working Funds (Non-major Only) (130)
35
Cash
Cash (131)
118,853,109
57,718,289
36
SpecialDeposits
Special Deposits (132-134)
6,811,261
6,951,064
37
WorkingFunds
Working Fund (135)
146,555
146,305
38
TemporaryCashInvestments
Temporary Cash Investments (136)
385,000,000
39
NotesReceivable
Notes Receivable (141)
40
CustomerAccountsReceivable
Customer Accounts Receivable (142)
1,340,158,384
1,368,326,668
41
OtherAccountsReceivable
Other Accounts Receivable (143)
935,962,485
1,294,343,299
42
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
58,801,948
64,476,202
43
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
44
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Assoc. Companies (146)
26,853,161
21,355,991
45
FuelStock
Fuel Stock (151)
227
1,456,406
1,375,066
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
373,578,968
365,624,133
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
542,285,091
419,851,065
53
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
228
(c)
304,420,902
(g)
195,017,512
54
StoresExpenseUndistributed
Stores Expense Undistributed (163)
227
55
GasStoredCurrent
Gas Stored Underground - Current (164.1)
77,770,222
113,465,206
56
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57
Prepayments
Prepayments (165)
223,630,108
227,100,005
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)
850,628,963
945,999,103
62
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
61,151,005
14,376,070
63
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
124,896,962
129,373,589
64
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
(d)
97,370,694
(h)
102,130,395
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)
4,223,589,136
4,989,381,744
68
DeferredDebitsAbstract
DEFERRED DEBITS
69
UnamortizedDebtExpense
Unamortized Debt Expenses (181)
127,770,059
131,251,529
70
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230a
71
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230b
69,362,073
3,683,889
72
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
5,092,767,084
5,018,800,793
73
PreliminarySurveyAndInvestigationCharges
Prelim. Survey and Investigation Charges (Electric) (183)
141,631
82,918
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)
4,356,080
3,237,868
77
TemporaryFacilities
Temporary Facilities (185)
78
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
49,816,379
55,551,664
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)
107,282,815
97,418,150
82
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234
2,204,934,915
1,728,161,422
83
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
84
DeferredDebits
Total Deferred Debits (lines 69 through 83)
7,656,431,036
7,038,188,233
85
AssetsAndOtherDebits
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
64,465,673,455
64,105,225,466


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: c, Value: 0
(b) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: c, Value: 0
(c) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: c, Value: 0
(d) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: c, Value: 0
(e) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: d, Value: 0
(f) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: d, Value: 0
(g) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: d, Value: 0
(h) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: d, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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
6,735,547,928
6,735,547,928
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
10,161,810,977
9,712,977,993
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118
(a)
56,608,615
(b)
56,608,615
13
ReacquiredCapitalStock
(Less) Reaquired Capital Stock (217)
250
14
NoncorporateProprietorship
Noncorporate Proprietorship (Non-major only) (218)
15
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
122(a)(b)
6,440,579
6,290,667
16
ProprietaryCapital
Total Proprietary Capital (lines 2 through 15)
20,196,384,934
19,747,402,038
17
LongTermDebtAbstract
LONG-TERM DEBT
18
Bonds
Bonds (221)
256
17,631,788,750
18,032,100,000
19
ReacquiredBonds
(Less) Reaquired Bonds (222)
256
20
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256
21
OtherLongTermDebt
Other Long-Term Debt (224)
256
22
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
13,962,293
14,860,769
23
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
78,573,747
80,156,440
24
LongTermDebt
Total Long-Term Debt (lines 18 through 23)
17,567,177,296
17,966,804,329
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases - Noncurrent (227)
13,123,878
17,990,411
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
893,248,356
1,003,439,991
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
1,989,990,540
2,025,769,027
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
1,138,869,659
1,039,213,260
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
56,085,128
57,007,082
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
4,945,998,774
4,899,104,864
35
OtherNoncurrentLiabilities
Total Other Noncurrent Liabilities (lines 26 through 34)
9,037,316,335
9,042,524,635
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
NotesPayable
Notes Payable (231)
847,170,001
800,000,001
38
AccountsPayable
Accounts Payable (232)
2,185,874,566
2,402,987,144
39
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
40
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
50,359,041
22,050,491
41
CustomerDeposits
Customer Deposits (235)
245,030,694
231,822,866
42
TaxesAccrued
Taxes Accrued (236)
262
581,127,687
433,396,782
43
InterestAccrued
Interest Accrued (237)
151,162,872
220,498,682
44
DividendsDeclared
Dividends Declared (238)
5,798,466
2,319,386
45
MaturedLongTermDebt
Matured Long-Term Debt (239)
46
MaturedInterest
Matured Interest (240)
47
TaxCollectionsPayable
Tax Collections Payable (241)
31,010,401
34,679,077
48
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
527,171,071
692,014,936
49
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
3,894,575
12,512,046
50
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
86,503,602
88,095,705
51
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
56,085,128
57,007,082
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)
4,659,017,848
4,883,370,034
55
DeferredCreditsAbstract
DEFERRED CREDITS
56
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
413,040,184
423,431,367
57
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
266
112,621,313
114,033,790
58
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
59
OtherDeferredCredits
Other Deferred Credits (253)
269
210,639,011
208,094,334
60
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
3,934,000,632
(c)
3,876,105,498
61
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reaquired Debt (257)
826,413
862,920
62
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accum. Deferred Income Taxes-Accel. Amort.(281)
272
307
307
63
AccumulatedDeferredIncomeTaxesOtherProperty
Accum. Deferred Income Taxes-Other Property (282)
7,769,847,464
7,394,379,151
64
AccumulatedDeferredIncomeTaxesOther
Accum. Deferred Income Taxes-Other (283)
564,801,718
448,217,063
65
DeferredCredits
Total Deferred Credits (lines 56 through 64)
13,005,777,042
12,465,124,430
66
LiabilitiesAndOtherCredits
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
64,465,673,455
64,105,225,466


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 53, Column: c, Value: 0
(b) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 49, Column: c, Value: 0
(c) Concept: OtherRegulatoryLiabilities
Duplicate fact discrepancy. Schedule: 278 - Schedule - Other Regulatory Liabilities (Account 254), Row: 41, Column: b, Value: 3876105497

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
STATEMENT OF INCOME

Quarterly

  1. 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.
  2. 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.
  3. 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.
  4. 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.
  5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if applicable

  1. Do not report fourth quarter data in columns (e) and (f)
  2. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin 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.
  3. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
  4. Use page 122 for important notes regarding the statement of income for any account thereof.
  5. 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.
  6. 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 purches, and a summary of the adjustments made to balance sheet, income, and expense accounts.
  7. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
  8. 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.
  9. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  10. 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)(b)
4,125,552,123
4,333,372,715
(e)(f)
4,125,552,123
4,333,372,715
2,964,194,544
3,078,654,563
1,161,357,579
1,254,718,152
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
320
2,108,532,841
2,135,853,350
2,108,532,841
2,135,853,350
1,484,173,953
1,452,306,850
624,358,888
683,546,500
5
MaintenanceExpense
Maintenance Expenses (402)
320
308,785,457
376,090,618
308,785,457
376,090,618
193,169,329
268,820,831
115,616,128
107,269,787
6
DepreciationExpense
Depreciation Expense (403)
336
676,864,997
618,963,462
676,864,997
618,963,462
534,385,977
485,387,840
142,479,020
133,575,622
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336
83,384,982
92,691,541
83,384,982
92,691,541
57,768,093
66,384,025
25,616,889
26,307,516
9
AmortizationOfElectricPlantAcquisitionAdjustments
Amort. of Utility Plant Acq. Adj. (406)
336
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
8,360,503
68,611
8,360,503
68,611
8,360,503
68,611
11
AmortizationOfConversionExpenses
Amort. of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262
167,036,384
158,004,933
167,036,384
158,004,933
121,661,789
118,667,205
45,374,595
39,337,728
15
IncomeTaxesOperatingIncome
Income Taxes - Federal (409.1)
262
1
1
1
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes - Other (409.1)
262
41,756,046
36,117,762
41,756,046
36,117,762
4,454,033
2,738,715
37,302,013
38,856,477
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision for Deferred Income Taxes (410.1)
234, 272
16,693,572
95,437,845
16,693,572
95,437,845
31,463,982
93,281,404
14,770,410
2,156,441
18
ProvisionForDeferredIncomeTaxesCreditOperatingIncome
(Less) Provision for Deferred Income Taxes-Cr. (411.1)
234, 272
21,366,830
20,820,785
21,366,830
20,820,785
24,851,105
7,634,102
3,484,275
13,186,683
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adj. - Net (411.4)
266
20
GainsFromDispositionOfPlant
(Less) Gains from Disp. of Utility Plant (411.6)
704
16,787
704
16,787
704
16,787
21
LossesFromDispositionOfServiceCompanyPlant
Losses from Disp. of Utility Plant (411.7)
270,726
270,726
270,726
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)
3,416,059,903
3,534,302,846
3,416,059,903
3,534,302,846
2,443,567,055
2,490,066,092
972,492,848
1,044,236,754
27
NetUtilityOperatingIncome
Net Util Oper Inc (Enter Tot line 2 less 25)
709,492,220
799,069,869
709,492,220
799,069,869
520,627,489
588,588,471
188,864,731
210,481,398
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)
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
(c)
10,330
(d)
50,584
(g)
10,330
(h)
50,584
37
InterestAndDividendIncome
Interest and Dividend Income (419)
8,628,752
5,147,440
8,628,752
5,147,440
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
32,107,672
18,976,650
32,107,672
18,976,650
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
347
347
41
OtherIncome
TOTAL Other Income (Enter Total of lines 31 thru 40)
40,726,441
24,174,674
40,726,441
24,174,674
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
13,632
26,000
13,632
26,000
46
LifeInsurance
Life Insurance (426.2)
47
Penalties
Penalties (426.3)
149,236
1,359,694
149,236
1,359,694
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Exp. for Certain Civic, Political & Related Activities (426.4)
2,508,502
2,067,513
2,508,502
2,067,513
49
OtherDeductions
Other Deductions (426.5)
109,774,025
67,511,733
109,774,025
67,511,733
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
112,445,395
70,964,940
112,445,395
70,964,940
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262
91,677
89,652
91,677
89,652
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262
10,911,178
8,013,391
10,911,178
8,013,391
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Inc. Taxes (410.2)
234, 272
4,039,758
5,526,192
4,039,758
5,526,192
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
234, 272
23,292,178
29,232,291
23,292,178
29,232,291
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adj.-Net (411.5)
1,412,477
992,904
1,412,477
992,904
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
31,484,398
32,622,742
31,484,398
32,622,742
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
40,234,556
14,167,524
40,234,556
14,167,524
61
InterestChargesAbstract
Interest Charges
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
196,860,242
199,233,506
196,860,242
199,233,506
63
AmortizationOfDebtDiscountAndExpense
Amort. of Debt Disc. and Expense (428)
6,865,857
6,754,734
6,865,857
6,754,734
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reaquired Debt (428.1)
5,095,708
4,671,446
5,095,708
4,671,446
65
AmortizationOfPremiumOnDebtCredit
(Less) Amort. of Premium on Debt-Credit (429)
261,161
516,897
261,161
516,897
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
36,506
36,506
36,506
36,506
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Assoc. Companies (430)
68
OtherInterestExpense
Other Interest Expense (431)
21,513,241
13,658,525
21,513,241
13,658,525
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
13,091,780
8,126,137
13,091,780
8,126,137
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
216,945,601
215,638,671
216,945,601
215,638,671
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
452,312,063
569,263,674
452,312,063
569,263,674
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)
452,312,063
569,263,674
452,312,063
569,263,674


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: OperatingRevenues

See footnote in row 2, column (c)

(b) Concept: OperatingRevenues

Includes interdepartmental operating revenues in Line 2 and

operations expenses in Line 4 for the three-month period ended March 31:

 

 

 

 

 

 

2018

2017

 

Revenues

Expenses

Revenues

Expenses

Electric

8,832,885

17,796,146

7,957,772

15,263,017

Gas

56,328,785

47,365,524

50,921,542

43,616,297

Total

65,161,670

65,161,670

58,879,314

58,879,314

(c) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: c, Value: 0
(d) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: d, Value: 0
(e) Concept: OperatingRevenues

See footnote in row 2, column (c)

(f) Concept: OperatingRevenues

Includes interdepartmental operating revenues in Line 2 and

operations expenses in Line 4 for the three-month period ended March 31:

 

 

 

 

 

 

2018

2017

 

Revenues

Expenses

Revenues

Expenses

Electric

8,832,885

17,796,146

7,957,772

15,263,017

Gas

56,328,785

47,365,524

50,921,542

43,616,297

Total

65,161,670

65,161,670

58,879,314

58,879,314

(g) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: c, Value: 0
(h) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: d, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report


End of:
2018
/
Q1
STATEMENT OF RETAINED EARNINGS
  1. Do not report Lines 49-53 on the quarterly report.
  2. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  3. 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).
  4. State the purpose and amount for each reservation or appropriation of retained earnings.
  5. 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.
  6. Show dividends for each class and series of capital stock.
  7. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings.
  8. 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.
  9. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122-123.
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
9,450,613,073
8,576,546,935
2
ChangesAbstract
Changes
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
4
AdjustmentsToRetainedEarningsCreditAbstract
Adjustments to Retained Earnings Credit
4.1
AdjustmentsToRetainedEarningsCredit
4.2
AdjustmentsToRetainedEarningsCredit
4.3
AdjustmentsToRetainedEarningsCredit
4.4
AdjustmentsToRetainedEarningsCredit
4.5
AdjustmentsToRetainedEarningsCredit
4.6
AdjustmentsToRetainedEarningsCredit
4.7
AdjustmentsToRetainedEarningsCredit
4.8
AdjustmentsToRetainedEarningsCredit
4.9
AdjustmentsToRetainedEarningsCredit
4.10
AdjustmentsToRetainedEarningsCredit
9
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Acct. 439)
10
AdjustmentsToRetainedEarningsDebitAbstract
Adjustments to Retained Earnings Debit
10.1
AdjustmentsToRetainedEarningsDebit
10.2
AdjustmentsToRetainedEarningsDebit
10.3
AdjustmentsToRetainedEarningsDebit
10.4
AdjustmentsToRetainedEarningsDebit
10.5
AdjustmentsToRetainedEarningsDebit
10.6
AdjustmentsToRetainedEarningsDebit
10.7
AdjustmentsToRetainedEarningsDebit
10.8
AdjustmentsToRetainedEarningsDebit
10.9
AdjustmentsToRetainedEarningsDebit
10.10
AdjustmentsToRetainedEarningsDebit
15
AdjustmentsToRetainedEarningsDebit
TOTAL Debits to Retained Earnings (Acct. 439)
16
BalanceTransferredFromIncome
Balance Transferred from Income (Account 433 less Account 418.1)
452,312,063
569,263,674
17
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Acct. 436)
17.1
AppropriationsOfRetainedEarnings
17.2
AppropriationsOfRetainedEarnings
Reserves for excess earnings on FERC hydroelectric
17.3
AppropriationsOfRetainedEarnings
project licenses pursuant to Federal Power Act Section 10 (d)
588,299
17.4
AppropriationsOfRetainedEarnings
22
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Acct. 436)
588,299
23
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
23.1
DividendsDeclaredPreferredStock
23.2
DividendsDeclaredPreferredStock
Preferred Stock Dividends Declared
(e)
3,479,089
23.3
DividendsDeclaredPreferredStock
23.4
DividendsDeclaredPreferredStock
Accrued Preferred Dividend Requirement
(a)
3,479,079
23.5
DividendsDeclaredPreferredStock
29
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
3,479,079
3,479,089
30
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
30.1
DividendsDeclaredCommonStock
30.2
DividendsDeclaredCommonStock
Common Stock Dividends Declared
(f)
244,000,000
30.3
DividendsDeclaredCommonStock
30.4
DividendsDeclaredCommonStock
30.5
DividendsDeclaredCommonStock
36
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Acct. 438)
244,000,000
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)
9,899,446,057
8,898,919,819
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
.1
AppropriatedRetainedEarnings
.2
AppropriatedRetainedEarnings
.3
AppropriatedRetainedEarnings
.4
AppropriatedRetainedEarnings
Reserves for excess earnings on FERC hydroelectric
.5
AppropriatedRetainedEarnings
project licenses pursuant to Federal Power Act Section 10 (d)
.6
AppropriatedRetainedEarnings
.7
AppropriatedRetainedEarnings
.8
AppropriatedRetainedEarnings
.9
AppropriatedRetainedEarnings
.10
AppropriatedRetainedEarnings
.11
AppropriatedRetainedEarnings
.12
AppropriatedRetainedEarnings
.13
AppropriatedRetainedEarnings
.14
AppropriatedRetainedEarnings
45
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215)
588,299
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
262,364,920
238,586,547
47
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
262,364,920
237,998,248
48
RetainedEarnings
TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
10,161,810,977
9,136,918,067
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
(b)
56,608,615
50
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
(c)
10,330
(g)
50,584
51
DividendsReceived
(Less) Dividends Received (Debit)
52
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
53
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year (Total lines 49 thru 52)
(d)
56,608,615


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report


End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: DividendsDeclaredPreferredStock

There were no preferred dividends declared for the quarter ended March 31,2018. However, since preferred stocks are cumulative, a preferred dividend accrual was recorded. The liability is shown in Line 44, Dividends Declared, on page 112 of the balance sheet.

