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ferc:NegotiatedRateMember 2018-02-01 2018-02-28 C000654 0-3 2018-01-01 2018-03-31 C000654 0-65 2018-03-01 2018-03-31 C000654 0-19 2017-12-31 C000654 0-71 2018-02-01 2018-02-28 C000654 0-5 2018-01-01 2018-03-31 C000654 0-16 2017-12-31 C000654 2018-03-01 2018-03-31 C000654 ferc:IntangiblePlantMember ferc:GasUtilityMember 2018-01-01 2018-03-31 C000654 ferc:RecourseRateMember 2018-02-01 2018-02-28 C000654 0-56 ferc:DiscountedRateMember 2018-02-01 2018-02-28 C000654 0-6 2018-03-01 2018-03-31 C000654 2017-03-31 C000654 0-16 2018-03-31 C000654 0-56 2018-01-01 2018-03-31 C000654 2017-12-31 C000654 0-12 2017-12-31 C000654 ferc:DiscountedRateMember 2018-02-01 2018-02-28 C000654 0-1 2018-01-01 2018-03-31 C000654 0-3 2018-02-01 2018-02-28 C000654 0-58 2018-01-01 2018-03-31 iso4217:USD pure ferc:dth
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
Resubmission No.

FERC FINANCIAL REPORT
FERC FORM No. 2: Annual Report of
Major Natural Gas Companies and
Supplemental Form 3-Q: Quarterly
Financial Report

These reports are mandatory under the Natural Gas Act, Sections 10(a), and 16 and 18 CFR Parts 260.1 and 260.300. 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 a confidential nature.
Exact Legal Name of Respondent (Company)

Transcontinental Gas Pipe Line Company, LLC
Year/Period of Report:

End of:
2018
/
Q1


INSTRUCTIONS FOR FILING FERC FORMS 2, 2-A and 3-Q

GENERAL INFORMATION

  1. Purpose

    FERC Forms 2, 2-A, and 3-Q are designed to collect financial and operational information form natural gas companies subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be a non-confidential public use forms.
  2. Who Must Submit

    Each natural gas company whose combined gas transported or stored for a fee exceed 50 million dekatherms in each of the previous three years must submit FERC Form 2 and 3-Q.

    Each natural gas company not meeting the filing threshold for FERC Form 2, but having total gas sales or volume transactions exceeding 200,000 dekatherms in each of the previous three calendar years must submit FERC Form 2-A and 3-Q.

    Newly established entities must use projected data to determine whether they must file the FERC Form 3-Q and FERC Form 2 or 2-A.
  3. What and Where to Submit

    1. Submit Forms 2, 2-A and 3-Q electronically through the submission software at http://www.ferc.gov/docs-filing/eforms/form-2/elec-subm-soft.asp .
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Form 2 and 3-Q filings.
    3. Submit immediately upon publication, by either eFiling or mailing two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders and any annual financial or statistical report regularly prepared and distributed to bondholders, security analysts, or industry associations. Do not include monthly and quarterly reports. Indicate by checking the appropriate box on Form 2, Page 3, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders is prepared. Unless eFiling the Annual Report to Stockholders, mail these reports to the Secretary of the Commission at:

      Secretary of the Commission
      Federal Energy Regulatory Commission
      888 First Street, NE
      Washington, DC 20426
    4. For the Annual CPA certification, submit with the original submission of this form, a letter or report (not applicable to respondents classified as Class C or Class D prior to January 1, 1984) prepared in conformity with the current standards of reporting which will:
      1. Contain a paragraph attesting to the conformity, in all material respects, of the schedules listed below with the Commission's applicable Uniform Systems 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. §§ 158.10-158.12 for specific qualifications.)