 

The following is the detail of accrued dividends on First Preferred Stocks for the first quarter ended March 31, 2018:

 

Annual

No. of Dividends Total

Class of Stock Shares Per Share Accrued

 

6.00% Cumulative, Non-Redeemable 4,211,662 $1.500 $ 1,579,373

5.50% Cumulative, Non-Redeemable 1,173,163 1.375 403,275

5.00% Cumulative, Non-Redeemable 400,000 1.250 125,000

5.00% Cumulative, Redeemable 1,778,172 1.250 555,679

5.00% Cumulative, Redeemable - Series A 934,322 1.250 291,975

4.80% Cumulative, Redeemable 793,031 1.200 237,909

4.50% Cumulative, Redeemable 611,142 1.125 171,884

4.36% Cumulative, Redeemable 418,291 1.090 113,984

-----------

Total $ 3,479,079

===========

 

 

(b) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 49, Column: c, Value: 0
(c) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: c, Value: 0
(d) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 53, Column: c, Value: 0
(e) Concept: DividendsDeclaredPreferredStock

The following is the detail of dividends declared on First Preferred Stocks for the first quarter ended March 31, 2017:

 

Annual

No. of Dividends Total

Class of Stock Shares Per Share Declared

 

6.00% Cumulative, Non-Redeemable 4,211,662 $1.500 $ 1,579,378

5.50% Cumulative, Non-Redeemable 1,173,163 1.375 403,276

5.00% Cumulative, Non-Redeemable 400,000 1.250 125,000

5.00% Cumulative, Redeemable 1,778,172 1.250 555,680

5.00% Cumulative, Redeemable - Series A 934,322 1.250 291,977

4.80% Cumulative, Redeemable 793,031 1.200 237,909

4.50% Cumulative, Redeemable 611,142 1.125 171,884

4.36% Cumulative, Redeemable 418,291 1.090 113,985

-----------

Total $ 3,479,089

===========

 

(f) Concept: DividendsDeclaredCommonStock

This represents dividends declared on Common Stock to PG&E Corporation for the quarter ended March 31, 2017.

(g) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 50, Column: d, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
STATEMENT OF CASH FLOWS
  1. 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.
  2. 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.
  3. 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.
  4. 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)
452,312,063
569,263,674
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
751,889,476
711,723,614
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Unamortized Loss or Gain on Reacquired Debt
5,059,201
5,980,335
5.2
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Expenses, Discount and Premium - Long Term Debt
4,561,197
2,272,815
8
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
23,117,653
264,297,702
9
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustment (Net)
1,412,477
992,904
10
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(a)
463,045,088
(n)
311,333,244
11
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(b)
27,658,809
(o)
1,660,227
12
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
13
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
145,935,755
136,286,310
14
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(c)
78,082,201
(p)
270,695,542
15
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
179,087,402
95,820,227
16
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
32,107,672
18,976,650
17
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
398,654
320,532
18
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other (provide details in footnote):
18.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (provide details in footnote):
(d)
426,305,168
(q)
210,840,140
22
NetCashFlowFromOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
1,515,157,780
1,594,132,990
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)
(e)
1,493,781,996
(r)
1,225,822,656
27
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
(f)
7,390,467
(s)
9,316,747
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
(g)
32,107,672
(t)
18,976,650
31
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other (provide details in footnote):
34
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 26 thru 33)
(h)
1,469,064,791
(u)
1,216,162,753
36
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
37
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
6,497,024
6,709,640
39
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Assoc. and Subsidiary Companies
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
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 Advances by Assoc. and Subsidiary Companies
376,390
950,060
53.2
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Net (Increase) Decrease in Restricted Cash
139,803
7,826
53.3
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Proceeds from nuclear decommissioning trust sales
492,884,185
469,826,062
53.4
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Purchases of nuclear decommissioning trust investments and Other
505,430,761
493,414,944
57
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
1,475,350,930
1,232,099,761
59
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
60
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
61
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Long-Term Debt (b)
589,732,446
62
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Preferred Stock
63
ProceedsFromIssuanceOfCommonStockFinancingActivities
Common Stock
64
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other (provide details in footnote):
66
NetIncreaseInShortTermDebt
Net Increase in Short-Term Debt (c)
47,022,163
755,154,864
67
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
67.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Equity contribution from PG&E Corporation
125,000,000
70
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total 61 thru 69)
47,022,163
40,422,418
72
PaymentsForRetirementAbstract
Payments for Retirement of:
73
PaymentsForRetirementOfLongTermDebtFinancingActivities
Long-term Debt (b)
(i)
400,000,000
74
PaymentsForRetirementOfPreferredStockFinancingActivities
Preferred Stock
75
PaymentsForRetirementOfCommonStockFinancingActivities
Common Stock
76
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Customer Advances for Construction
(j)
6,364,586
(v)
22,806,880
76.2
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other
(k)(l)
17,058,529
(w)(x)
62,066,407
78
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
80
DividendsOnPreferredStock
Dividends on Preferred Stock
3,479,089
81
DividendsOnCommonStock
Dividends on Common Stock
244,000,000
83
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
363,671,780
372,774,794
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)
323,864,930
10,741,565
88
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
442,864,594
68,401,200
90
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
(m)
118,999,664
(y)
57,659,635


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 463045088
(b) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: 27658809
(c) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -78082201
(d) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

This consists of the following:

 

2018 2017

 

(Increase) Decrease in Other Working Capital $ (266,363,419) $ (297,088,352)

Increase (Decrease) - Other Noncurrent Liabilities (76,054,210) 29,758,566

Others

Nuclear Fuel Lease Amortization 24,156,540 32,178,619

Payment on capital lease obligation (1,966,873) (1,894,608)

Derivative Instrument (9,315,213) (2,128,828)

Bad Debt Expense 7,702,726 15,778,709

Tax benefit on stock option exercises (11,457,638) 23,956,632

Other-net* (93,007,081) (11,400,878) -------------- --------------

Total $ (426,305,168) $ (210,840,140)

============== ==============

 

 

*This primarily consists of allowances related to GHG.

(e) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -1493781996
(f) Concept: GrossAdditionsToNuclearFuelInvestingActivities
Original value: -7390467
(g) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -32107672
(h) Concept: CashOutflowsForPlant
Original value: -1469064791
(i) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -400000000
(j) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: 6364586
(k) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -17058529
(l) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

This consists of the following:

 

2018 2017

 

Increase (Decrease) in customer deposits 7,944,358 2,594,439

Debt Issuance Costs - ST borrowings (25,000) 0

Employee taxes paid for withheld shares (9,829,758) (64,660,846)

Premium paid for early redemption of long-term debt (15,148,129) 0

-------------- --------------

Total $ (17,058,529) $ (62,066,407) ============== ==============

 

(m) Concept: CashAndCashEquivalents

This consists of the following:

 

2018 2017

 

Cash (131) $ 118,853,109 $ 57,513,630

Working Funds (135) 146,555 146,005

-------------- --------------

Total $ 118,999,664 $ 57,659,635

============== ==============

 

 

Supplemental disclosures of cash flow information (in millions):

 

Cash received (paid) for:

Interest (net of amounts capitalized) $ (259) $ (242)

Supplemental disclosures of noncash investing and financing activities:

 

Capital expenditures financed through

accounts payable 255 237

Terminated capital leases 137 -

(n) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 311333244
(o) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -1660227
(p) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -270695542
(q) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

See footnote in Column B, Line 18.

(r) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -1225822656
(s) Concept: GrossAdditionsToNuclearFuelInvestingActivities
Original value: -9316747
(t) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -18976650
(u) Concept: CashOutflowsForPlant
Original value: -1216162753
(v) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -22806880
(w) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

See footnote in Column B, Line 79.

(x) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -62066407
(y) 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
NOTES TO FINANCIAL STATEMENTS
  1. 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.
  2. 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.
  3. 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 Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
  4. 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.
  5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  6. 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.
  7. 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.
  8. 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.
  9. 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 March 31, 2018, as filed with the Securities and Exchange Commission (“SEC”) on May 3, 2018.  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 3-Q 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 to/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 for FERC reporting, (11) Stranded tax reclass amounts from Accumulated Other Comprehensive Income to Retained Earnings pursuant to ASU 2018-02, and (12) FERC reporting does not reclass non-service costs related to pension benefits on the income statement pursuant to ASU 2017-07.

 

Subsequent Events:

 

Management has evaluated the impact of events occurring after March 31, 2018 up to May 3, 2018, 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 May 3, 2018. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

 

Energy Storage Assets (FERC Order No. 784):

 

The following disclosure has been included to comply with accounting and reporting guidance issued by the FERC for new electric storage technologies as a result of FERC Order No. 784.

 

Energy Plant Account

 

Energy storage assets totaled $32,142,500 at March 31, 2018, all of which is recorded in account 363 in accordance with FERC Order No. 784.

 

Power Purchased Account

 

Energy storage-related purchased power costs totaled ($58,374) for the quarter ended March 31, 2018, all of which is recorded in account 555.1 in accordance with FERC Order No. 784.

 

Operation and Maintenance Expense Accounts

 

Energy storage-related operating expenses totaled $0 for the quarter ended March 31, 2018, of which $0 is recorded in account 582 and $0 is recorded in account 588.  Amounts associated with distribution functional use would have been recorded in account 584.1 and amounts associated with production functional use would have been recorded in account 548.1, in accordance with FERC Order No. 784. Please see table below.

 

Energy storage-related maintenance expenses totaled $16,360 for the quarter ended March 31, 2018, of which $0 is recorded in account 570 and $16,360 is recorded in account 592.  Amounts associated with distribution functional use would have been recorded in account 592.2 and amounts associated with production functional use would have been recorded in account 553.1, in accordance with FERC Order No. 784. Please see table below.

Other Expense Accounts

 

Energy storage-related employee pension and benefits expenses are recorded in account 926 in the amount of $0.

 

Energy storage-related payroll tax expenses are recorded in account 408.1 in the amount of $0.   

 

The following information to be reported in the newly adopted schedule pages 419-420 can be submitted as part of pages 122-123:

 

Energy Storage Operations (Small Plants)

Line no.

Name of Energy Storage Project

Functional classification

Location of the Project

Project Cost

Operations (Excluding Fuel used in Storage Operations)

Maintenance

Cost of fuel used in storage operations

Account No. 555.1, Power Purchased for Storage Operations

Other Expenses

1

Vaca-Dixon

Production

 

Vacaville, CA

$11,286,007

 

$0

 

 

$2,062

 

$0

($58,374)

 

 

$0

2

Hitachi

Distribution

San Jose, CA

$20,856,493

 

$0

 

$13,733

 

$0

$0

$0

 

3

Browns Valley

Distribution

Marysville, CA

$0

$0

$565

$0

$0

$0

Totals

$32,142,500

$0

$16,360

$0

($58,374)

$0

 

 

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

 

NOTE 1: 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 (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 2017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2017 Form 10-K.  This quarterly report should be read in conjunction with the 2017 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, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other post-retirement benefit plans 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 and results of operations during the period in which such change occurred.

 

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “Northern California wildfires”).  According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires also resulted in 44 fatalities. The Northern California wildfires are under investigation by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed. Further, the CPUC's SED is conducting investigations to assess the compliance of electric and communication companies' facilities with applicable rules and regulations in fire-impacted areas. See "Northern California Wildfires" in Note 9 below. 

 

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

 

Variable Interest Entities

 

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

 

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 has a controlling interest or was the primary beneficiary of any of these VIEs at March 31, 2018, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at March 31, 2018, it did not consolidate any of them.

 

Pension and Other Post-Retirement Benefits

 

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

 

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2018 and 2017 were as follows:

 

Pension Benefits

 

Other Benefits

 

Three Months Ended March 31,

(in millions)

2018

 

2017

 

2018

 

2017

Service cost for benefits earned

$

128

 

 

$

118

 

 

$

16

 

 

$

15

 

Interest cost

172

 

 

179

 

 

17

 

 

19

 

Expected return on plan assets

(255

)

 

(193

)

 

(33

)

 

(24

)

Amortization of prior service cost

(1

)

 

(2

)

 

4

 

 

4

 

Amortization of net actuarial loss

1

 

 

6

 

 

(1

)

 

1

 

Net periodic benefit cost

45

 

 

108

 

 

3

 

 

15

 

Regulatory account transfer (1)

39

 

 

(23

)

 

 

 

 

Total

$

84

 

 

$

85

 

 

$

3

 

 

$

15

 

 

 

 

 

 

 

 

 

(1) 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.

 

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) are summarized below:

 

Pension
Benefits

 

Other
Benefits

 

Total

(in millions, net of income tax)

Three Months Ended March 31, 2018

Beginning balance

$

(25

)

 

$

17

 

 

$

(8

)

Amounts reclassified from other comprehensive income:

 

 

 

 

 

Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1)

(1

)

 

3

 

 

2

 

Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1)

1

 

 

(1

)

 

 

Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)

 

 

(2

)

 

(2

)

Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively)

(5

)

 

 

 

(5

)

Net current period other comprehensive gain (loss)

(5

)

 

 

 

(5

)

Ending balance

$

(30

)

 

$

17

 

 

$

(13

)

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

 

 

Pension Benefits

 

Other
Benefits

 

Total

(in millions, net of income tax)

Three Months Ended March 31, 2017

Beginning balance

$

(25

)

 

$

16

 

 

$

(9

)

Amounts reclassified from other comprehensive income: (1)

 

 

 

 

 

Amortization of prior service cost (net of taxes of $1 and $2, respectively)

(1

)

 

2

 

 

1

 

Amortization of net actuarial loss (net of taxes of $3, and $0, respectively)

3

 

 

1

 

 

4

 

Regulatory account transfer (net of taxes of $2 and $2, respectively)

(2

)

 

(3

)

 

(5

)

Net current period other comprehensive gain (loss)

 

 

 

 

 

Ending balance

$

(25

)

 

$

16

 

 

$

(9

)

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

 

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

Recently Adopted Accounting Standards

 

Revenue Recognition Standard

 

In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), which amends the previous revenue recognition guidance.  The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.  PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Condensed Consolidated Financial Statements as of the adoption date or for the three months ended March 31, 2018. A majority of the Utility's revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.

 

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 as a result of seasonality, weather, and customer usage patterns.

 

The FERC authorizes the Utility’s revenue requirements in periodic (often annual) TO rate cases.  The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of revenues subject to refund.

 

Regulatory Balancing Account Revenue

 

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years.  The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and natural gas services.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year.  The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. 

 

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

 

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

(in millions)

Three Months Ended March 31,

Electric

2018

Revenue from contracts with customers

 

Residential

$

1,336

 

Commercial

1,073

 

Industrial

324

 

Agricultural

125

 

Public street and highway lighting

20

 

Other (1)

(201

)

Total revenue from contracts with customers - electric

2,677

 

Regulatory balancing accounts (2)

274

 

Total electric operating revenue

$

2,951

 

 

 

Natural gas

 

Revenue from contracts with customers

 

Residential

$

958

 

Commercial

196

 

Transportation service only

297

 

Other (1)

(52

)

Total revenue from contracts with customers - gas

1,399

 

Regulatory balancing accounts (2)

(294

)

Total natural gas operating revenue

1,105

 

Total operating revenues

$

4,056

 

 

 

(1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

 

Presentation of Net Periodic Pension and Post-Retirement Benefit Costs

 

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs.  PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018.

 

On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.  As a result, the Condensed Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $13 million and $14 million for PG&E Corporation and the Utility, respectively, for the three months ended March 31, 2017.

 

On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes.  In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuaries. The capitalization of service costs only will result in higher rate base and will lead to a reduction in the Utility's 2018 revenues.  The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

 

Recognition and Measurement of Financial Assets and Financial Liabilities

 

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments.  The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income.  The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Condensed Consolidated Financial Statements and related disclosures.

 

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

 

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Condensed Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification.

 

Accounting Standards Issued But Not Yet Adopted

 

Recognition of Lease Assets and Liabilities

 

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted.  PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019.  PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and related disclosures.

 


NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

 

Regulatory Assets and Liabilities

 

Current Regulatory Assets

 

At March 31, 2018 and December 31, 2017, the Utility had current regulatory assets of $646 million and $615 million, which included $444 million and $426 million, respectively, of costs related to CEMA fire prevention and vegetation management.

 

Long-Term Regulatory Assets

 

Long-term regulatory assets are comprised of the following:

 

Asset Balance at

(in millions)

March 31, 2018

 

December 31, 2017

Pension benefits

$

1,915

 

 

$

1,954

 

Environmental compliance costs

749

 

 

837

 

Utility retained generation

308

 

 

319

 

Price risk management

68

 

 

65

 

Unamortized loss, net of gain, on reacquired debt

88

 

 

79

 

Catastrophic event memorandum account

314

 

 

274

 

Other

282

 

 

265

 

Total long-term regulatory assets

$

3,724

 

 

$

3,793

 

 

Long-Term Regulatory Liabilities

 

Long-term regulatory liabilities are comprised of the following:

 

Liability Balance at

(in millions)

March 31, 2018

 

December 31, 2017

Cost of removal obligations

$

5,674

 

 

$

5,547

 

Deferred income taxes

873

 

 

1,021

 

Recoveries in excess of AROs

533

 

 

624

 

Public purpose programs

591

 

 

590

 

Other

915

 

 

897

 

Total long-term regulatory liabilities

$

8,586

 

 

$

8,679

 

 

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

Regulatory Balancing Accounts

 

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

 

Receivable Balance at

(in millions)

March 31, 2018

 

December 31, 2017

Electric distribution

$

176

 

 

$

 

Electric transmission

125

 

 

139

 

Utility generation

203

 

 

 

Gas distribution and transmission

269

 

 

486

 

Energy procurement

1

 

 

71

 

Public purpose programs

115

 

 

103

 

Other

478

 

 

423

 

Total regulatory balancing accounts receivable

$

1,367

 

 

$

1,222

 

 

 

Payable Balance at

(in millions)

March 31, 2018

 

December 31, 2017

Electric distribution

$

 

 

$

72

 

Electric transmission

108

 

 

120

 

Utility generation

 

 

14

 

Energy procurement

265

 

 

149

 

Public purpose programs

491

 

 

452

 

Other

400

 

 

313

 

Total regulatory balancing accounts payable

$

1,264

 

 

$

1,120

 

 

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

 

NOTE 4: DEBT

 

Revolving Credit Facilities and Commercial Paper Program

 

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at March 31, 2018:

(in millions)

Termination Date

 

Facility

Limit

 

Letters of

Credit

Outstanding

 

Commercial

Paper

 

Facility

Availability

PG&E Corporation

April 2022

 

$

300

 

(1)

$

 

 

$

121

 

 

$

179

 

Utility

April 2022

 

3,000

 

(2)

48

 

 

97

 

 

2,855

 

Total revolving credit facilities

 

 

$

3,300

 

 

$

48

 

 

$

218

 

 

$

3,034

 

 

 

 

 

 

 

 

 

 

 

(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans.