        Reference
        Reference 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
      Filers should state in the letter or report, which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist
    5. 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 website at http://www.ferc.gov/help/how-to.asp.
    6. Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 2 and 2-A free of charge from: http://www.ferc.gov/docs-filing/forms/form-2/form-2.pdf and http://www.ferc.gov/docs-filing/forms/form-2a/form-2a.pdf, respectively. Copies may also be obtained from the Public Reference and Files Maintenance Branch, Federal Energy Regulatory Commission, 888 First Street, NE. Room 2A, Washington, DC 20426 or by calling (202).502-8371
  4. When to Submit:

    FERC Forms 2, 2-A, and 3-Q must be filed by the dates:

    1. FERC Form 2 and 2-A --- by April 18th of the following year (18 C.F.R. §§ 260.1 and 260.2)
    2. FERC Form 3-Q --- Natural gas companies that file a FERC Form 2 must file the FERC Form 3-Q within 60 days after the reporting quarter (18 C.F.R.§ 260.300), and
    3. FERC Form 3-Q --- Natural gas companies that file a FERC Form 2-A must file the FERC Form 3-Q within 70 days after the reporting quarter (18 C.F.R. § 260.300).
  5. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the Form 2 collection of information is estimated to average 1,623 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 Form 2A collection of information is estimated to average 250 hours per response. The public reporting burden for the Form 3-Q collection of information is estimated to average 167 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 all reports in conformity with the Uniform System of Accounts (USofA) (18 C.F.R. Part 201). Interpret all accounting words and phrases in accordance with the USofA.
  2. Enter in whole numbers (dollars or Dth) 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.
  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 only. Please explain the reason for the resubmission in a footnote to the data field.
  8. Footnote and further explain accounts or pages as necessary.
  9. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  10. 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.
  11. Report all gas volumes in Dth unless the schedule specifically requires the reporting in another unit of measurement.

DEFINITIONS
  1. Btu per cubic foot – The total heating value, expressed in Btu, produced by the combustion, at constant pressure, of the amount of the gas which would occupy a volume of 1 cubic foot at a temperature of 60°F if saturated with water vapor and under a pressure equivalent to that of 30°F, and under standard gravitational force (980.665 cm. per sec) with air of the same temperature and pressure as the gas, when the products of combustion are cooled to the initial temperature of gas and air when the water formed by combustion is condensed to the liquid state (called gross heating value or total heating value).
  2. Commission Authorization -- 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.
  3. Dekatherm – A unit of heating value equivalent to 10 therms or 1,000,000 Btu.
  4. Respondent – The person, corporation, licensee, agency, authority, or other legal entity or instrumentality on whose behalf the report is made.

EXCERPTS FROM THE LAW

Natural Gas Act, 15 U.S.C. 717-717w

"Sec. 10(a). Every natural-gas company shall file with the Commission such annual and other periodic or special reports as the Commission may by rules and regulations or order prescribe as necessary or appropriate to assist the Commission in the proper administration of this act. The Commission may prescribe the manner and form in which such reports shall be made and require from such natural-gas companies specific answers to all questions upon which the Commission may need information. The Commission may require that such reports include, among other things, full information as to assets and liabilities, capitalization, investment and reduction thereof, gross receipts, interest dues and paid, depreciation, amortization, and other reserves, cost of facilities, costs of maintenance and operation of facilities for the production, transportation, delivery, use, or sale of natural gas, costs of renewal and replacement of such facilities, transportation, delivery, use and sale of natural gas..."

"Section 16. The Commission shall have power to perform all and any acts, and to prescribe, issue, make, amend, 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 form or forms of all statements declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and time within they shall be filed..."

General Penalties

The Commission may assess up to $1 million per day per violation of its rules and regulations. See NGA § 22(a), 15 U.S.C. §717t-1(a).


FERC FORM NO.
2/3-Q

REPORT OF MAJOR NATURAL GAS COMPANIES
IDENTIFICATION
01 Exact Legal Name of Respondent

Transcontinental Gas Pipe Line Company, LLC
02 Year/ Period of Report


End of:
2018
/
Q1
03 Previous Name and Date of Change (if name changed during year)

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

P.O. Box 1396 Houston, Texas 77251-1396
05 Name of Contact Person

Kathleen Hambleton
06 Title of Contact Person

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

P.O. Box 1396 Houston, Texas 77251-1396
08 Telephone of Contact Person, Including Area Code

713-215-3319
09 This Report is An Original / A Resubmission

(1)
An Original

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

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.