 

Other Short-term Borrowings

 

In February 2018, the Utility’s $250 million floating rate unsecured term loan, issued in February 2017, matured and was repaid. Additionally, in February 2018, the Utility entered into a $250 million floating rate unsecured term loan that will mature on February 22, 2019.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Long-term Debt Issuances and Redemptions

 

In January 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% Senior Notes due October 15, 2018. On January 31, 2018, the Utility deposited with the trustee funds sufficient to effect the early redemption of these bonds and satisfy and discharge its remaining obligation of $400 million on February 18, 2018.

 

In April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. The term loan matures on April 16, 2020, unless extended by PG&E Corporation pursuant to the terms of the term loan agreement. The proceeds were used for general corporate purposes, including the early redemption of PG&E Corporation's outstanding $350 million principal amount of 2.40% Senior Notes due March 1, 2019. On April 16, 2018, PG&E Corporation issued a notice of early redemption of these bonds, with a redemption date of April 26, 2018.

 

Variable Rate Interest

 

At March 31, 2018, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 1.52% to 1.65%.  At March 31, 2018, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 1.60%.

 

NOTE 5: EQUITY

 

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2018 were as follows:

 

PG&E Corporation

 

Utility

(in millions)

Total

Equity

 

Total

Shareholders' Equity

Balance at December 31, 2017

$

19,472

 

 

$

19,747

 

Comprehensive income

445

 

 

452

 

Common stock issued

35

 

 

 

Share-based compensation

34

 

 

 

Preferred stock dividend requirement

 

 

(3

)

Preferred stock dividend requirement of subsidiary

(3

)

 

 

Balance at March 31, 2018

$

19,983

 

 

$

20,196

 

 

There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the three months ended March 31, 2018.  As of March 31, 2018, the remaining gross sales available under this agreement were $246.3 million.

 

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans.  During the three months ended March 31, 2018, 1.2 million shares were issued for cash proceeds of $35.1 million under these plans.

 

NOTE 6: 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 March 31,

(in millions, except per share amounts)

2018

 

2017

Income available for common shareholders

$

442

 

 

$

576

 

Weighted average common shares outstanding, basic

515

 

 

508

 

Add incremental shares from assumed conversions:

 

 

 

Employee share-based compensation

1

 

 

3

 

Weighted average common shares outstanding, diluted

516

 

 

511

 

Total earnings per common share, diluted

$

0.86

 

 

$

1.13

 

 

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 7: DERIVATIVES

 

Use of Derivative Instruments

 

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

 

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

 

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

 

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

Volume of Derivative Activity

 

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

 

 

 

 

Contract Volume at

Underlying Product

 

Instruments

 

March 31,
2018

 

December 31,
2017

Natural Gas (1) (MMBtus (2))

 

Forwards, Futures and Swaps

 

184,948,051

 

 

228,768,745

 

 

 

Options

 

31,481,247

 

 

60,736,806

 

Electricity (Megawatt-hours)

 

Forwards, Futures and Swaps

 

2,602,376

 

 

2,872,013

 

 

 

Congestion Revenue Rights (3)

 

304,484,831

 

 

312,272,177

 

 

 

 

 

 

 

 

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

(2) Million British Thermal Units.

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

 

Presentation of Derivative Instruments in the Financial Statements

 

At March 31, 2018, 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

$

30

 

 

$

(2

)

 

$

6

 

 

$

34

 

Other noncurrent assets – other

98

 

 

(1

)

 

 

 

97

 

Current liabilities – other

(52

)

 

2

 

 

19

 

 

(31

)

Noncurrent liabilities – other

(68

)

 

1

 

 

12

 

 

(55

)

Total commodity risk

$

8

 

 

$

 

 

$

37

 

 

$

45

 

 

At December 31, 2017, 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

$

30

 

 

$

(3

)

 

$

10

 

 

$

37

 

Other noncurrent assets – other

103

 

 

(1

)

 

 

 

102

 

Current liabilities – other

(47

)

 

3

 

 

13

 

 

(31

)

Noncurrent liabilities – other

(66

)

 

1

 

 

8

 

 

(57

)

Total commodity risk

$

20

 

 

$

 

 

$

31

 

 

$

51

 

 

Gains and losses associated with price risk management activities were recorded as follows:

 

 

Commodity Risk

 

 

Three Months Ended March 31,

(in millions)

 

2018

 

2017

Unrealized gain (loss) - regulatory assets and liabilities (1)

 

$

(12

)

 

$

(48

)

Realized loss - cost of electricity (2)

 

(18

)

 

(5

)

Realized loss - cost of natural gas (2)

 

(1

)

 

(1

)

Net commodity risk

 

$

(31

)

 

$

(54

)

 

 

 

 

 

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income.  These amounts exclude the impact of cash collateral postings.

(2) These amounts are fully passed through to customers in rates.  Accordingly, net income was not impacted by realized amounts on these instruments.

 

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

 

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies.  At March 31, 2018, the Utility’s credit rating was investment grade.  If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.

 

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

 

Balance at

(in millions)

March 31,
2018

 

December 31,
2017

Derivatives in a liability position with credit risk-related

contingencies that are not fully collateralized

$

(1

)

 

$

(1

)

Related derivatives in an asset position

 

 

 

Collateral posting in the normal course of business related to

these derivatives

 

 

 

Net position of derivative contracts/additional collateral

posting requirements (1)

$

(1

)

 

$

(1

)

 

 

 

 

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.

 

NOTE 8: 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

 

March 31, 2018

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

Short-term investments

$

28

 

 

 

 

 

 

 

 

$

28

 

Global equity securities

1,862

 

 

 

 

 

 

 

 

1,862

 

Fixed-income securities

776

 

 

599

 

 

 

 

 

 

1,375

 

Assets measured at NAV

 

 

 

 

 

 

 

 

17

 

Total nuclear decommissioning trusts (2)

2,666

 

 

599

 

 

 

 

 

 

3,282

 

Price risk management instruments (Note 7)

 

 

 

 

 

 

 

 

 

Electricity

 

 

2

 

 

125

 

 

3

 

 

130

 

Gas

 

 

1

 

 

 

 

 

 

1

 

Total price risk management instruments

 

 

3

 

 

125

 

 

3

 

 

131

 

Rabbi trusts

 

 

 

 

 

 

 

 

 

Fixed-income securities

 

 

74

 

 

 

 

 

 

74

 

Life insurance contracts

 

 

69

 

 

 

 

 

 

69

 

Total rabbi trusts

 

 

143

 

 

 

 

 

 

143

 

Long-term disability trust

 

 

 

 

 

 

 

 

 

Short-term investments

5

 

 

 

 

 

 

 

 

5

 

Assets measured at NAV

 

 

 

 

 

 

 

 

162

 

Total long-term disability trust

5

 

 

 

 

 

 

 

 

167

 

TOTAL ASSETS

$

2,671

 

 

$

745

 

 

$

125

 

 

$

3

 

 

$

3,723

 

Liabilities:

 

 

 

 

 

 

 

 

 

Price risk management instruments (Note 7)

 

 

 

 

 

 

 

 

 

Electricity

$

8

 

 

$

25

 

 

$

85

 

 

$

(33

)

 

$

85

 

Gas

 

 

2

 

 

 

 

(1

)

 

1

 

TOTAL LIABILITIES

$

8

 

 

$

27

 

 

$

85

 

 

$

(34

)

 

$

86

 

 

 

 

 

 

 

 

 

 

 

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

(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements

 

December 31, 2017

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

Short-term investments

$

385

 

 

$

 

 

$

 

 

$

 

 

$

385

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

Short-term investments

23

 

 

 

 

 

 

 

 

23

 

Global equity securities

1,967

 

 

 

 

 

 

 

 

1,967

 

Fixed-income securities

733

 

 

562

 

 

 

 

 

 

1,295

 

Assets measured at NAV

 

 

 

 

 

 

 

 

18

 

Total nuclear decommissioning trusts (2)

2,723

 

 

562

 

 

 

 

 

 

3,303

 

Price risk management instruments (Note 7)

 

 

 

 

 

 

 

 

 

Electricity

 

 

3

 

 

129

 

 

6

 

 

138

 

Gas

 

 

1

 

 

 

 

 

 

1

 

Total price risk management instruments

 

 

4

 

 

129

 

 

6

 

 

139

 

Rabbi trusts

 

 

 

 

 

 

 

 

 

Fixed-income securities

 

 

72

 

 

 

 

 

 

72

 

Life insurance contracts

 

 

71

 

 

 

 

 

 

71

 

Total rabbi trusts

 

 

143

 

 

 

 

 

 

143

 

Long-term disability trust

 

 

 

 

 

 

 

 

 

Short-term investments

8

 

 

 

 

 

 

 

 

8

 

Assets measured at NAV

 

 

 

 

 

 

 

 

167

 

Total long-term disability trust

8

 

 

 

 

 

 

 

 

175

 

TOTAL ASSETS

$

3,116

 

 

$

709

 

 

$

129

 

 

$

6

 

 

$

4,145

 

Liabilities:

 

 

 

 

 

 

 

 

 

Price risk management instruments (Note 7)

 

 

 

 

 

 

 

 

 

Electricity

$

10

 

 

$

15

 

 

$

87

 

 

$

(25

)

 

$

87

 

Gas

 

 

1

 

 

 

 

 

 

1

 

TOTAL LIABILITIES

$

10

 

 

$

16

 

 

$

87

 

 

$

(25

)

 

$

88

 

 

 

 

 

 

 

 

 

 

 

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

(2) Represents amount before deducting $440 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.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the three months ended March 31, 2018 and 2017.

 

Trust Assets

 

Assets Measured at Fair Value

 

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

 

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

 

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

 

Assets Measured at NAV Using Practical Expedient

 

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

 

Price Risk Management Instruments

 

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

 

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

 

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

 

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

 

Level 3 Measurements and Sensitivity Analysis

 

The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives.  The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

 

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 7 above.)

 

 

Fair Value at

 

 

 

 

 

 

(in millions)

 

March 31, 2018

 

 

 

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Valuation
Technique

 

Unobservable
Input

 

Range (1)

Congestion revenue rights

 

$

125

 

 

$

25

 

 

Market approach

 

CRR auction prices

 

$ (7.44) - 13.91

Power purchase agreements

 

$

 

 

$

60

 

 

Discounted cash flow

 

Forward prices

 

$ 18.81 - 38.80

 

 

 

 

 

 

 

 

 

 

 

 (1) Represents price per megawatt-hour

 

 

 

Fair Value at

 

 

 

 

 

 

(in millions)

 

December 31, 2017

 

 

 

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Valuation Technique

 

Unobservable Input

 

Range (1)

Congestion revenue rights

 

$

129

 

 

$

24

 

 

Market approach

 

CRR auction prices

 

$ (16.03) - 11.99

Power purchase agreements

 

$

 

 

$

63

 

 

Discounted cash flow

 

Forward prices

 

$ 18.81 - 38.80

 

 

 

 

 

 

 

 

 

 

 

(1) Represents price per megawatt-hour

 

Level 3 Reconciliation

 

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2018 and 2017:

 

Price Risk Management Instruments

(in millions)

2018

 

2017

Asset (liability) balance as of January 1

$

42

 

 

$

55

 

Net realized and unrealized gains:

 

 

 

Included in regulatory assets and liabilities or balancing accounts (1)

(2

)

 

(6

)

Asset (liability) balance as of March 31

$

40

 

 

$

49

 

 

 

 

 

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

 

Financial Instruments

 

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at March 31, 2018 and December 31, 2017, as they are short-term in nature or have interest rates that reset daily. 

 

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

 

At March 31, 2018

 

At December 31, 2017

(in millions)

Carrying Amount

 

Level 2 Fair Value

 

Carrying Amount

 

Level 2 Fair Value

PG&E Corporation

$

350

 

 

$

348

 

 

$

350

 

 

$

350

 

Utility

16,693

 

 

17,723

 

 

17,090

 

 

19,128

 

 

 

Nuclear Decommissioning Trust Investments

 

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

(in millions)

 

 

 

 

 

 

 

As of March 31, 2018

Amortized
Cost

 

Total
Unrealized
Gains

 

Total
Unrealized
Losses

 

Total Fair
Value

Nuclear decommissioning trusts

 

 

 

 

 

 

 

Short-term investments

$

28

 

 

$

 

 

$

 

 

$

28

 

Global equity securities

475

 

 

1,405

 

 

(1

)

 

1,879

 

Fixed-income securities

1,355

 

 

39

 

 

(19

)

 

1,375

 

Total (1)

$

1,858

 

 

$

1,444

 

 

$

(20

)

 

$

3,282

 

As of December 31, 2017

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

Short-term investments

$

23

 

 

$

 

 

$

 

 

$

23

 

Global equity securities

524

 

 

1,463

 

 

(2

)

 

1,985

 

Fixed-income securities

1,252

 

 

51

 

 

(8

)

 

1,295

 

Total (1)

$

1,799

 

 

$

1,514

 

 

$

(10

)

 

$

3,303

 

 

 

 

 

 

 

 

 

(1) Represents amounts before deducting $440 million for the periods ended March 31, 2018 and December 31, 2017, 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)

March 31, 2018

Less than 1 year

$

42

 

1–5 years

438

 

5–10 years

374

 

More than 10 years

521

 

Total maturities of fixed-income securities

$

1,375

 

 

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

 

Three Months Ended March 31,

(in millions)

2018

 

2017

Proceeds from sales and maturities of nuclear decommissioning trust investments

$

494

 

 

$

470

 

Gross realized gains on securities

37

 

 

29

 

Gross realized losses on securities

(4

)

 

(5

)

 

NOTE 9: 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 liability has been incurred and the amount of the liability can be reasonably estimated.  The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

 

Enforcement and Litigation Matters

 

Northern California Wildfires

 

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City. According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires also resulted in 44 fatalities.

 

The Utility incurred costs of $259 million for service restoration and repair to the Utility’s facilities (including $108 million in capital expenditures) through March 31, 2018, in connection with these fires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs.

 

The Northern California wildfires are under investigation by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed. Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. (For example, on February 3, 2018, it was reported that investigators with the Santa Rosa Fire Department had completed their investigation of two small fires that reportedly destroyed two homes and damaged one outbuilding and had concluded that the Utility’s facilities, along with high wind and other factors, contributed to those fires.) It is uncertain when the investigations will be complete and whether Cal Fire will release any preliminary findings before its investigations are complete.

 

As of April 30, 2018, the Utility had submitted 23 electric incident reports to the CPUC associated with the Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000. The information contained in these reports is factual and preliminary, and does not reflect a determination of the causes of the fires. The investigations into the fires are ongoing.

 

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, 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, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking and based on the assumption that utilities have the ability to recover these costs from their customers. Further, courts could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. There is no guarantee that the CPUC would authorize cost recovery even if a court decision were to determine that the doctrine of inverse condemnation applies. In addition to such claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations.

 

Given the incomplete investigations and the uncertainty as to the causes of the fires, PG&E Corporation and the Utility do not believe a loss is probable at this time. However, it is reasonably possible that facts could emerge through the course of the various investigations that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in an accrued liability in the future, the amount of which could be substantial. PG&E Corporation and the Utility currently are unable to reasonably estimate the amount of potential losses (or range of amounts) that they could incur given the preliminary stages of the investigations and the uncertainty regarding the extent and magnitude of potential damages. On January 31, 2018, the California Department of Insurance issued a press release announcing an update on property losses in connection with the October and December wildfires in California, stating that, as of such date, “insurers have received nearly 45,000 insurance claims totaling more than $11.79 billion in losses,” of which approximately $10 billion relates to statewide claims from the October 2017 wildfires. The remaining amount relates to claims from the Southern California December 2017 wildfires. According to the California Department of Insurance, as of the date of the press release, more than 21,000 homes, 3,200 businesses, and more than 6,100 vehicles, watercraft, farm vehicles, and other equipment were damaged or destroyed by the October 2017 wildfires. PG&E Corporation and the Utility have not independently verified these estimates. The California Department of Insurance did not state in its press release whether it intends to provide updated estimates of losses in the future.

 

If the Utility’s facilities are determined to be the cause of one or more of the Northern California wildfires, PG&E Corporation and the Utility could be liable for the related property losses and other damages. The California Department of Insurance January 31, 2018 press release reflects insured property losses only. The press release does not account for uninsured losses, interest, attorneys’ fees, fire suppression costs, evacuation costs, medical expenses, personal injury and wrongful death damages or other costs. If the Utility were to be found liable for certain or all of such other costs and expenses, the amount of PG&E Corporation’s and the Utility’s liability could be higher than the approximately $10 billion in estimated insured property losses with respect to the wildfires that occurred in October 2017, depending on the extent of the damage in connection with such fire or fires. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

 

As of May 1, 2018, PG&E Corporation and the Utility are aware of more than 150 lawsuits representing approximately 2,500 plaintiffs, 6 of which seek to be certified as class actions, that have been filed against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the fires. The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages. In addition, insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed 8 subrogation complaints in the San Francisco County Superior Court. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. Various government entities, including Mendocino, Napa and Sonoma Counties, have also asserted claims against PG&E Corporation and the Utility in the San Francisco County Superior Court based on the damages that these public entities allegedly suffered as a result of the fires. Such alleged damages include, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. On April 16, 2018, PG&E Corporation and the Utility submitted notices of claims against, among other government entities, Mendocino, Napa and Sonoma Counties, reserving their rights to pursue claims against these entities for contribution and equitable indemnity stemming from these entities’ actions and inactions before and during the Northern California wildfires.

 

On October 31, 2017, a group of plaintiffs submitted a petition for coordination to the Chair of the Judicial Council of California and requested coordination of the litigation in the San Francisco Superior Court. On November 9, 2017, PG&E Corporation and the Utility submitted a petition for coordination to the Chair of the Judicial Council of California, and requested separate coordination in the counties in which the fires occurred. On January 4, 2018, the coordination motion judge of the San Francisco Superior Court entered an order granting coordination of the litigation in connection with the Northern California wildfires and recommending that the coordinated proceeding take place in the San Francisco Superior Court. On January 12, 2018, the Judicial Council of California accepted the coordination motion judge’s recommendation and assigned the coordinated proceeding to San Francisco. The first case management conference took place on February 27, 2018. The individual plaintiffs, subrogation insurance carriers and certain government entities filed Master Complaints on March 12, 2018, and PG&E Corporation and the Utility filed Master Answers to those Master Complaints on March 16, 2018. PG&E Corporation and the Utility also filed on March 16, 2018, a legal challenge to the inverse condemnation causes of action in the Master Complaints. The court set a hearing on that challenge for May 18, 2018. The next case management conference will be scheduled at the May 18, 2018 hearing.

 

In addition, two derivative lawsuits for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively. The first lawsuit is filed against the members of the Board of Directors and certain officers of PG&E Corporation. PG&E Corporation is identified as a nominal defendant in that action. The second lawsuit is filed against the members of the Board of Directors, certain former members of the Board of Directors, and certain officers of both PG&E Corporation and the Utility. PG&E Corporation and the Utility are identified as nominal defendants in that action. On February 14, 2018, the Court consolidated the two lawsuits, and, on April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the Northern California wildfires, on April 24, 2018, the Court entered a stipulation and order to stay. The stay is subject to certain conditions regarding discovery.

 

PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires. The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $840 million, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. In addition, coverage limits within the Utility's wildfire insurance policies could result in further material self-insured costs in the event each fire were deemed to be a separate occurrence under the terms of the insurance policies. If the Utility were to be found liable for one or more fires, the Utility's insurance could be insufficient to cover that liability, depending on the extent of the damage in connection with such fire or fires. Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of approximately $630 million for any potential future event.

 

In addition, it could take a number of years before the Utility’s final liability is known. The Utility may be unable to recover costs in excess of insurance through regulatory mechanisms and, even if such recovery is possible, it could take a number of years to resolve and a number of years thereafter to collect. PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

 

Litigation and Regulatory Citations in Connection with the Butte Fire

 

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

 

Third-Party Claims

 

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council had previously authorized the coordination of all cases in Sacramento County.  As of March 31, 2018, 79 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador.  The complaints involve approximately 3,770 individual plaintiffs representing approximately 2,000 households and their insurance companies.  These complaints are part of or are in the process of being added to the two master complaints.  Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also seek punitive damages.  Prior to March 31, 2018, several plaintiffs dismissed the Utility's two vegetation management contractors from their complaints. The number of individual complaints and plaintiffs may still increase in the future, because the statute of limitations for property damage in connection with the Butte fire has not yet expired. (The statute of limitations for personal injury in connection with the Butte fire has expired.)  The Utility continues mediating and settling cases.

 

In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims.  On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility's vegetation contractors. The Utility and Cal Fire are currently engaged in a mediation process.

 

Further, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates to be approximately $190 million.  This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire.

 

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors. The County seeks to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also seeks punitive damages. It had previously indicated that it intended to bring a claim against the Utility that it estimated to be approximately $85 million. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million. This claim includes costs that the County of Calaveras allegedly incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. The Utility and the County of Calaveras are currently engaged in a mediation process.

 

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages.  On August 10, 2017, the Court denied the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hire and train qualified employees.  On August 16, 2017, the Utility filed a writ with the Court of Appeal challenging the trial court's ruling on punitive damages.  The Court of Appeal accepted the writ on September 15, 2017, and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted.  Briefing on the writ was completed as of January 2, 2018. The Utility sought expedited review of the motion. On April 4, 2018, the Court of Appeal indicated that it is prepared to issue a decision without oral argument. On April 13, 2018 and April 16, 2018, respectively, the plaintiffs and the Utility requested oral argument, which is now scheduled for June 22, 2018.

 

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility with respect to the Butte fire. The Court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could file lawsuits and make similar claims. On January 4, 2018, the Utility filed with the Court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

 

On May 1, 2018, the Court issued its ruling on the Utility's renewed motion in which the Court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The Court determined that it is bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the Court stated that the Utility's constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raises the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The next case management conference is scheduled for June 7, 2018. The Utility intends to file a writ seeking review of this decision. No trial date is pending.

 

Estimated Losses from Third-Party Claims

 

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

 

In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent.  While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility.

 

The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion in connection with the Butte fire.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages, but does not include punitive damages for which the Utility could be liable.  In addition, while this amount includes the Utility's early assumptions about fire suppression costs (including its assessment of the Cal Fire loss) and the County of Calaveras claim, it does not include any significant portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

 

The Utility currently is unable to reasonably estimate the upper end of the range of losses due to uncertainties related to the applicability of inverse condemnation and punitive damages and because it has insufficient information on the claims of over 600 households who have asserted claims, the claim from the OES, as well as claims from any other households that may be brought before the statute of limitations for property damage expires.  The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of the potential claim from the OES, outcomes of future court or jury decisions, and information about damages, including punitive damages, for which the Utility could be liable, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.

 

The following table presents changes in the third-party claims liability since December 31, 2015.  The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Loss Accrual (in millions)

 

 

Balance at December 31, 2015

 

$

 

Accrued losses

 

750

Payments (1)

 

(60)

Balance at December 31, 2016

 

690

 

Accrued losses

 

350

Payments (1)

 

(479)

Balance at December 31, 2017

 

561

 

Accrued losses

 

 

Payments (1)

 

(118

)

Balance at March 31, 2018

 

$

443

 

 

 

 

(1) As of March 31, 2018 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $734 million of which $657 million has been paid by the Utility.

 

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $99 million in connection with the Butte fire.  For the three months ended March 31, 2018, the Utility incurred legal expenses in connection with the Butte fire of $12 million.

 

Loss Recoveries

 

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of $922 million.  The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range.  Through March 31, 2018, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors (excluded from the table below), including $7 million received in the three months ended March 31, 2018.  Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

 

The following table presents changes in the insurance receivable since December 31, 2015.  The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Insurance Receivable (in millions)

 

 

Balance at December 31, 2015

 

$

 

Accrued insurance recoveries

 

625

Reimbursements

 

(50)

Balance at December 31, 2016

 

575

Accrued insurance recoveries

 

297

Reimbursements

 

(276)

Balance at December 31, 2017

 

596

Accrued insurance recoveries

 

 

Reimbursements

 

(197

)

Balance at March 31, 2018

 

$

399

 

 

In April 2018, the Utility received another $31 million in insurance reimbursements.

 

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded.

 

Regulatory Citations

 

On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED's investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent a gray pine tree from leaning and contacting the Utility's electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017.

 

Enforcement Matters

 

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

 

Regulatory Proceedings

 

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

 

On April 26, 2018, the CPUC approved the revised proposed decision issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the "settlement agreement") by the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN.

 

The decision results in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city).  In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules.  Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above. The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017 violate the CPUC ex-parte rules.

 

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

 

At March 31, 2018, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $8 million accrual for a portion of the 2018 GT&S revenue requirement reduction and an accrual of the $24 million payable to the California General Fund and the Cities of San Bruno and San Carlos.  In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

 

For more information about the proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

 

Natural Gas Transmission Pipeline Rights-of-Way

 

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way.  The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met.  In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

 

Potential Safety Citations

 

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation.

 

If the SED assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. Historically, the SED has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. In the past, the SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The CPUC can also open an OII and levy additional fines even after the SED has issued a citation.

 

The Utility is unable to reasonably estimate the amount or range of future charges as a result of SED investigations or any proceedings that could be commenced in connection with potential violations of electric and natural gas laws and regulations.

 

Other Matters

 

PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $89 million at March 31, 2018, and $86 million at December 31, 2017.  These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets.  The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

 

Disallowance of Plant Costs

 

2015 GT&S Rate Case Capital Disallowances

 

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

 

Environmental Remediation Contingencies

 

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

 

March 31,

 

December 31,

(in millions)

2018

 

2017

Topock natural gas compressor station

$

342

 

 

$

334

 

Hinkley natural gas compressor station

144

 

 

147

 

Former manufactured gas plant sites owned by the Utility or third parties (1)

329

 

 

320

 

Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites
(2)

113

 

 

115

 

Fossil fuel-fired generation facilities and sites (3)

157

 

 

123

 

Total environmental remediation liability

$

1,085

 

 

$

1,039

 

 

 

 

 

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

(2) Primarily driven by the Shell Pond site.

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

 

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

 

The Utility’s environmental remediation liability at March 31, 2018, reflects its best estimate of probable future costs associated with its final remediation plans.  Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the Utility's time frame for remediation.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition and cash flows during the period in which they are recorded. At March 31, 2018, the Utility expected to recover $737 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

 

For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

 

Natural Gas Compressor Station Sites

 

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

 

Topock Site

 

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. On December 21, 2017, the DTSC issued its final environmental impact report. The environmental impact report includes requirements related to conditions of work that have been anticipated or previously required and are accounted for in the current environmental remediation liability. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $293 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 through the HSM, where 90% of the costs are recovered in rates.

 

Hinkley Site

 

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $146 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 in the past. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $340 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

 

Utility-Owned Generation Facilities and Third-Party Disposal Sites

 

Utility-owned generation facilities and third-party disposal sites are long-term projects that are undergoing a remediation process. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $142 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

 

Fossil Fuel-Fired Generation Sites

 

In 1998 the Utility divested its generation power plant business as part of generation deregulation. Although the Utility has sold its fossil-fueled power plants, the Utility has retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $106 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 European Mutual Association for Nuclear Insurance, covering nuclear or non- nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  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, as of April 1, 2018, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $47 million.  If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, as of April 1, 2018.  For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. 

 

Resolution of Remaining Chapter 11 Disputed Claims

 

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001.  While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC.  Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

 

At December 31, 2017, the Consolidated Balance Sheets reflected $243 million in net claims within Disputed claims and customer refunds.  There were no significant changes to this balance during the three months ended March 31, 2018. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.

 

Tax Matters

 

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits.  As of March 31, 2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $20 million within the next 12 months.  PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. 

Tax Cuts and Jobs Act of 2017

 

On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. The Tax Act required PG&E Corporation and the Utility to re-measure all existing deferred income tax assets and liabilities to reflect the reduction in the federal tax rate. PG&E Corporation and the Utility recorded reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued by the SEC in Staff Accounting Bulletin No. 118, for the re-measurement of deferred tax balances as of December 31, 2017. There were no material updates to these estimates in the three months ended March 31, 2018.

 

On March 30, 2018, the Utility submitted to the CPUC PFMs of the CPUC’s final decisions in the Utility’s 2017 GRC, and the 2015 GT&S rate case. Additionally, the Utility submitted updated testimony in connection with the 2019 GT&S rate case.  These submittals reflect the effects of the Tax Act on these rate cases. On an aggregate basis from these submittals, the Utility anticipates an annual reduction to revenue requirements of approximately $325 million starting in 2018, and incremental increases to rate base of approximately $271 million for 2018 (including the impact of the pending private letter ruling advice letter), and $613 million for 2019.  The incremental increases to rate base are due primarily to the elimination of bonus depreciation. The Utility also expects to reflect an annual revenue requirement reduction, starting in 2018, of approximately $125 million from other rate cases, including the TO19 rate case.  The associated rate base increases are approximately $100 million in 2018 and $200 million in 2019. The Utility is unable to predict the timing and outcome of the CPUC decisions in connection with these submittals.

 

Purchase Commitments

 

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments.  At December 31, 2017, the Utility had undiscounted future expected obligations of approximately $44 billion.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.) The Utility has not entered into any new material commitments during the three months ended March 31, 2018.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
  1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
  2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
  3. 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.
  4. 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
2,433,257
2,433,257
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
138,103
138,103
3
Preceding Quarter/Year to Date Changes in Fair Value
4
Total (lines 2 and 3)
138,103
138,103
569,263,674
569,401,777
5
Balance of Account 219 at End of Preceding Quarter/Year
2,571,360
2,571,360
6
Balance of Account 219 at Beginning of Current Year
6,290,667
6,290,667
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
149,912
149,912
8
Current Quarter/Year to Date Changes in Fair Value
9
Total (lines 7 and 8)
149,912
149,912
452,312,063
452,461,975
10
Balance of Account 219 at End of Current Quarter/Year
6,440,579
6,440,579


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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)
70,286,900,770
51,105,225,135
13,038,070,957
6,143,604,678
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
41,678,530
(a)
23,447,809
18,230,721
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
272,167
21,600
293,767
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
11,481,975,065
6,571,246,753
4,464,715,663
446,012,649
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
Total (3 thru 7)
81,810,282,198
57,699,941,297
17,502,492,853
6,607,848,048
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
11
ConstructionWorkInProgress
Construction Work in Progress
2,562,191,365
1,671,613,001
452,031,799
438,546,565
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
13
UtilityPlantAndConstructionWorkInProgress
Total Utility Plant (8 thru 12)
84,372,473,563
59,371,554,298
17,954,524,652
7,046,394,613
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
36,139,391,382
(b)
25,912,550,059
7,479,016,591
2,747,824,732
15
UtilityPlantNet
Net Utility Plant (13 less 14)
48,233,082,181
33,459,004,239
10,475,508,061
4,298,569,881
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
35,026,244,605
25,852,425,120
7,464,887,044
1,708,932,441
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
8,376,589
8,376,589
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
1,104,770,188
60,124,939
5,752,958
1,038,892,291
22
DepreciationAmortizationAndDepletionUtilityPlantInService
Total in Service (18 thru 21)
36,139,391,382
25,912,550,059
7,479,016,591
2,747,824,732
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)
36,139,391,382
(c)
25,912,550,059
7,479,016,591
2,747,824,732


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

Balance at 3/31/2018 includes the impact of removing three capital leases that were terminated during 2017 in the amount of $11.9 million, net of depreciation.

(b) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility

Balance at 3/31/2018 includes the impact of removing three capital leases that were terminated during 2017 in the amount of $11.9 million, net of depreciation.