11 Name

Ted T. Timmermans
12 Title

Vice President and Chief Acctg Officer
13 Signature

/s/ Ted T. Timmermans
14 Date Signed

05/23/2018
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:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
List of Schedules (Natural Gas Company)
Enter in column (d) the terms "none," "not applicable," or "NA" as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the responses are "none," "not applicable," or "NA."
Line No.
Title of Schedule
(a)
Reference Page No.
(b)
Date Revised
(c)
Remarks
(d)
ScheduleIdentificationAbstract Identification 1
02-04
ScheduleListOfSchedulesAbstract List of Schedules (Natural Gas Campnay) 2
REV 12-07
GeneralCorporateInformationAndFinancialStatementsAbstract GENERAL CORPORATE INFORMATION AND FINANCIAL STATEMENTS
1
ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year 108
12-96
2
ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet
REV 06-04
ScheduleComparativeBalanceSheetAssetsAndOtherDebitsAbstract Comparative Balance Sheet (Assets And Other Debits) 110
REV 06-04
ScheduleComparativeBalanceSheetLiabilitiesOtherCreditsAbstract Comparative Balance Sheet (Liabilities and Other Credits) 112
REV 06-04
3
ScheduleStatementOfIncomeAbstract Statement of Income for the Year 114
REV 06-04
4
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accumulated Comprehensive Income and Hedging Activities 117
NEW 06-02
5
ScheduleStatementOfRetainedEarningsAbstract Statement of Retained Earnings for the Year 118
REV 06-04
6
ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows 120
REV 06-04
7
ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements 122.1
REV 12-07
BalanceSheetSupportingSchedulesAbstract BALANCE SHEET SUPPORTING SCHEDULES
8
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization, and Depletion 200
12-96
9
ScheduleGasPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Gas Plant in Service and Accumulated Provision for Depreciation by Function 210
NEW 06-04
10
ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets 232
REV 12-07
11
ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities 278
REV 12-07
AccessoryElectricEquipmentNuclearProductionAbstract INCOME ACCOUNT SUPPORTING SCHEDULES
12
ScheduleMonthlyQuantityRevenueDataByRateScheduleAbstract Monthly Quantity & Revenue Data 299
NEW 12-08
13
ScheduleNaturalGasCompanyGasRevenuesAndDekathermsAbstract Natural Gas Company- Gas Revenues and Dekatherms 309
NEW 12-97
14
ScheduleGasProductionAndOtherGasSupplyExpensesAbstract Gas Production and Other Gas Supply Expenses 310
NEW 06-04
15
ScheduleNaturalGasStorageTerminalingProcessingServicesAbstract Natural Gas Storage, Terminaling, Processing Services 311
NEW 06-04
16
ScheduleGasCustomerAccountsServiceSalesAdministrativeAndGeneralExpensesAbstract Gas Customer Accounts, Service, Sales, Administrative and General Expenses 312
NEW 06-04
17
ScheduleDepreciationDepletionAndAmortization2QAbstract Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 403.1, 404.1, 404.2, 404.3, 405) (Except Amort of Acqusition Adjustments) 339
NEW 06-04
StatisticalDataAbstract GAS PLANT STATISTICAL DATA
18
ScheduleGasAccountNaturalGasAbstract Gas Account - Natural Gas 520
REV 01-11
19
ScheduleShipperSuppliedGasForTheCurrentQuarterAbstract Shipper Supplied Gas for the Current Quarter 521
REVISED 02-11


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Important Changes During the Year
Give details concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Answer each inquiry. Enter "none" or "not applicable" where applicable. If the answer is given elsewhere in the report, refer to the schedule in which it appears.
  1. Changes in and important additions to franchise rights: Describe the actual consideration and state from whom the franchise rights were acquired. If the franchise rights were 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: Briefly describe the property, and the related transactions, and cite Commission authorization, if any was required. Give date journal entries called for by 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 conditions. 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 cite 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 or assumed by respondent as guarantor for the performance by another of any agreement or obligation, including ordinary commercial paper maturing on demand or not later than one year after date of issue: State on behalf of whom the obligation was assumed and amount of the obligation. Cite Commission authorization if any was required.
  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, 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. Estimated increase or decrease in annual revenues caused by important rate changes: State effective date and approximate amount of increase or decrease for each revenue classification. State the number of customers affected.
  12. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
  13. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

 

1. N/A

 

2. N/A

 

3. N/A

 

4. N/A

 

5. On March 23, 2018, Transco placed into service the Phase 2 facilities of the Garden State Expansion Project which created an additional 160,000 dth/day of firm transportation capacity from Transco’s Station 210 Zone 6 Pool to a new delivery point on Transco’s Trenton Woodbury Lateral in Burlington County, New Jersey. In total, the project created 180,000 dth/day of capacity for one customer, New Jersey Natural Gas Company. The service will provide approximately $24.3 million in annual reservation revenue.

 

6. N/A

 

7. N/A

 

8. During the first quarter of 2018, the annual effect of our wage scale changes resulted in a base payroll increase of approximately $3.7 million.

 

9. N/A

 

10. N/A

 

11. Effective March 23, 2018, Transco placed into service Phase 2 of the Garden State Expansion Project, an incrementally priced transportation project. This project serves one customer who will pay a negotiated reservation rate, not the recourse rate stated in the tariff. The estimated increase in annual revenues for service provided from this expansion project is provided in Item 5 of page 108.1.

12. Effective April 11, 2018, Ted T. Timmermans resigned as Controller, Kathleen R. Hambleton was elected Controller.

13. N/A



Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Comparative Balance Sheet (Assets And Other Debits)
Line No.
Title of Account
(a)
Reference Page Number
(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)
200-201
12,696,321,538
12,562,677,365
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200-201
1,672,475,547
1,240,950,317
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 2 and 3)
200-201
14,368,797,085
13,803,627,682
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Provision for Depr., Amort., Depl. (108, 111, 115)
5,439,547,226
5,377,699,428
6
UtilityPlantNet
Net Utility Plant (Total of line 4 less 5)
8,929,249,859
8,425,928,254
7
NuclearFuel
Nuclear Fuel (120.1 thru 120.4, and 120.6)
8
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Provision for Amort., of Nuclear Fuel Assemblies (120.5)
9
NuclearFuelNet
Nuclear Fuel (Total of line 7 less 8)
10
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Total of lines 6 and 9)
8,929,249,859
8,425,928,254
11
OtherGasPlantAdjustments
Utility Plant Adjustments (116)
122
12
GasStoredBaseGas
Gas Stored-Base Gas (117.1)
220
76,273,878
76,273,878
13
SystemBalancingGas
System Balancing Gas (117.2)
220
45,308,167
8,867,537
14
GasStoredInReservoirsAndPipelinesNoncurrent
Gas Stored in Reservoirs and Pipelines-Noncurrent (117.3)
220
15
GasOwedToSystemGas
Gas Owed to System Gas (117.4)
220
16
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
17
NonutilityProperty
Nonutility Property (121)
9,872,868
9,872,868
18
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Provision for Depreciation and Amortization (122)
844,313
844,313
19
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
222-223
20
InvestmentInSubsidiaryCompanies
Investments in Subsidiary Companies (123.1)
224-225
9,997,386
12,391,479
22
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
23
OtherInvestments
Other Investments (124)
222-223
24
SinkingFunds
Sinking Funds (125)
25
DepreciationFund
Depreciation Fund (126)
26
AmortizationFundFederal
Amortization Fund - Federal (127)
27
OtherSpecialFunds
Other Special Funds (128)
145,028,498
134,738,047
28
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
29
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
30
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Total of lines 17-20, 22-29)