(c) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility

Balance at 3/31/2018 includes the impact of removing three capital leases that were terminated during 2017 in the amount of $11.9 million, net of depreciation.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
  1. 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
118,703,296
60,124,939
2
Steam Production Plant
855,944,113
297,166,775
3
Nuclear Production Plant
10,094,294,926
6,508,357,357
4
Hydraulic Production - Conventional
3,147,835,115
1,376,405,179
5
Hydraulic Production - Pumped Storage
931,450,534
768,044,223
6
Other Production
1,132,562,643
293,376,219
7
Transmission
11,585,068,991
3,024,635,850
8
Distribution
28,847,557,740
13,015,872,719
9
Regional Transmission and Market Operation
10
General
986,523,939
568,566,798
11
TOTAL (Total of lines 1 through 10)
57,699,941,297
25,912,550,059


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
Transmission Service and Generation Interconnection Study Costs
  1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies.
  2. List each study separately.
  3. In column (a) provide the name of the study.
  4. In column (b) report the cost incurred to perform the study at the end of period.
  5. In column (c) report the account charged with the cost of the study.
  6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
  7. 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
(a)
(see details in footnotes)
450,293
1,050,924
20
Total
21
Generation Studies
22
(b)
(see details in footnotes)
210,858
484,530
39
Total
40 Grand Total


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

Order

Order Description

BALANCE 12/31/2017

COSTS INCURRED PERIOD ENDED 3/31/2018

REIMBURSEMENTS RECEIVED PERIOD ENDED 3/31/2018

NET ACTIVITY PERIOD ENDED 3/31/2018

BALANCE 3/31/2018

9715072

WL -(SIS)Interconnection Merced Irr Dist

 

-500

-500

-500

9719582

WG Gradient Resources Project SIS

22,884

 

 

 

22,884

9719800

WAPA O'Neill Substation - System Impact

4,623

 

 

 

4,623

9719900

WG - BURNS&MCDONNELL-Cluster work

5,991

-473

 

-473

5,518

9722202

WG - C6 - Cluster 6 Phase 2

24,434

 

 

 

24,434

9724040

KMPUD Load Interconnection Study

-11,807

 

 

 

-11,807

9724300

Ntwrk Eval for Calpine 115kV Geysers Gen

-10,369

 

 

 

-10,369

9725002

WG - C8 - SM - Quail Creek Solar 1

128

 

 

 

128

9725844

CDWR BDCP Phase 2 sudy

703

 

 

 

703

9726740

WG - 2016 Reassessment Gen Interconn

-1

 

 

 

-1

9726940

WAPA - Cottonwood Olinda line work

106,089

 

 

 

106,089

9727720

SFPUC - Potrero Interconnection

179

 

 

 

179

9727980

LBNL Capacity Increase

4,654

 

 

 

4,654

9728340

SVP Breaker Replacement

-8,863

 

 

 

-8,863

9728360

Travis AFB Facility Study

-64,156

 

 

 

-64,156

9728526

Port of Stockton Load Increase

-21,890

 

 

 

-21,890

9728645

WG # MMA # Q720&Q1002

-0

 

 

 

-0

9729040

2016 Merced ID Load Interconnection Faci

-19,504

 

 

 

-19,504

9729280

LBNL Interconnection Capacity Increase

23,583

 

-23,583

-23,583

-0

9729340

WG - 2017 Reassessment

301,644

 

-301,644

-301,644

0

9729546

WAPA SLTP

3,044

 

 

 

3,044

9729703

WG - C9P2 - Cluster 9 Phase 2

789,183

36,814

-826,011

-789,197

-13

9729761

Port of Stockton FAS

-40,364

 

 

 

-40,364

9729808

WG - Cluster 10 IR Review for Protection

-0

 

 

 

-0

9729841

WG - C10P1 - Cluster 10 Phase 1

519,231

304,943

 

304,943

824,175

9729845

WG - C10 - SM - Project01

-105

 

 

 

-105

9729846

WG - C10 - SM - Project02

-128

 

 

 

-128

9729847

WG - C10 - SM - Project03

-129

 

 

 

-129

9729848

WG - C10 - SM - Project04

-242

 

 

 

-242

9729849

WG - C10 - SM - Project05

-156

 

 

 

-156

9729850

WG - C10 - SM - Project06

-258

 

 

 

-258

9729851

WG - C10 - SM - Project07

-197

 

 

 

-197

9729852

WG - C10 - SM - Project08

-248

 

 

 

-248

9729853

WG - C10 - SM - Project09

-192

 

 

 

-192

9729854

WG - C10 - SM - Project10

-238

 

 

 

-238

9729855

WG - C10 - SM - Project11

5,427

 

 

 

5,427

9729856

WG - C10 - SM - Project12

-135

 

 

 

-135

9729857

WG - C10 - SM - Project13

-113

 

 

 

-113

9729859

WG - C10 - SM - Project15

-186

 

 

 

-186

9729881

WG - C10 - SM - Project17

-226

 

 

 

-226

9729882

WG - C10 - SM - Project18

-146

 

 

 

-146

9729883

WG - C10 - SM - Project19

-124

 

 

 

-124

9729884

WG - C10 - SM - Project20

-238

 

 

 

-238

9729885

WG - C10 - SM - Project21

-5,963

 

 

 

-5,963

9729886

WG - C10 - SM - Project22

-170

 

 

 

-170

9729887

WG - C10 - SM - Project23

-144

 

 

 

-144

9729888

WG - C10 - SM - Project24

-133

 

 

 

-133

9729889

WG - C10 - SM - Project25

-151

 

 

 

-151

9729890

WG - C10 - SM - Project26

-249

 

 

 

-249

9729891

WG - C10 - SM - Project27

-197

 

 

 

-197

9729892

WG - C10 - SM - Project28

-272

 

 

 

-272

9729893

WG - C10 - SM - Project29

-265

 

 

 

-265

9729894

WG - C10 - SM - Project30

-112

 

 

 

-112

9729895

WG - C10 - SM - Project31

-220

 

 

 

-220

9729896

WG - C10 - SM - Project32

-220

 

 

 

-220

9729897

WG - C10 - SM - Project33

-102

 

 

 

-102

9729898

WG - C10 - SM - Project34

-79

 

 

 

-79

9729899

WG - C10 - SM - Project35

-147

 

 

 

-147

9729900

WG - C10 - SM - Project36

-269

 

 

 

-269

9729901

WG - C10 - SM - Project37

-177

 

 

 

-177

9729902

WG - C10 - SM - Project38

-259

1,680

 

1,680

1,421

9729903

WG - C10 - SM - Project39

-71

 

 

 

-71

9729904

WG - C10 - SM - Project40

-163

 

 

 

-163

9729905

WG - C10 - SM - Project41

-195

 

 

 

-195

9729906

WG - C10 - SM - Project42

-122

 

 

 

-122

9729907

WG - C10 - SM - Project43

-309

 

 

 

-309

9729908

WG - C10 - SM - Project44

-163

 

 

 

-163

9729909

WG - C10 - SM - Project45

-243

 

 

 

-243

9729910

WG - C10 - SM - Project46

-292

 

 

 

-292

9729911

WG - C10 - SM - Project47

-439

 

 

 

-439

9729912

WG - C10 - SM - Project48

-339

 

 

 

-339

9729913

WG - C10 - SM - Project49

-265

 

 

 

-265

9729914

WG - C10 - SM - Project50

-79

 

 

 

-79

9729960

WG - C10 - SM - Project51

-9

 

 

 

-9

9729961

WG - C10 - SM - Project52

-135

 

 

 

-135

9729962

WG - C10 - SM - Project53

-102

 

 

 

-102

9729963

CAISO ISP Panoche

2,876

 

 

 

2,876

9730243

SFPUC - Potrero Interconnection

-100,814

 

100,814

100,814

-0

9730361

SVP Breaker Replacement Facility Study

8,270

 

 

 

8,270

9730681

WG - ISP - Porthos

 

1,680

 

1,680

1,680

9730823

WAPA Lemoore NAS

8,739

1,034

 

1,034

9,773

9731302

Swan Lake Affected Sys. Study

11,471

48,485

 

48,485

59,955

9707780

CP-Martin 115/60 kV Upgrade Project

379

38

 

38

417

9713955

WL - Tesla Tracy 230kV Line 1 Reloc-FAS

13,216

 

 

 

13,216

9722206

Trans Bay Cable Quick Start Study

3,596

 

 

 

3,596

9717187

WL - CA HiSpeed Train Interconnect Study

26,848

5,542

 

5,542

32,390

9714755

WL - KMPUD-IFAS

63,553

 

 

 

63,553

9731780

WG - 2018 Reassessment

 

49,353

 

49,353

49,353

9732200

WG # ISP-South Belridge Expansion

 

1,198

 

1,198

1,198

 

Total Transmission

1,657,857

450,293

-1,050,924

-600,631

1,057,226

 

(b) Concept: DescriptionOfStudyPerformed

Order

Order Description

BALANCE 12/31/2017

COSTS INCURRED PERIOD ENDED 3/31/2018

REIMBURSEMENTS RECEIVED PERIOD ENDED 3/31/2018

NET ACTIVITY PERIOD ENDED 3/31/2018

BALANCE 3/31/2018

9724683

TO-Green Ridge Repowering Facilities Sty

7,405

 

-7,405

-7,405

 

9725281

Estrella Substation - Facilities Study

-678

 

 

 

-678

9727121

WDT Ripon Independent Study Process

-55,737

 

55,737

55,737

 

9727122

WDT Ripon FCDS Full Capac Deliver Status

-13,296

 

 

 

-13,296

9727181

WDT Cabrillo Wind Energy Indep Study

7,348

 

 

 

7,348

9727183

R21 Verwey-Hanford Dairy Digestr Det Sty

569

 

-569

-569

 

9727300

WDT-HZI-Waste Conn Fac SLO 4-16 Indep Sy

1,447

 

-1,447

-1,447

 

9728500

WDT - Apple Hill ES 1 Independent Study

-58,601

80

58,521

58,601

 

9728501

WDT - Apple Hill ES 2 Independent Study

-57,903

80

57,823

57,903

 

9728502

WDT - Apple Hill ES 1 Deliverability Sty

1,687

 

 

 

1,687

9728503

WDT - Apple Hill ES 2 Deliverability Sty

-3,138

 

 

 

-3,138

9728663

WDT - Poco Power - Fast Track Study

1,979

 

 

 

1,979

9728701

WDT - 50001 SCWA North/South Cluster 10

-48,705

2,543

 

2,543

-46,162

9728800

R21 David Tevelde Dairy Digester Det Sty

-1,336

 

 

 

-1,336

9728862

Q653EA SKIC 20 Telecom Modification

 

 

-4,695

-4,695

-4,695

9728963

R21 Target Corp Shafter Detailed Study

-5,992

 

5,992

5,992

 

9729141

WDT - HZIU Kompogas SLO - ISP

-3,430

 

3,430

3,430

 

9729180

R21 Charleston East 344360 NEM 2 Det Sty

-1,796

 

1,796

1,796

 

9729240

Castroville Energy Stg 5MW Indepent Sty

-3,075

 

3,075

3,075

 

9729360

WDT - SEPV Cuyama - Fast Track Study

-16

 

16

16

 

9729460

WDT - Sirius Ph 3 Fast Track Study

1,140

 

 

 

1,140

9729480

R21 Maddox Dairy Ph1 Enos 347251 Det Sty

-4,246

 

 

 

-4,246

9729481

WDT - Madera 2 Fast Tack Study

1,111

 

-1,111

-1,111

 

9729482

WDT - Kettleman 1 Fast Track Study

-397

 

 

 

-397

9729520

R21 Berrenda Mesa Water 352031 Det Study

-45,503

 

 

 

-45,503

9729522

R21Beldrige Wtr Stor 352165 NEM2 Det Sty

1,110

 

 

 

1,110

9729523

R21 - SCRWA - ENOS 318636 - Detailed Sty

154

 

-154

-154

 

9729524

WDT - SEPV Cuyama Supplemental Review

-644

 

644

644

 

9729621

QF 19C010 Humboldt Redwood Facility Sty

-6,278

 

6,278

6,278

 

9729681

SPI Quincy - Facilities Study

-5,553

 

5,553

5,553

 

9729700

SPI Sonora - Facilities Study

-5,503

 

5,503

5,503

 

9729701

WDT - NortBelridge Comm Solar Fast Track

3,152

 

-3,152

-3,152

 

9729704

WDT - West Paso Community Solar Fast Trk

-397

 

397

397

 

9729760

WDT - SEPV Cuyama System Impact Study

-4,005

 

4,005

4,005

 

9729800

WDT - Cadet Community Solar Fast Track

999

 

-999

-999

 

9729801

WDT - Midway-Sunset Comm Solar Fast Trk

-17

 

17

17

 

9729804

R21 Premier Int Hold 361723 NEM2 Det Sty

-53,618

168

 

168

-53,449

9729805

WDT - Nacimiento Interc Study 2017 Indep

2,599

7,177

 

7,177

9,776

9729806

WDT - Chevron USA Prod Co ISP

-55,769

24,355

 

24,355

-31,414

9729807

WDT - Dalena Farms Cluster Study

-41,294

 

 

 

-41,294

9729810

1453-WD BUCCANEER System Impact Study

-6,533

 

 

 

-6,533

9729844

WDT - SEPV Kings - Fast Track

-165

 

 

 

-165

9729861

WDT-1484-WD-North Belridge Com - Sup Rev

325

 

-325

-325

 

9729920

1452-WD Madera 2 - Independent Study

-9,619

 

9,619

9,619

 

9729921

Shiloh I Wind Project Facilities Study

-1,813

3,024

 

3,024

1,210

9729923

Exchequer RAS - CAISO Post COD

-202

1,461

 

1,461

1,259

9729940

R21 Cache Creek Casino 366552 Det Study

-55,051

 

 

 

-55,051

9729942

R21 Kern Oil Refining (98110) Detail Sty

-5,899

 

 

 

-5,899

9729980

MMA - Q1158 Slate - ISO 51731

1,901

1,815

 

1,815

3,717

9729981

MMA-Q1036 Mustang 2-Gen-Tie-ISO 51601

1,749

 

 

 

1,749

9730000

MMA - Q1011 GHS Project - ISO 51541

2,861

720

-3,581

-2,861

 

9730003

WDT - Midway Sunset Comm Solar Supp Rev

-1,164

 

1,164

1,164

 

9730060

MMA - QF Santa Clara Wind - 51155

2,791

480

 

480

3,271

9730061

MMA - Q1096 & QF Altamont Midway - 51156

2,059

 

 

 

2,059

9730062

MMA - QF Forebay Wind - 51154

1,599

480

 

480

2,079

9730065

Q877 California Flats - Roadway PEIE

-572,623

14,707

 

14,707

-557,917

9730066

1499-WD - Cadet Community Supp Review

-178

 

178

178

 

9730068

1419-RD Sandridge Ptnrs NEMA2 Det Study

-3,184

 

 

 

-3,184

9730120

City of Wasco 370604 RESBCT Detailed Sty

-6,663

 

 

 

-6,663

9730121

WDT - Kent Solar Fast Track Study

673

 

-673

-673

 

9730123

R21-Mariposa Biomass Prj-Detailed Study

-6,384

6,901

 

6,901

517

9730180

MMA - Q1011 GHS Project-Gen-Tie - 51541

86

 

-86

-86

 

9730181

MMA - QF Oroville Cogeneration - 51158

3,721

2,056

 

2,056

5,777

9730182

WDT - IP Cabernet - Fast Track

880

 

-880

-880

 

9730220

R21 George DeBoer Q-1432-RD Detailed Sty

-6,671

 

 

 

-6,671

9730221

R21 Henry Miller Q-1433-RD Detailed Sty

-6,415

 

 

 

-6,415

9730242

MMA - Q653F SP PVUSA - BESS-ISO 60192-C

1,255

240

 

240

1,495

9730244

R21 Rijlaarsdam NEMA 2 1483-RD (Det Sty)

-6,280

674

 

674

-5,606

9730280

MMA-Q1028&29 Ltl Bear Solar1&2-ISO 51587

460

 

-460

-460

 

9730281

WDT - CA-17-0018 SB43 MAHAL (FT)

1,205

 

 

 

1,205

9730304

1510-WD Semperviren 2, Shadelands - SR

235

 

-235

-235

 

9730305

WDT IP Malbec - FT

-19

 

 

 

-19

9730320

R21 1458-RD State Center Comm. Detailed

-5,198

 

 

 

-5,198

9730340

WDT - Korbel Power (ISP)

2,848

2,486

-5,335

-2,848

 

9730360

Kingsburg Cogen - Facility Study

1,494

 

 

 

1,494

9730382

WDT-Eurus Energy-Facility Mods Study

-20,500

 

 

 

-20,500

9730420

1469-RD BELRIDGE WATER/Detailed

-8,780

543

 

543

-8,237

9730421

1513-RD Sandridge Partners/Detailed

-7,015

 

 

 

-7,015

9730441

R21 - Shasta Storage 1/Detailed

-58,612

8,119

 

8,119

-50,493

9730481

R21 D ARRIGO BROS CO OF CALIF/Detailed

-7,366

3,296

 

3,296

-4,070

9730500

Kent Solar, LLC (1521-WD) - ISP

-798

 

798

798

 

9730540

WDT Small World Trading - FT

-138

322

 

322

184

9730580

WDT Semperviren 3 - FT

-262

 

262

262

 

9730581

R21 Avalon Dairy Digester/Detailed

-8,372

84

 

84

-8,288

9730600

R21 The Wine Group LLC/Detailed

-10,000

 

 

 

-10,000

9730620

WDT Peterson Road 2/FT

1,997

 

 

 

1,997

9730640

WDT - 50003 SCWA R4 - Independent Study

-8,206

1,982

 

1,982

-6,225

9730660

WDT - CA-17-0097 SB43 Arco - ISP

1,226

 

 

 

1,226

9730662

R21 - Bear Creek - EDMUD - Detailed Stdy

-7,313

1,046

 

1,046

-6,267

9730664

WDT-CA-17-0101 SB43 Devils Den-Fst Trk

1,870

637

 

637

2,507

9730665

WDT-CA-17-0102 SB43 Gates-ISP

-7,158

5,317

 

5,317

-1,840

9730666

WDT-CA-17-0106 SB43 Coalinga 1-Fst Trk

-205

 

 

 

-205

9730667

WDT-CA-17-0122 SB43 Coalinga 2-Fst Trk

-349

 

 

 

-349

9730672

WDT - CA-17-0018 SB43 Mahal - Sup Rev

-2,182

 

 

 

-2,182

9730740

CA Department of Corrections #387295/Det

-10,000

 

 

 

-10,000

9730743

WDT CA-17-0100 SB43 Derrick/ISP

-9,262

1,043

 

1,043

-8,219

9730744

WDT - American Canyon Solar A/FT

337

 

 

 

337

9730745

WDT - American Canyon Solar B/FT

-715

 

 

 

-715

9730746

WDT - American Canyon Solar C/FT

487

 

 

 

487

9730760

R21 EBMUD Enos (387729) RESBCT/Detailed

-54,658

848

 

848

-53,810

9730784

WDT SEPV American Canyon/FT

207

 

 

 

207

9730785

WDT Palm Drive Solar A/FT

57

 

 

 

57

9730786

WDT Palm Drive Solar B/FT

302

 

 

 

302

9730800

R21 - Bangor Solar - 1402-RD - Det Stdy

-10,000

511

 

511

-9,490

9730820

WDT-CA-17-0090 SB43 Dulgarian/FT

233

 

 

 

233

9730822

WDT - Merced 2/FT

1,438

 

-1,438

-1,438

 

9730840

WDT - IP Cabernet_08_2017/FT

-218

84

 