164,054,439
156,158,081
31
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
32
Cash
Cash (131)
33
SpecialDeposits
Special Deposits (132-134)
513,623
611,174
34
WorkingFunds
Working Funds (135)
35
TemporaryCashInvestments
Temporary Cash Investments (136)
222-223
36
NotesReceivable
Notes Receivable (141)
37
CustomerAccountsReceivable
Customer Accounts Receivable (142)
159,133,935
170,071,766
38
OtherAccountsReceivable
Other Accounts Receivable (143)
3,666,791
2,048,695
39
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Provision for Uncollectible Accounts - Credit (144)
27,750
40
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
1,330,479,903
506,354,990
41
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Associated Companies (146)
3,393,330
3,269,987
42
FuelStock
Fuel Stock (151)
43
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
44
ResidualsAndExtractedProducts
Residuals (Elec) and Extracted Products (Gas) (153)
45
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
37,336,826
37,037,044
46
Merchandise
Merchandise (155)
47
OtherMaterialsAndSupplies
Other Materials and Supplies (156)
48
NuclearMaterialsHeldForSale
Nuclear Materials Held for Sale (157)
49
AllowanceInventoryAndWithheld
Allowances (158.1 and 158.2)
50
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
51
StoresExpenseUndistributed
Stores Expense Undistributed (163)
404,025
350,309
52
GasStoredCurrent
Gas Stored Underground-Current (164.1)
220
53
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2 thru 164.3)
220
696,452
790,239
54
Prepayments
Prepayments (165)
230
5,017,827
8,614,548
55
AdvancesForGas
Advances for Gas (166 thru 167)
56
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
132,973
119,155
57
RentsReceivable
Rents Receivable (172)
58
AccruedUtilityRevenues
Accrued Utility Revenues (173)
59
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
2,929,940
3,205,073
60
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
61
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
62
DerivativeInstrumentAssetsHedges
Derivative Instrument Assets - Hedges (176)
63
DerivativeInstrumentAssetsHedgesLongTerm
(Less) Long-Term Portion of Derivative Instrument Assests - Hedges (176)
64
CurrentAndAccruedAssets
TOTAL Current and Accrued Assets (Total of lines 32 thru 63)
1,543,677,875
732,472,980
65
DeferredDebitsAbstract
DEFERRED DEBITS
66
UnamortizedDebtExpense
Unamortized Debt Expense (181)
24,116,947
15,377,244
67
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230
68
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230
69
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
470,063,177
445,227,545
70
PreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Electric)(183)
71
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2)
62,649
72
ClearingAccounts
Clearing Accounts (184)
1,668,308
2,144,430
73
TemporaryFacilities
Temporary Facilities (185)
74
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
2,248,586
3,312,397
75
DeferredLossesFromDispositionOfUtilityPlant
Deferred Losses from Disposition of Utility Plant (187)
76
ResearchDevelopmentAndDemonstrationExpenditures
Research, Development, and Demonstration Expend. (188)
77
UnamortizedLossOnReacquiredDebt
Unamortized Loss on Reacquired Debt (189)
78
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234-235
427,505,810
427,562,810
79
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
80
DeferredDebits
TOTAL Deferred Debits (Total of lines 66 thru 79)
922,328,861
889,335,566
81
AssetsAndOtherDebits
TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80)
11,680,893,079
10,289,036,296


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Comparative Balance Sheet (Liabilities and Other Credits)
Line No.
Title of Account
(a)
Reference Page Number
(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)
250-251
3
PreferredStockIssued
Preferred Stock Issued (204)
250-251
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
252
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
252
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
252
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
3,117,858,116
2,777,858,116
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118-119
1,755,981,065
1,662,455,417
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118-119
(a)(b)
1,861,474
(c)(d)
163,556
13
ReacquiredCapitalStock
(Less) Reacquired Capital Stock (217)
250-251
14
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
117
554,824
251,000
15
ProprietaryCapital
TOTAL Proprietary Capital (Total of lines 2 thru 14)
4,872,532,531
4,440,400,977
16
LongTermDebtAbstract
LONG TERM DEBT
17
Bonds
Bonds (221)
256-257
207,500,000
207,500,000
18
ReacquiredBonds
(Less) Reacquired Bonds (222)
256-257
19
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256-257
20
OtherLongTermDebt
Other Long-Term Debt (224)
256-257
3,025,000,000
2,025,000,000
21
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
258-259
22
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Dr (226)
258-259
11,514,739
5,042,665
23
CurrentPortionOfLongTermDebt
(Less) Current Portion of Long-Term Debt
249,981,892
24
LongTermDebt
TOTAL Long-Term Debt (Total of lines 17 thru 23)
2,971,003,369
2,227,457,335
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases-Noncurrent (227)
247,748,985
229,359,773
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
392,907,273
363,956,090
35
OtherNoncurrentLiabilities
TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34)
640,656,258
593,315,863
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
CurrentPortionOfLongTermDebt
Current Portion of Long-Term Debt
249,981,892
38
NotesPayable
Notes Payable (231)
39
AccountsPayable
Accounts Payable (232)
414,827,407
469,156,393
40
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
41
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
17,191,738
47,150,115
42
CustomerDeposits
Customer Deposits (235)
20,154,332
15,754,164
43
TaxesAccrued
Taxes Accrued (236)
262-263
17,141,018
12,713,409
44
InterestAccrued
Interest Accrued (237)
29,974,183
49,900,406
45
DividendsDeclared
Dividends Declared (238)
46
MaturedLongTermDebt
Matured Long-Term Debt (239)
47
MaturedInterest
Matured Interest (240)
48
TaxCollectionsPayable
Tax Collections Payable (241)
49
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
268
11,249,850
10,971,581
50
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
1,603,144
1,565,538
51
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
52
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
53
DerivativeInstrumentLiabilitiesHedges
Derivative Instrument Liabilities - Hedges (245)
54
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
(Less) Long-Term Portion of Derivative Instrument Liabilities - Hedges
55
CurrentAndAccruedLiabilities
TOTAL Current and Accrued Liabilities (Total of lines 37 thru 54)
762,123,564
607,211,606
56
DeferredCreditsAbstract
DEFERRED CREDITS
57
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
74,642,196
80,271,022
58
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
94,808
100,679
59
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
60
OtherDeferredCredits
Other Deferred Credits (253)
269
16,368,771
16,647,017
61
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
970,461,415
966,684,630
62
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reacquired Debt (257)
260
63
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accumulated Deferred Income Taxes - Accelerated Amortization (281)
64
AccumulatedDeferredIncomeTaxesOtherProperty
Accumulated Deferred Income Taxes - Other Property (282)
1,292,819,664
1,276,602,664
65
AccumulatedDeferredIncomeTaxesOther
Accumulated Deferred Income Taxes - Other (283)
80,190,503
80,344,503
66
DeferredCredits
TOTAL Deferred Credits (Total of lines 57 thru 65)
2,434,577,357
2,420,650,515
67
LiabilitiesAndOtherCredits
TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66)
11,680,893,079
10,289,036,296