84

-134

9730861

R21 - City Count of SF (Enos 390303)/Det

-7,995

1,946

 

1,946

-6,049

9730862

1529-RD City of Paso Robles/Detailed

-6,924

253

 

253

-6,672

9730880

WDT - DRES Quarry 2.3/FT

119

40

 

40

159

9730881

WDT - IP Merlot 1/FT

147

 

 

 

147

9730882

WDT - IP Merlot 2/FT

435

 

-435

-435

 

9730883

WDT - IP Merlot 3/FT

913

 

-913

-913

 

9730920

WDT-SR Sovereign Energy Semperviren 3

-2,067

 

2,067

2,067

 

9730940

R21-Calcom Solar-Western Sky Dairy-DS

-850

 

 

 

-850

9730941

R21-OpTerra-S K F Sanitation District-DS

-7,100

 

 

 

-7,100

9730961

WDT - FT - San Rafael Airport Unit No. 2

690

425

-1,115

-690

 

9730962

WDT - ISP - Intersect Power - IP Porthos

-67,791

240

67,551

67,791

 

9730963

WDT - FT - ZGlobal - Eagle 2 Solar

1,552

 

 

 

1,552

9730964

WDT - FT - Morris 385 LLC - Morris 385

1,537

1,059

 

1,059

2,597

9730966

WDT - FT - El Pomar Parners - El Pomar

831

 

-831

-831

 

9731000

WDT-SR 1561 American Canyon Solar A

-1,345

 

 

 

-1,345

9731002

WDT - SR - 1562 American Canyon Solar B

-1,779

 

 

 

-1,779

9731003

WDT - SR - 1563 American Canyon Solar C

-910

 

 

 

-910

9731020

R21-DS-MaasEn. Lakeside Energy Dairy Dig

-9,545

 

9,545

9,545

 

9731040

WDT-SR-Rival Power-Peterson Road 2

532

956

 

956

1,488

9731060

R21 - DS - Chowchilla Dairy Power

-10,000

 

 

 

-10,000

9731061

WDT-FT-ET Solar - Midway Towers Comm Sol

-399

1,782

 

1,782

1,383

9731062

WDT-FT-ET Solar - East Bay Community Sol

-421

1,918

 

1,918

1,498

9731063

R21-DS-Sandridge Partners Etal-NEMA

-9,356

3,738

 

3,738

-5,618

9731080

MMA - QF Altamont Frick - ISO 51135-QM

562

 

 

 

562

9731081

WDT-SR-RenewableProp-Palm Drive Solar A

-1,316

 

 

 

-1,316

9731082

WDT-SR-RenewableProp-Palm Drive Solar B

-1,204

 

 

 

-1,204

9731120

MMA - Q965 Java Solar - ISO 51436

1,279

2,656

 

2,656

3,935

9731181

WDT-FT-CED White River 2 Battery Storage

292

 

-292

-292

 

9731182

R21 - Musco Olive Biom Gen - Fac Study

-7,871

3,142

 

3,142

-4,729

9731183

R21-DS-FoundationWindpower-Mann Packing

-8,222

9,204

 

9,204

982

9731187

WDT - FT - ZGlobal - Merced 2

-1,000

 

1,000

1,000

 

9731201

WDT - SR - IP Portfolio - IP Cabernet

-1,719

80

 

80

-1,640

9731202

WDT - SR - IP Portfolio - IP Merlot 1

-1,748

164

 

164

-1,584

9731203

WDT - SR - IP Portfolio - IP Merlot 2

-1,748

204

1,544

1,748

 

9731204

WDT - SR - IP Portfolio - IP Merlot 3

-1,748

204

1,544

1,748

 

9731205

WDT - SR - El Pomar Partners - El Pomar

-838

956

-118

838

 

9731206

WDT-SR-ForeFront Power-Ava Elizabeth

-1,361

159

 

159

-1,201

9731207

WDT-SR-ForeFront Power-Forefront C2

-842

756

 

756

-85

9731208

WDT-SR-ForeFront Power-Dulgarian

-876

626

 

626

-250

9731209

WDT - SR - San Rafael Airport Unit #2

-1,455

1,386

68

1,455

 

9731210

WDT - FT - Solar Electric SEPV Cuyama 2

310

 

 

 

310

9731211

WDT - SR - Green Light - Eagle 2 Solar

-711

956

 

956

245

9731280

R21-DS-BNB Renewable-Campbell Soup Supp

-9,661

991

 

991

-8,670

9731281

R21-DS-Renewable Solar-Danell Brothers

-8,346

1,664

 

1,664

-6,682

9731283

WDT - FT - SFPUC - Burton High School PV

-86

80

 

80

-7

9731287

R21-DIS-Forefront-CDCR-1569-RD

-10,000

685

 

685

-9,315

9731300

WDT-SR-Forefront Power-Mouren Farming

-974

1,532

 

1,532

558

9731320

WDT - FT - EPRI - SVUSD Bus Barn Storage

524

3,802

 

3,802

4,326

9731340

R21 - DIS - West Biofuels - SunWest Bio

-9,622

6,077

 

6,077

-3,545

9731341

R21 - DIS - Syn Tech - Lisa Boone Harris

-10,000

337

 

337

-9,663

9731360

WDT-SIS-Solar Electric-SEPV Cuyama 2

-9,736

6,183

 

6,183

-3,554

9731380

R21-DIS-E&J Gallo Winery-Asti Pond Solar

 

842

-10,000

-9,158

-9,158

9731381

R21-DIS-SunPower-EBMUD RESBCT

 

257

-55,000

-54,743

-54,743

9731382

WDT-Forefront Power-Pistachio Road

-9,491

3,011

 

3,011

-6,481

9731383

R21-DIS-Maas Energy-Lakeshore Dairy Dig

-10,000

397

 

397

-9,603

9731480

WDT - FT - REP Energy - VGES 1

 

1,932

-1,000

932

932

9731481

WDT - FT - REP Energy - VGES 2

 

1,932

-1,000

932

932

9731482

WDT - SIS - Rival Power Peterson Road 2

-10,000

2,767

 

2,767

-7,233

9731484

R21 - DIS - JKB Energy-Trinitas Fund II

-9,491

455

 

455

-9,037

9731502

MMA-Q744 Redwood Solar (Phs4)-ISO 50857

44

960

 

960

1,004

9731503

R21-DIS-Concentric-South County Packing

-10,000

1,801

 

1,801

-8,199

9731504

R21-DIS-ARC Alternatives-City of Lincoln

-10,000

86

 

86

-9,914

9731507

WDT-FT-REP Energy-DRES Quarry 2.4

 

931

-1,000

-69

-69

9731510

WDT-FT-Renewable Prop-Palm Drive Solar C

 

2,763

-1,000

1,763

1,763

9731511

WDT-SR-ET Capital-Midway Towers Comm

 

 

-2,500

-2,500

-2,500

9731517

WDT-SR-ET Capital, Inc. East Bay Com Sol

 

 

-2,500

-2,500

-2,500

9731519

WDT-ISP-Calbio Energy-Bar20 Dairy Biogas

-10,000

5,991

 

5,991

-4,009

9731580

R21-DIS-Berry Pet-Berry 21Z and PanFee

 

 

-60,000

-60,000

-60,000

9731582

R21 - DIS - NRG - Calmat Co. Q#: 1593-RD

-10,000

4,059

 

4,059

-5,941

9731620

WDT-ISP-Calbio Energy-MaddoxDairyBiogas

 

2,368

-10,000

-7,632

-7,632

9731621

WDT-ISP-Calbio Energy-Double Diamond

 

1,010

-10,000

-8,990

-8,990

9731622

WDT - FT - Forefront Power - Rocha

 

792

-1,000

-208

-208

9731623

MMA - Q1106 Fountain Wind - ISO 51770

 

638

 

638

638

9731624

R21-DIS--SunPower-West Valley Mission Co

 

257

-10,000

-9,743

-9,743

9731626

R21-DIS-FirestoneWalker-FirestoneBrewery

 

1,829

-10,000

-8,171

-8,171

9731640

WDT-SIS-Green Light Energy-Eagle 2 Solar

 

427

-10,000

-9,573

-9,573

9731680

WDT-FT - DG California Solar-Lodi Solar

 

672

-1,000

-328

-328

9731681

WDT-FT-DG California Solar-MendocinoSola

 

1,745

-1,000

745

745

9731682

R21-DIS-DG Calif Solar, DPIF CA 6 Fresno

 

597

-10,000

-9,403

-9,403

9731700

MMA - Q1141 Alamo Springs - ISO 51745

 

516

 

516

516

9731701

MMA - Q1157 Alamo Springs 2 - ISO 51708

 

200

 

200

200

9731702

WDT-ISP-Forefront Power-Nachtigall

 

804

-10,000

-9,196

-9,196

9731703

WDT-ISP-Forefront Power-Terry

 

1,210

-10,000

-8,790

-8,790

9731720

R21-DIS-ARC Alternatives-County of Kern

 

 

-10,000

-10,000

-10,000

9731722

WDT-SR-Sonoma School-SVUSD Bus Barn Stor

 

1,288

-2,500

-1,212

-1,212

9731723

WDT-Wireless Sur-Cenergy-NLH1 Solar-0102

 

1,049

-900

149

149

9731724

WDT-ISP-Forefront Power-Broadman

 

1,023

-10,000

-8,977

-8,977

9731740

R21-DIS-Forefront-CA Dept of Corr 23100

 

 

-10,000

-10,000

-10,000

9731741

R21-DIS-Forefront-CA Dept of Corr 23104

 

85

-58,000

-57,915

-57,915

9731742

R21-DIS-Forefront-CA Dept of Corr 23102

 

 

-56,000

-56,000

-56,000

9731760

WDT-ISP-Forefront-Dulgarian (1589-WD)

 

40

-10,000

-9,960

-9,960

9731761

WDT-ISP-Forefront-Forefront C2 (1587-WD)

 

80

-10,000

-9,920

-9,920

9731762

WDT-ISP-Forefront-Ava Elizabeth 1586-WD

 

847

-10,000

-9,153

-9,153

9731839

WDT - C9P2 - FCDS - Strauss Wind Energy

 

805

41,301

42,106

42,106

9731840

R21-DIS-Newcomb-City of Fresno(App22373)

 

 

-72,000

-72,000

-72,000

9731841

WDT-EIT-Forefront-1584-WD Mouren Farming

 

644

-10,000

-9,356

-9,356

9731842

MMA - Q705 - Frontier Solar - ISO 4411

 

964

 

964

964

9731880

MMA - Q877-CA Flats Solar 150-ISO 51211

 

480

 

480

480

9731881

R21-DIS-BloomEnergy-KeysightTechnologies

 

1,193

-10,000

-8,807

-8,807

9731920

WDT-ISP-CEDWhiteRiverSolar2-WhiteRiver2

 

718

-10,000

-9,282

-9,282

9731921

MMA - Collins Pine Repower - ISO 51161

 

1,596

 

1,596

1,596

9731960

WDT-SR-RenewProp-1758WD-PalmDriveSolarC

 

1,978

-2,500

-522

-522

9731980

WDT-FT-OHR Energy-RuAnn Dairy Dig BioMAT

 

802

-1,000

-198

-198

9731981

WDT-FT-Apex Energy/ZGlobal-Jade Solar

 

251

-1,000

-749

-749

9732000

R21-DIS-SiliconVallCleanWater-12kVSwitch

 

 

-10,000

-10,000

-10,000

9732001

WDT-FT-RenewProp-Silveira Ranch Solar C

 

576

-1,000

-424

-424

9732002

WDT-FT-RenewProp-Silveira Ranch Solar D

 

576

-1,000

-424

-424

9732003

MMA - Thermalito Powerplant - ISO 51162

 

651

 

651

651

9732020

WDT-FT-RenewProp-Silveira Ranch Solar A

 

576

-1,000

-424

-424

9732021

WDT-FT-RenewProp-Silveira Ranch Solar B

 

746

-1,000

-254

-254

9732022

WDT-FT - EnSync, Inc - 385 Morris

 

81

-1,000

-919

-919

9732060

WDT-SR: Forefront Power-Rocha-1783-WD

 

1,361

-2,500

-1,139

-1,139

9732080

WDT-ISP-YubaCityCogen-WaltonEnergyReliCe

 

 

-100,500

-100,500

-100,500

9732081

WDT-SR: Pathion, Inc. - 1808-WD VGES 1

 

81

-2,500

-2,419

-2,419

9732082

WDT-SR: Pathion, Inc. - 1809-WD VGES 2

 

40

-2,500

-2,460

-2,460

9732100

WDT-ISP: PG&E CoyoteValleyEnergyStorage

 

551

 

551

551

9732121

R21-DIS-Forefront- UCSantaCruz App 23113

 

 

-10,000

-10,000

-10,000

9732122

WDT-FT: Forefront Power - Kern Sunset

 

 

-1,000

-1,000

-1,000

9732123

WDT-FT: Forefront Power - Highway 43

 

 

-1,000

-1,000

-1,000

9732124

WDT-FT: Forefront Power - Beard

 

40

-1,000

-960

-960

9732180

WDT-FCDS: Yuba City Cogen-Walton Energy

 

 

-50,000

-50,000

-50,000

9732260

WDT-ISP: LightsourceRe-Sawmill One Solar

 

 

-57,000

-57,000

-57,000

9732264

WDT - C9P2 - FCDS - Paso Robles 1311-WD

 

 

41,301

41,301

41,301

9732304

WDT-ISP: Ormat Nevada-Pease Reliability

 

 

-10,000

-10,000

-10,000

9732305

WDT-FCDS: Ormat Nevada-Pease Reliability

 

 

-50,000

-50,000

-50,000

9726820

R21-Livermore Community Solar Frm-Det St

11,107

 

-11,107

-11,107

 

9729922

R21 Merced County RES-BCT Detailed Study

-7,576

 

 

 

-7,576

9731460

R21-DIS-Golden State FC-Golden State

 

1,044

-10,000

-8,956

-8,956

9731625

R21-DIS-Crimson Resources-Crimson Resour

 

1,966

-10,000

-8,034

-8,034

 

Total Distribution

-1,621,346

210,858

-484,530

-273,671

-1,895,018

 