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 26, Column: c, Value: 0
(b) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 26, Column: c, Value: 0
(c) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 22, Column: c, Value: 0
(d) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 22, Column: c, Value: 0

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Statement of Income
Quarterly
  1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
  2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in (j) the quarter to date amounts for other utility function for the current year quarter.
  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 (k) the quarter to date amounts for other utility function for the prior year quarter.
  4. 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. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2.
  5. Use page 122 for important notes regarding the statement of income for any account thereof.
  6. 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.
  7. 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.
  8. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
  9. Enter on page 122 a concise explanation of only those changes in accounting mehods 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.
  10. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  11. 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)
Reference Page Number
(b)
Total Current Year to Date Balance for Quarter/Year
(c)
Total Prior Year to Date Balance for Quarter/Year
(d)
Current Three Months Ended Quarterly Only No Fourth Quarter
(e)
Prior Three Months Ended Quarterly Only No Fourth Quarter
(f)
Elec. Utility Current Year to Date (in dollars)
(g)
Elec. 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
Gas Operating Revenues (400)
300-301
479,053,155
415,062,808
479,053,155
415,062,808
479,053,155
415,062,808
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
317-325
183,027,709
132,773,415
183,027,709
132,773,415
183,027,709
132,773,415
5
MaintenanceExpense
Maintenance Expenses (402)
317-325
9,119,401
7,133,093
9,119,401
7,133,093
9,119,401
7,133,093
6
DepreciationExpense
Depreciation Expense (403)
336-338
76,703,813
68,125,126
76,703,813
68,125,126
76,703,813
68,125,126
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336-338
3,994,674
726,182
3,994,674
726,182
3,994,674
726,182
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336-338
1,279,607
1,221,403
1,279,607
1,221,403
1,279,607
1,221,403
9
AmortizationOfGasPlantAcquisitionAdjustments
Amortization of Utility Plant Acu. Adjustment (406)
336-338
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. of Prop. Losses, Unrecovered Plant and Reg. Study Costs (407.1)
11
AmortizationOfConversionExpenses
Amortization of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
12,050,561
16,639,862
12,050,561
16,639,862
12,050,561
16,639,862
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
44,009,057
13,606,931
44,009,057
13,606,931
44,009,057
13,606,931
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262-263
20,782,907
18,977,412
20,782,907
18,977,412
20,782,907
18,977,412
15
IncomeTaxesUtilityOperatingIncome
Income Taxes-Federal (409.1)
262-263
23,901,000
48,501,000
23,901,000
48,501,000
23,901,000
48,501,000
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes-Other (409.1)
262-263
6,353,000
7,290,000
6,353,000
7,290,000
6,353,000
7,290,000
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision of Deferred Income Taxes (410.1)
234-235
11,210,067
112,211,388
11,210,067
112,211,388
11,210,067
112,211,388
18
ProvisionForDeferredIncomeTaxesCreditUtilityOperatingIncome
(Less) Provision for Deferred Income Taxes-Credit (411.1)
234-235
983,000
983,000
983,000
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adjustment-Net (411.4)
20
GainsFromDispositionOfPlant
(Less) Gains from Disposition of Utility Plant (411.6)
191,234
251,635
191,234
251,635
191,234
251,635
21
LossesFromDispositionOfUtilityPlant
Losses from Disposition of Utility Plant (411.7)
1,379,123
98,896
1,379,123
98,896
1,379,123
98,896
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)
17,212,784
11,680,421
17,212,784
11,680,421
17,212,784
11,680,421
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Total of lines 4 thru 24)
313,842,007
298,485,268
313,842,007
298,485,268
313,842,007
298,485,268
26
NetUtilityOperatingIncome
Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to line 27)
165,211,148
116,577,540
165,211,148
116,577,540
165,211,148
116,577,540
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 Expense 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
(a)(b)
1,697,917
(c)(d)
622,862
(e)(f)
1,697,917
(g)(h)
622,862
37
InterestAndDividendIncome
Interest and Dividend Income (419)
1,865,853
1,451,819
1,865,853
1,451,819
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
19,781,659
18,365,710
19,781,659
18,365,710
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
148,441
4,286,707
148,441
4,286,707
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
41
OtherIncome
TOTAL Other Income (Total of lines 31 thru 40)
19,801,154
24,727,098
19,801,154
24,727,098
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
227,956
227,956
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
340
128,730
128,730
46
LifeInsurance
Life Insurance (426.2)
47
Penalties
Penalties (426.3)
10,000
10,000
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Expenditures for Certain Civic, Political and Related Activities (426.4)
81,933
171,904
81,933
171,904
49
OtherDeductions
Other Deductions (426.5)
139,354
384,130
139,354
384,130
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
340
221,287
922,720
221,287
922,720
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262-263
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262-263
76,000
21,000
76,000
21,000
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262-263
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Income Taxes (410.2)
234-235
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Credit (411.2)
234-235
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adjustments-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
5,871
5,871
5,871
5,871
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
81,871
15,129
81,871
15,129
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
19,661,738
23,789,249
19,661,738
23,789,249
61
InterestChargesAbstract
INTEREST CHARGES
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
38,614,278
36,676,500
38,614,278
36,676,500
63
AmortizationOfDebtDiscountAndExpense
Amortization of Debt Disc. and Expense (428)
258-259
373,032
327,484
373,032
327,484
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reacquired Debt (428.1)
40,595
40,595
65
AmortizationOfPremiumOnDebtCredit
(Less) Amortization of Premium on Debt-Credit (429)
258-259
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reacquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Associated Companies (430)
340
14,899
14,899
14,899
14,899
68
OtherInterestExpense
Other Interest Expense (431)
340
6,058,264
161,953
6,058,264
161,953
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Credit (432)
6,826,318
4,664,383
6,826,318
4,664,383
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
38,234,155
32,557,048
38,234,155
32,557,048
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
146,638,731
107,809,741
146,638,731
107,809,741
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)
262-263
77
ExtraordinaryItemsAfterTaxes
Extraordinary Items after Taxes (line 75 less line 76)
78
NetIncomeLoss
Net Income (Total of line 71 and 77)
146,638,731
107,809,741
146,638,731
107,809,741