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
OTHER REGULATORY ASSETS (Account 182.3)
  1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
  2. 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.
  3. 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
AB802 Memo Account - Electric
325,760
152,674
478,434
2
(amortization: < 12 months)
3
AB802 Memo Account - Gas
266,531
124,914
391,445
4
(amortization: < 12 months)
5
Acc Amt - Plant RA Tax
161,887,481
880,143
162,767,624
6
(amortization: 11 years)
7
Accum Amort - URG Plant Reg Asset
3,520,575
3,520,575
8
(amortization: < 12 months)
9
Accum Amort - URG Plant Reg Asset Non Current
646,489,723
10,560,750
657,050,473
10
(amortization: 12 years)
11
AMCDOP- Cost Adjust Mechanism
49,846,489
13,291,679
53,644,201
9,493,967
12
(amortization: < 12 months)
13
Balancing Account - Utility Generation
13,857,923
577,721,443
361,040,243
202,823,277
14
(amortization: < 12 months)
15
BCA Charge Account
440,257
67,029
1,135,012
627,726
16
(amortization: <12 months)
17
Biomass Memo Account
357,908
15,037,437
4,973,731
10,421,614
18
Bioram Memo Account
5,775,726
6,015,359
6,855,367
4,935,718
19
CA Alternate Rates for Energy Program-Electric
23,438,916
117,774,941
119,038,667
22,175,190
20
(amortization: < 12 months)
21
CA Alternate Rates for Energy Program-Gas
21,906,240
48,458,576
42,366,210
15,813,874
22
(amortization: < 12 months)
23
CA Solar Initiative Thermal Program Memo Account
6,742,116
1,771,281
1,952,994
6,560,403
24
(amortization: < 12 months)
25
Catastrophic Event Memorandum Account
527,923,691
587,233,058
409,463,340
705,693,409
26
(amortization: <12 months)
27
CEE Incentive Electric Balancing Account
2,471,330
21,457
2,164,765
328,022
28
(amortization: < 12 months)
29
CEE Incentive Gas Balancing Account
212,379
550,223
44,850
717,752
30
(amortization: < 12 months)
31
CEMA Gas Noncurrent
26,429,472
817,797
1,664,800
25,582,469
32
(amortization: > 12 months)
33
Core Brokerage Fee
1,183,802
1,624,533
3,282,721
474,386
34
Amortization : < 12 MONTHS
35
Core Fixed Cost Gas Balancing Account
288,383,643
698,346,507
977,389,146
9,341,004
36
(amortization: < 12 months)
37
Core Pipeline Demand Charge Account
12,944,627
137,814,070
163,220,579
12,461,882
38
(amortization: < 12 months)
39
Critical Docs Program memo Acct NC
6,260,968
1,483,343
7,744,311
40
(amortization: > 12 months)
41
Deferred Debit - Gas Reserves (Contra Balancing Ac
206,150,601
138,351,775
114,328,599
182,127,425
42
(amortization: < 12 months)
43
Demand Response Expenditures BA - DRAM
487,925
18,000,000
17,512,075
44
(amortization: > 12 months)
45
Demand Response Expenditures B/A (DREBA)
7,884,858
13,592,136
9,088,059
3,380,781
46
amortization: < 12 months
47
Department of Energy Litigation Balancing Account
15,017,082
15,024,971
48,714
40,825
48
(amortization: > 12 months)
49
Diablo Canyon Seismic Studies Balancing Acct
17,360,284
547,348
17,907,632
50
(amortization: < 12 months)
51
Distribution Revenue Adjustment Mechanism
71,915,222
1,254,301,401
1,006,774,768
175,611,411
52
(amortization: < 12 months)
53
DWR Power Charge Collection Balancing Account
1,170,532
417,680
3,637
756,489
54
(amortization: < 12 months)
55
Dynamic Pricing Memorandum Account
515,392
515,392
56
(amortization: < 12 months)
57
Electric Balancing Account Reserve Account
(a)
999,999,999
(c)
999,999,999
58
Electric Balancing Account Reserve Account
999,999,999
999,999,999
59
Electric Balancing Account Reserve Account
999,999,999
999,999,999
60
Electric Balancing Account Reserve Account
707,101,109
409,864,010
595,350,558
892,587,657
61
(amortization: < 12 months)
62
Electric Hazardous Substance Balancing Account
35,775,193
47,606,804
44,718,990
38,663,007
63
(amortization: < 12 months)
64
Electric Price Risk Management - Current
43,680,362
48,396,156
43,680,362
48,396,156
65
Electric Price Risk Management - NonCurrent
64,887,869
67,899,785
64,887,869
67,899,785
66
Electric Program Investment Charge
4,303,871
23,438,060
28,028,107
286,176
67
(amortization: < 12 months)
68
End-Use Customer Refund Adjustment
18,724,309
4,250,455
2,150,784
16,624,638
69
(amortization: < 12 months)
70
Energy Recovery Bonds Balancing Account
3,772,785
3,455,972
375,265
692,078
71
(amortization: < 12 months)
72
Energy Resource Recovery Account
70,591,762
733,563,700
891,871,537
(d)
87,716,075
73
(amortization: < 12 months)
74
Environmental Compliance
159,159,599
13,088,501
8,191,379
164,056,721
75
(amortization: 32 years)
76
Environmental Compliance Non-HSM
40,989,048
1,900,642
1,484,457
41,405,233
77
(amortization: 32 years)
78
Family Electric Rate Assistance Balancing Acct
6,396,125
1,318,626
6,396,125
1,318,626
79
(amortization: < 12 months)
80
FIN 47 - Regulatory Asset
17,558,035
187,729
17,745,764
81
Financing Costs - Current
1,507,230
43,016
1,464,214
82
(amortization: < 12 months)
83
Financing Costs Regulatory Asset
17,025,505
43,016
376,808
16,691,713
84
(amortization: 20 years)
85
Fire Hazard Prevention Memo Acct
1,078,845
13,581
164,118
928,308
86
(amortization: < 12 Months)
87
Gas Core Firm Storage Account
2,836,041
18,401,478
26,506,512
5,268,993
88
(amortization: < 12 months)
89
Gas Hazardous Substance Balancing Account
83,475,447
110,913,002
104,344,309
90,044,140
90
(amortization: < 12 months)
91
Gas Hazardous Substance Regulatory Asset
375,144,418
27,899,421
20,244,824
382,799,015
92
(amortization: 32 years)
93
Gas Non-Hazardous Substance Regulatory Asset
133,533,912
517,029
389,150
133,661,791
94
(amortization: 32 years)
95
Gas Pipeline Expense and Capital Balancing Account
3,436,047
401,471
3,436,047
401,471
96
(amortization: <12 months)
97
Gas Price Risk Management - Current
1,084,176
1,085,949
1,084,176
1,085,949
98
GPBA-Greenhouse Gas Compliance Subaccount
157,201,621
45,232,188
202,433,809
99
(amortization: < 12 months)
100
Gas Public Purpose Program Surcharge Memo Acct
45,383,992
68,949,957
46,351,991
67,981,958
101
(amortization: < 12 months)
102
Gas Transmission and Storage Memo Account
180,904,540
107,643,362
47,051,720
241,496,182
103
(amortization: < 12 months)
104
Gas Transmission and Storage Revenue Sharing Mech.
18,143,606
101,380,451
100,901,982
18,622,075
105
(amortization: < 12 months)
106
GPBA - GHG Operational Cost Subaccount
27,406,445
11,873,092
39,279,537
107
(amortization: < 12 months)
108
Green Tariff Shared Renewables Bal Acct
106,047
1,819,489
1,277,596
647,940
109
(amortization: < 12 months)
110
Greem Tariff Shared Renewables Memo Acct
4,996,470
184,347
105,464
5,075,353
111
(amortization: < 12 months)
112
Greenhouse Gas Expense Memo Account - E
1,892,398
153,291
7,228
1,746,335
113
Greenhouse Gas Expense Memo Account - G
334,859
108,368
28,760
414,467
114
(amortization: < 12 months)
115
GTSMA - Noncurrent
103,417,415
103,417,415
116
(amortization: > 12 months)
117
Hydro Licensing Balancing Account
20,372,843
307,942
6,924,241
26,989,142
118
(amortization: > 12 months)
119
Land Conserv. Plan Env. Remediation Memo Acct.
746,382
177,565
746,382
177,565
120
(amortization: < 12 months)
121
Line 407 Memo Acct NC
301,110
668,282
969,392
122
(amortization: > 12 months)
123
Major Emergency Balancing Account
288,710
20,750,767
19,347,713
1,691,764
124
(amortization: < 12 Months)
125
Market Redesign & Technology Memo Account
751,168
751,168
126
(amortization: < 12 months)
127
Miscellaneous Electric Reg Asset - Current
481,041,835
19,382,191
733,178
499,690,848
128
(amortization: < 12 months)
129
Miscellaneous Gas Reg Asset - Current
3,865,759
4,470,074
8,335,833
130
(amortization: < 12 months)
131
Miscellaneous Electric Reg Asset - Noncurrent
9,638,676
50,048,836
9,395,469
50,292,043
132
(amortization: 25 years)
133
Mobile Home Park BA Electric Current
1,622,479
613,636
480,658
1,755,457
134
(amortization: < 12 months)
135
Mobile Home Park BA Electric NC
15,117,286
3,538,026
2,975,154
15,680,158
136
(amortization: > 12 months)
137
Mobile Home Park BA Gas Current
1,806,908
934,620
552,950
2,188,578
138
(amortization: < 12 months)
139
Mobile Home Park BA Gas NC
17,475,604
4,265,410
1,548,441
20,192,573
140
(amortization: > 12 months)
141
Mobile Home Park Balancing Account - Electric
7,093,489
3,778,083
7,093,490
3,778,082
142
(amortization: < 12 months)
143
Mobile Home Park Balancing Account - Gas
7,269,902
3,598,198
7,269,901
3,598,199
144
(amortization: < 12 months)
145
Modified transition cost balancing account
10,808,975
6,231,993
18,884,711
23,461,693
146
(amortization: < 12 months)
147
Negative Ongoing Competition Transition Chrg BA
3,089,668,292
6,261,137
179,905
3,095,749,524
148
(amortization: < 12 months)
149
New Environmental Regulations Balancing Account
1,726,803
690,204
1,036,599
150
(amortization: > 12 months)
151
New System Generation BA
46,650,016
102,368,396
43,849,021
(e)
11,869,359
152
(amortization: < 12 months)
153
Non Current HSM BA Elec
38,439,275
16,397,536
46,630,654
8,206,157
154
(amortization: > 12 months)
155
Non Current HSM BA Gas
89,691,641
38,260,917
108,804,859
19,147,699
156
(amortization: > 12 months)
157
Nuclear Decommissioning Adjustment Mechanism
45,752,788
17,094,511
27,615,354
56,273,631
158
(amortization: 2 years)
159
Nuclear Regulatory Commission Rulemaking Costs BA
8,001,467
8,820,966
9,063,782
7,758,651
160
(amortization: > 12 Months)
161
Pension Regulatory Asset
1,953,963,992
689,583
39,328,194
1,915,325,381
162
(amortization: indefinite)
163
Procurement Energy Efficiency Rev. Adj. Mechanism
11,603,488
61,635,595
50,446,502
22,792,581
164
(amortization: < 12 months)
165
Public Purpose Programs Revenue Adjustment Mech.
26,720,208
50,903,637
50,521,337
26,337,908
166
(amortization: < 12 months)
167
Purchased Gas Balancing Account
2,119,259
535,703,953
534,723,669
3,099,543
168
(amortization: < 12 months)
169
Reg Asset - Abandoned Capital Projects
18,324,235
8,716,520
4,358,264
22,682,491
170
(amortization: < 12 months)
171
Reg Asset - Hydro Non Current
10,758,023
41,173
3,863
10,795,333
172
(amortization: > 12 months)
173
Reg Asset - Cema Elec Non Current
322,049,440
56,787,054
15,564,252
363,272,242
174
(amortization: > 12 months)
175
Reliability Services Balancing Account
410,816
26,337,258
13,842,394
12,084,048
176
(amortization: < 12 months)
177
Renewables Portfolio Standard Cost Memo Acct
283,130
1,113
284,243
178
(amortization: < 12 months)
179
Residential Rate Reform Memorandum Account (RRRMA)
19,253,940
3,725,787
4,892,931
18,086,796
180
(amortization: < 12 months)
181
Tax Normalization Memo Account (TNMA)
9,965,012
1,889,375
11,854,387
182
(amortization: > 12 months)
183
Transition Cost - Noncore Balancing Account
2,314,575
108,353,104
52,128,793
53,909,736
184
(amortization: < 12 months)
185
Transmission Access Charge Balancing Account
139,010,141
86,146,086
112,092,168
113,064,059
186
(amortization: < 12 months)
187
Transmission Integrity Mgmt Balancing Account
115,856,993
115,856,993
188
(amortization: > 12 months)
189
Transmission Integrity Mgmt BA - Current
106,522,415
18,668,920
87,853,495
190
(amortization: < 12 months)
191
Transmission Revenue Balancing Account
101,030,149
57,129,514
47,624,122
91,524,757
192
(amortization: < 12 months)
193
Unamortized Financial Hedging Cost
12,779,844
209,049
12,570,795
194
(amortization: 20 years)
195
Unamortized Financial Hedging Cost Current
836,195
836,195
196
(amortization: < 12 months)
197
URG Plant Regulatory Asset - current
42,239,000
42,239,000
198
(amortization: < 12 months)
199
URG Plant Regulatory Asset - noncurrent
944,805,000
944,805,000
200
(amortization: 22 years)
201
URG Plant Regulatory Asset - Tax
183,010,953
183,010,953
202
(amortization: 11 years)
203
Vegetation Management Reg. Asset - Current
15,848,080
36,986,067
37,452,601
15,381,546
204
(amortization: < 12 months)
205
Wildfires Customer Protections Memo Acct - Elec
863,075
863,075
206
(amortization: > 12 months)
207
Wildfires Customer Protections Memo Acct - Gas
706,152
706,152
208
(amortization: > 12 months)
209
Miscellaneous minor items
346,369
75,383,202
75,581,786
147,785
44
TOTAL
5,018,800,793
7,010,836,041
6,936,869,750
5,092,767,084


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets

The FERC software will not allow the entire beginning balance of Electric Balancing Account Reserve Account of ($3,707,101,106) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 14: ($999,999,999)

Line 15: ($999,999,999)

Line 16: ($999,999,999)

Line 17: ($707,101,109)

Total ($3,707,101,106)

(b) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Primarily Integrated Distribution Energy resources and Land Conservation Plan Implementation account, offset to 400 and 182.3, respectively.

(c) Concept: OtherRegulatoryAssets

The FERC software will not allow the ending beginning balance of Electric Balancing Account Reserve Account of ($3,892,587,654) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 14: ($999,999,999)

Line 15: ($999,999,999)

Line 16: ($999,999,999)

Line 17: ($892,587,657)

Total ($3,892,587,654)

(d) Concept: OtherRegulatoryAssets

Ending balance reflects reclass of $71.3 million of ISO revenues related to the Midway Sunset Power Purchase Agreement from the New Generation System Balancing Account to the Energy Resource Balance Account

(e) Concept: OtherRegulatoryAssets

Ending balance reflects reclass of $71.3 million of ISO revenues related to the Midway Sunset Power Purchase Agreement from the New Generation System Balancing Account to the Energy Resource Balance Account


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
OTHER REGULATORY LIABILITIES (Account 254)
  1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
  2. 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.
  3. 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
CA Energy Systems 21st Centur B/A Elect NC
308,025
929,096
865,149
371,972
2
(amortization: 5 years)
3
California Solar Initiative
66,414,573
3,345,161
2,235,728
65,305,140
4
(amortization: 5 years)
5
Demand Response Expenditures Balancing Account
57,642,744
27,507,070
16,445,590
46,581,264
6
Distribution Resource Plan Demo B/A Curr
107,978
170,566
263,887
201,299
7
(amortization: <12 months)
8
Electric Vehicle Program BA Current
1,972,296
1,992,400
6,194,751
2,230,055
9
(amortization: <12 months)
10
Electric Price Risk Management - Current
26,867,114
26,867,114
27,139,479
27,139,479
11
Electric Price Risk Management - NonCurrent
101,500,411
101,500,411
97,340,636
97,340,636
12
Electric Program Investment Charge Balancing Acct
173,193,908
25,984,378
23,886,137
171,095,667
13
Engineering Critical Assessment Bal NC
806,019
51,811,434
51,005,415
14
(amortization: >12 months)
15
FAS 109 Reg Liability
1,020,833,435
147,548,241
873,285,194
16
(amortization: >12 months)
17
FAS 143 Regulatory Liability - Nuclear
(a)
999,999,999
(e)
999,999,999
18
FAS 143 Regulatory Liability - Nuclear
574,459,930
60,227,550
29,701,949
604,985,531
19
FAS 143 Regulatory Liability - Fossil
132,024,941
3,484,857
135,509,798
20
FAS 143 Regulatory Liability - Fossil Decomm
176,633,546
1,619,653
175,013,893
21
FAS 143 Regulatory Liability-Nuclear Decomm
2,863,247,225
156,904,457
135,696,741
2,842,039,509
22
FIN 47 Regulatory Liability
709,047,472
271,956,407
237,172,761
743,831,118
23
Gas PPP Surcharge-RDD
398,165
3,108,828
3,982,512
475,519
24
(amortization: <12 months)
25
Gas Price Risk Management - Current
376,079
376,079
386,789
386,789
26
GHGRBA - Greenhouse Gas Revenue Subaccount
89,838,359
12,362,662
85,816,308
163,292,005
27
(amortization: <12 months)
28
GHGRBA - Low Carbon Fuels Stnd Rev Subaccount
18,626,564
4,042,533
67,533
14,651,564
29
(amortization: <12 months)
30
GPBA - Greenhouse Gas Revenue Subaccount
222,829,867
26,903,804
249,733,671
31
(amortization: <12 months)
32
GPBA - Low Carbon Fuels Stnd Rev Subaccount
685,998
18,170
2,715
670,543
33
(amortization: <12 months)
34
Miscellaneous Electric Reg Liab - Current
80,613,478
72,172,089
152,785,567
35
(amortization: <12 months)
36
Miscellaneous Electric Reg Liab - NonCurrent
245,025,521
4,134,375
66,651,854
307,543,000
37
Miscellaneous Gas Reg Liab - Current
9
10,212,215
28,149,715
17,937,509
38
(amortization: <12 months)
39
Miscellaneous Gas Reg Liab - NonCurrent
19,026,468
3,382,670
2,301,437
17,945,235
40
(amortization: 2 years)
41
Non Current Reg Liab-CC8 Settlement
46,856,179
565,126
46,291,053
42
(amortization: 25 Years)
43
On Bill Financing Balancing Electric
44,053,920
8,551,299
11,527,296
47,029,917
44
On Bill Financing Balancing Gas
9,541,492
1,628,819
2,200,196
10,112,869
45
PPP (PPPLIBA)-Electric
161,760,083
16,763,489
22,841,822
167,838,416
46
(amortization: <12 months)
47
PPP (PPPLIBA)-Gas
57,115,769
11,976,962
19,250,544
64,389,351
48
(amortization: <12 months)
49
PPP Energy Efficiency-Gas
3,523,260
571,536
13,585
2,965,309
50
PPP Surcharge Energy Efficiency - Gas
6,165,082
18,478,053
25,574,384
13,261,413
51
(amortization: <12 months)
52
PPP Surcharge Low Income - Gas
8,697,021
20,325,274
31,334,140
2,311,845
53
(amortization: <12 months)
54
PPP Surcharge RDD - Current
3,589,635
2,856,403
2,774,433
3,507,665
55
(amortization: <12 months)
56
Procurement Energy Efficiency
15,108,043
2,603,763
58,297
12,562,577
57
Procurement Energy Efficiency Bal Acct Current
121,365,565
62,073,412
89,915,758
149,207,911
58
(amortization: <12 months)
59
Publ Purp Prog Energy Efficiency Bal Acct Current
24,615,781
11,823,507
17,132,701
29,924,975
60
(amortization: <12 months)
61
Regulatory Liability Retirement
418,061,715
6,743,346
424,805,061
62
(amortization: indefinite)
63
Rule 20A Balancing Account (RBA) - NC
12,529,856
7,259,115
5,270,741
64
(amortization: > 12 months)
65
Self Generation Program - Electric
180,387,537
3,283,142
15,584,872
192,689,267
66
Self Generation Program-Gas
35,020,030
720,690
3,403,080
37,702,420
67
SW Marketing, Education and Outreach Program BA
4,349,170
3,191,068
2,706,514
3,864,616
68
SW Marketing, Education and Outreach Program BA
755,732
352,988
300,343
703,087
69
TAMA - Gas
64,490,315
64,490,315
70
(amortization: 2 Years)
71
Vegetation Management BA
50,829,356
53,344,783
2,515,427
72
(amortization: < 12 months)
73
Miscellanous minor items
71,771,391
74,501,172
2,847,755
117,974
41 TOTAL
(f)
3,876,105,498
1,172,106,827
1,230,001,962
3,934,000,632


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities

The FERC software will not allow the entire beginning balance of FAS 143 Regulatory Liability of ($1,574,459,929) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 18: ($999,999,999)

Line 19: ($574,459,930)

Total ($1,574,459,929)

(b) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

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

(c) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

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

(d) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Activity primarily related to Non-Tariff Products offset to 182.3

(e) Concept: OtherRegulatoryLiabilities

The FERC software will not allow the entire ending balance of FAS 143 Regulatory Liability of ($1,604,985,530) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 18: ($999,999,999)

Line 19: ($604,985,531)

Total ($1,604,985,530)

(f) Concept: OtherRegulatoryLiabilities
Duplicate fact discrepancy. Schedule: 278 - Schedule - Other Regulatory Liabilities (Account 254), Row: 41, Column: b, Value: 3876105497

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
Electric Operating Revenues
  1. 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.
  2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
  3. 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.
  4. 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.
  5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
  6. 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.)
  7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
  8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
  9. 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
1,335,924,700
6,985,130
4,757,488
3
CommercialAndIndustrialSalesAbstract
(442) Commercial and Industrial Sales
4
CommercialSalesAbstract
Small (or Comm.) (See Instr. 4)
(a)
1,197,588,895
8,050,356
637,532
5
IndustrialSalesAbstract
Large (or Ind.) (See Instr. 4)
(b)
323,724,902
3,599,438
1,342
6
PublicStreetAndHighwayLightingAbstract
(444) Public Street and Highway Lighting
17,497,338
81,926
35,042
7
OtherSalesToPublicAuthoritiesAbstract
(445) Other Sales to Public Authorities
471,415
3,908
7
8
SalesToRailroadsAndRailwaysAbstract
(446) Sales to Railroads and Railways
1,667,028
98,728
25
9
InterdepartmentalSalesAbstract
(448) Interdepartmental Sales
8,832,884
64,850
10
SalesToUltimateConsumersAbstract
TOTAL Sales to Ultimate Consumers
(c)
2,885,707,162
18,884,336
5,431,436
11
SalesForResaleAbstract
(447) Sales for Resale
4,319,096
12
SalesOfElectricityAbstract
TOTAL Sales of Electricity
2,890,026,258
18,884,336
5,431,436
13
ProvisionForRateRefundsAbstract
(Less) (449.1) Provision for Rate Refunds
122,028,996
14
RevenuesNetOfProvisionForRefundsAbstract
TOTAL Revenues Net of Prov. for Refunds
2,767,997,262
18,884,336
5,431,436
15
OtherOperatingRevenuesAbstract
Other Operating Revenues
16
ForfeitedDiscounts
(450) Forfeited Discounts
1,170,396
17
MiscellaneousServiceRevenues
(451) Miscellaneous Service Revenues
(d)
2,649,403
18
SalesOfWaterAndWaterPower
(453) Sales of Water and Water Power
636,963
19
RentFromElectricProperty
(454) Rent from Electric Property
28,329,032
20
InterdepartmentalRents
(455) Interdepartmental Rents
21
OtherElectricRevenue
(456) Other Electric Revenues
(e)
111,153,164
22
RevenuesFromTransmissionOfElectricityOfOthers
(456.1) Revenues from Transmission of Electricity of Others
164,770
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
274,399,882
26
OtherOperatingRevenues
TOTAL Other Operating Revenues
196,197,282
27
ElectricOperatingRevenues
TOTAL Electric Operating Revenues
2,964,194,544


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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 Kw or greater.

(c) Concept: SalesToUltimateConsumers

Column (b) includes California Department of Water Resources ("DWR") revenues of $93,117,331 which was deducted from Line 21 below.

(d) Concept: MiscellaneousServiceRevenues

 

This consists of :

 

NSF fees and rent charges to customers' refundable deposits

382,453

NRD Revenue

888,694

MLX billings to electric residential customers

811,922

MLX billings to electric non-residential customers

226,741

Reimbursable third-party labor requested on behalf of customers

339,593

 

 

Total

2,649,403

(e) Concept: OtherElectricRevenue

 

This consists of :

 

Unbilled revenues

(50,483,029)

Reimbursement to the Utility for costs spent on customer projects

8,413,677

Reimbursement to the Utility for costs spent on customer billing

1,689,626

Reimbursement fees paid to the CPUC based on sales

(8,533,963)

Employee transfer fees

341,127

Other revenue-damage claim

671,336

Recreational Facilities Revenue

41,161

Revenue assigned - base

(5,247,639)

Pass-through franchise fees and uncollectible revenue

5,247,639

Transition Cost Revenue Account for non-bypassable charges

9,358,616

Fees for utility energy service contracts

7,362,086

Other electric revenues not classified elsewhere

12,926,497

MCI rights of way

172,915

DWR

(93,117,331)

Miscellaneous (items under $250,000)

4,118

 

 

Total

(111,153,164)

 

The DWR revenues of $93,117,331 represents amount passed through to the DWR. The Utility acts as a pass-through entity for DWR charges collected from the Utility's customers. 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
  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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
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)
61,386,057
3
SteamPowerGenerationMaintenanceExpense
Steam Power Generation – Maintenance (510-515)
3,215,010
4
PowerProductionExpensesSteamPower
Total Power Production Expenses - Steam Power
64,601,067
5
NuclearPowerGenerationOperationsExpense
Nuclear Power Generation – Operation (517-525)
136,765,521
6
NuclearPowerGenerationMaintenanceExpense
Nuclear Power Generation – Maintenance (528-532)
6,364,578
7
PowerProductionExpensesNuclearPower
Total Power Production Expenses - Nuclear Power
143,130,099
8
HydraulicPowerGenerationOperationsExpense
Hydraulic Power Generation – Operation (535-540.1)
20,816,602
9
HydraulicPowerGenerationMaintenanceExpense
Hydraulic Power Generation – Maintenance (541-545.1)
11,058,671
10
PowerProductionExpensesHydraulicPower
Total Power Production Expenses - Hydraulic Power
31,875,273
11
RentsOtherPowerGeneration
Other Power Generation – Operation (546-550.1)
3,036,275
12
MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration
Other Power Generation – Maintenance (551-554.1)
2,698,375
13
MaintenanceOfMiscellaneousOtherPowerGenerationPlant
Total Power Production Expenses - Other Power
5,734,650
14
OtherPowerSuplyExpensesAbstract
Other Power Supply Expenses
15
PurchasedPower
(555) Purchased Power
(a)
671,146,506
15.1
PowerPurchasedForStorageOperations
(555.1) Power Purchased for Storage Operations
16
SystemControlAndLoadDispatchingElectric
(556) System Control and Load Dispatching
17
OtherExpensesOtherPowerSupplyExpenses
(557) Other Expenses
72,767,041
18
OtherPowerSupplyExpense
Total Other Power Supply Expenses (line 15-17)
743,913,547
19
PowerProductionExpenses
Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)
989,254,636
20
TransmissionExpensesAbstract
2. TRANSMISSION EXPENSES
21
TransmissionExpensesOperationAbstract
Transmission Operation Expenses
22
OperationSupervisionAndEngineeringElectricTransmissionExpenses
(560) Operation Supervision and Engineering
847,354
24
LoadDispatchReliability
(561.1) Load Dispatch-Reliability
25
LoadDispatchMonitorAndOperateTransmissionSystem
(561.2) Load Dispatch-Monitor and Operate Transmission System
7,600,558
26
LoadDispatchTransmissionServiceAndScheduling
(561.3) Load Dispatch-Transmission Service and Scheduling
27
SchedulingSystemControlAndDispatchServices
(561.4) Scheduling, System Control and Dispatch Services
5,323,790
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
2,048,468
32
StationExpensesTransmissionExpense
(562) Station Expenses
1,946,374
32.1
OperationOfEnergyStorageEquipmentTransmissionExpense
(562.1) Operation of Energy Storage Equipment
33
OverheadLineExpense
(563) Overhead Lines Expenses
1,356,882
34
UndergroundLineExpensesTransmissionExpense
(564) Underground Lines Expenses
158,174
35
TransmissionOfElectricityByOthers
(565) Transmission of Electricity by Others
229,896
36
MiscellaneousTransmissionExpenses
(566) Miscellaneous Transmission Expenses
21,515,712
37
RentsTransmissionElectricExpense
(567) Rents
38
OperationSuppliesAndExpensesTransmissionExpense
(567.1) Operation Supplies and Expenses (Non-Major)
39
TransmissionOperationExpense
TOTAL Transmission Operation Expenses (Lines 22 - 38)
41,027,208
40
TransmissionMaintenanceAbstract
Transmission Maintenance Expenses
41
MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses
(568) Maintenance Supervision and Engineering
209,097
42
MaintenanceOfStructuresTransmissionExpense
(569) Maintenance of Structures
106,909
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
(b)
5,455,351
47.1
MaintenanceOfEnergyStorageEquipmentTransmission
(570.1) Maintenance of Energy Storage Equipment
48
MaintenanceOfOverheadLinesTransmission
(571) Maintenance of Overhead Lines
19,563,005
49
MaintenanceOfUndergroundLinesTransmission
(572) Maintenance of Underground Lines
203,196
50
MaintenanceOfMiscellaneousTransmissionPlant
(573) Maintenance of Miscellaneous Transmission Plant
186,799
51
MaintenanceOfTransmissionPlant
(574) Maintenance of Transmission Plant
52
TransmissionMaintenanceExpenseElectric
TOTAL Transmission Maintenance Expenses (Lines 41 – 51)
25,724,357
53
TransmissionExpenses
Total Transmission Expenses (Lines 39 and 52)
66,751,565
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
3,220,438
63
RegionalMarketOperationExpense
Regional Market Operation Expenses (Lines 55 - 62)
3,220,438
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)
3,220,438
72
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
73
DistributionOperationExpensesElectric
Distribution Operation Expenses (580-589)
(c)
35,105,113
74
DistributionMaintenanceExpenseElectric
Distribution Maintenance Expenses (590-598)
(d)
142,739,546
75
DistributionExpenses
Total Distribution Expenses (Lines 73 and 74)
177,844,659


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: PurchasedPower

Of the quarter end balance,($58,374) relates to energy storage operation per FERC Order 784.

(b) Concept: MaintenanceOfStationEquipmentTransmission

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

(c) Concept: DistributionOperationExpensesElectric

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

(d) Concept: DistributionMaintenanceExpenseElectric

Of the quarter end balance, $16,360 relate 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1

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
45,291,470
2
CustomerServiceAndInformationExpenses
(907-910) Customer Service and Information Expenses
92,492,183
3
SalesExpenses
(911-917) Sales Expenses
234,709
4
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
5
AdministrativeAndGeneralExpensesOperationAbstract
Operation
6
AdministrativeAndGeneralSalaries
(920) Administrative and General Salaries
115,866,044
7
OfficeSuppliesAndExpenses
(921) Office Supplies and Expenses
8,225,947
8
AdministrativeExpensesTransferredCredit
(Less) (922) Administrative Expenses Transferred-Credit
60,891,695
9
OutsideServicesEmployed
(923) Outside Services Employed
51,908,131
10
PropertyInsurance
(924) Property Insurance
2,600,369
11
InjuriesAndDamages
(925) Injuries and Damages
92,935,833
12
EmployeePensionsAndBenefits
(926) Employee Pensions and Benefits
(a)
76,242,457
13
FranchiseRequirements
(927) Franchise Requirements
18,011,218
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
1,187,263
18
RentsAdministrativeAndGeneralExpense
(931) Rents
19
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Total of lines 6 thru 18)
300,884,829
20
AdministrativeAndGeneralExpensesMaintenanceAbstract
Maintenance
21
MaintenanceOfGeneralPlant
(935) Maintenance of General Plant
1,368,793
22
AdministrativeAndGeneralExpenses
TOTAL Administrative and General Expenses (Total of lines 19 and 21)
302,253,622


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: EmployeePensionsAndBenefits

Of the quarter end balance, $0 relate 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
  1. 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.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
  3. 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).
  4. 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.
  5. 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.
  6. 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.
  7. 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.
  8. Report in column (i) and (j) the total megawatthours received and delivered.
  9. 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 (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  10. 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.
  11. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.
PaymentByCompanyOrPublicAuthority
Payment By (Company of Public Authority) (Footnote Affiliation)
(a)
TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Energy Received From (Company of Public Authority) (Footnote Affiliation)
(b)
TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Energy Delivered To (Company of Public Authority) (Footnote Affiliation)
(c)
StatisticalClassificationCode
Statistical Classification
(d)
RateScheduleTariffNumber
Ferc Rate Schedule of Tariff Number
(e)
TransmissionPointOfReceipt
Point of Receipt (Substation or Other Designation)
(f)
TransmissionPointOfDelivery
Point of Delivery (Substation or Other Designation)
(g)
BillingDemand
Billing Demand (MW)
(h)
TransmissionOfElectricityForOthersEnergyReceived
Megawatt Hours Received
(i)
TransmissionOfElectricityForOthersEnergyDelivered
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
RevenuesFromTransmissionOfElectricityForOthers
Total Revenues ($) (k+l+m)
(n)
1
TRANSMISSION AGENCY OF
2
(a)
NORTHERN CALIFORNIA (TANC)
VARIOUS
VARIOUS
MIDWAY
VARIOUS
233
117,723
115,497
557,512
60,716
618,228
35 TOTAL
233
117,723
115,497
557,512
60,716
618,228


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

1 - Other Charges represent booking estimate adjustments. In September 2003 the Utility changed 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.

 

2 - Transmission is provided under the Midway Transmission Service.

 

3 - 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
  1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
  3. 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.
  4. 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.
  5. In column (d) report the revenue amounts as shown on bills or vouchers.
  6. 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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40
TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
  1. 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.
  2. 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.
  3. 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.
  4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
  5. 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.
  6. Enter ""TOTAL"" in column (a) as the last line.
  7. 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
(b)
62,967
62,967
3
Pacificorp
(c)
69,177
69,177
4
Western Area Power
5
Administration
(a)
564
564
6
California-Oregon
7
Intertie
(d)
97,187
97,187
TOTAL
564
229,331
229,895


FOOTNOTE DATA

(a) Concept: DemandChargesTransmissionOfElectricityByOthers

Represents payments for lease of transmission capacity.

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for operations and maintenance costs.

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for operations and maintenance costs.

(d) 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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
  1. 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
641,546
641,546
2
Steam Production Plant
4,991,265
4,991,265
3
Nuclear Production Plant
74,978,431
9,682,893
84,661,324
4
Hydraulic Production Plant-Conventional
18,465,856
1,188,000
19,653,856
5
Hydraulic Production Plant-Pumped Storage
3,088,117
570,000
3,658,117
6
Other Production Plant
12,375,584
12,375,584
7
Transmission Plant
77,705,582
77,705,582
8
Distribution Plant
298,232,048
298,232,048
9
General Plant
7,436,376
7,436,376
10
Common Plant-Electric
37,112,718
45,685,654
82,798,372
11
TOTAL
534,385,977
46,327,200
11,440,893
592,154,070


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
  1. 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)
91,388,877
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
8,123,190
4 Transmission Rights
5 Ancillary Services
2,358,942
6 Other Items (list separately)
7
Grid Management Charges
10,595,990
8
FERC Fees
1,047,892
9
ISO Congestion
10
Unaccounted for Energy
5,331,131
11
Congestion Revenue Rights-Hedge
6,984,607
12
Congestion Revenue Rights-Auction
623,720
13
Convergence Bidding
28,243
14
Other ISO-related charges:
15
Minimum Load
16
Neutrality
150,330
17
Voltage Support
18
Other
3,638,725
19
Cost Recovery
1,012,384
20
Inter Day Ahead SC Trade
21
Inter Real Time SC Trade
22
Interest
209,893
23
Capacity - Other
388,198
24
DA IFM Credit Allocation
8,073,047
25
RT Offset/Allocation
5,618,045
26
Net Purchases for Energy Storage
58,374
46 TOTAL
104,831,614


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
  1. 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.
  2. Report in column (b) by month the system’s output in Megawatt hours for each month.
  3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
  4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
  5. 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
6,936,447
11,901
8
1,900
2
February
(a)
6,521,940
12,437
20
1,900
3
March
(b)
7,049,805
11,479
5
2,000
4
Total for Quarter 1
20,508,192
5
April
6
May
7
June
8
Total for Quarter 2
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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: EnergyActivity

Based on preliminary data at time of filing.

(b) Concept: EnergyActivity

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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
  1. 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.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. 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
13,520
8
1,900
8,128
50
5,342
2
February
14,095
20
1,900
8,911
5,184
3
March
(a)
13,009
5
2,000
(b)
8,520
(c)
4,489
4
Total for Quarter 1
25,559
50
15,015
5
April
6
May
7
June
8
Total for Quarter 2
9
July
10
August
11
September
12
Total for Quarter 3
13
October
14
November
15
December
16
Total for Quarter 4
17
Total
25,559
50
15,015


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

The source of the entries in this column is the metered data from Pacific Gas and Electric Company's (the "Utility") Daily Service Report, Line 9.

(b) Concept: FirmNetworkServiceForSelf

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

(c) Concept: OtherService

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:

05/03/2018
Year/Period of Report

End of:
2018
/
Q1
Monthly ISO/RTO Transmission System Peak Load
  1. 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.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. 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).
  5. 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: Enter System
1
January
2
February
3
March
4
Total for Quarter 1
5
April
6
May
7
June
8
Total for Quarter 2
9
July
10
August
11
September
12
Total for Quarter 3
13
October
14
November
15
December
16
Total for Quarter 4
17
Total Year to Date/Year

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