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: c, Value: 0
(b) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: c, Value: 0
(c) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: d, Value: 0
(d) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: d, Value: 0
(e) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: c, Value: 0
(f) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: c, Value: 0
(g) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: d, Value: 0
(h) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: d, Value: 0

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Statement of Accumulated Comprehensive Income and Hedging Activities
  1. Report in columns (b) (c) 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.
Line No.
Item
(a)
Unrealized Gains and Losses on available-for-sale securities
(b)
Minimum Pension liabililty Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest Rate Swaps
(f)
Other Cash Flow Hedges [Insert Footnote at Line 1 to specify]
(g)
Totals for each category of items recorded in Account 219
(h)
Net Income (Carried Forward from Page 114, Line 78)
(i)
Total Comprehensive Income
(j)
1
Balance of Account 219 at Beginning of Preceding Year
5,421
5,421
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
9,694
9,694
3
Preceding Quarter/Year to Date Changes in Fair Value
13,071
13,071
4
Total (lines 2 and 3)
22,765
22,765
107,809,741
107,832,506
5
Balance of Account 219 at End of Preceding Quarter/Year
(a)
28,186
28,186
6
Balance of Account 219 at Beginning of Current Year
251,000
251,000
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
4,343
4,343
8
Current Quarter/Year to Date Changes in Fair Value
299,481
299,481
9
Total (lines 7 and 8)
303,824
303,824
146,638,731
146,942,555
10
Balance of Account 219 at End of Current Quarter/Year
(b)
554,824
554,824


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsBalance

 

EQUITY INTEREST IN UNDERLYING OTHER COMPREHENSIVE INCOME OF SUBSIDIARIES.

(b) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsBalance

 

EQUITY INTEREST IN UNDERLYING OTHER COMPREHESIVE INCOME OF SUBSIDIARIES.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:


End of:
2018
/
Q1
Statement of Retained Earnings
  1. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  2. 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).
  3. State the purpose and amount for each reservation or appropriation of retained earnings.
  4. 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.
  5. Show dividends for each class and series of capital stock.
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
1
UnappropriatedRetainedEarnings
Balance-Beginning of Period
1,662,455,417
1,715,884,381
2
ChangesAbstract
Changes (Identify by prescribed retained earnings accounts)
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
3.1
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Account 439) (footnote details)
3.2
AdjustmentsToRetainedEarningsCredit
TOTAL Debits to Retained Earnings (Account 439) (footnote details)
3.3
AdjustmentsToRetainedEarningsCredit
Balance Transferred from Income (Acct 433 less Acct 418.1)
148,336,648
107,186,879
4
AdjustmentsToRetainedEarningsCredit
Adjustments to Retained Earnings Credit (Debit)
7
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Account 436)
7.1
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Account 436) (footnote details)
8
AppropriationsOfRetainedEarnings
Appropriations of Retained Earnings Amount
9
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
9.1
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Account 437) (footnote details)
10
DividendsDeclaredPreferredStock
Dividends Declared-Preferred Stock Amount
11
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
11.1
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Account 438) (footnote details)
(a)
54,811,000
(h)
99,410,563
12
DividendsDeclaredCommonStock
Dividends Declared-Common Stock Amount
13
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Account 216.1, Unappropriated Undistributed Subsidiary Earnings
14
UnappropriatedRetainedEarnings
Balance-End of Period (Total of lines 1, 4, 5, 6, 8, 10, 12, and 13)
1,755,981,065
1,723,660,697
15
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
16
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215) (footnote details)
17
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROPRIATED RETAINED EARNINGS-AMORTIZATION RESERVE, FEDERAL (Account 215.1)
18
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Appropriated Retained Earnings-Amortization Reserve, Federal (Account 215.1)
19
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Appropriated Retained Earnings (Accounts 215, 215.1) (Total of lines of 16 and 18)
20
RetainedEarnings
TOTAL Retained Earnings (Accounts 215, 215.1, 216) (Total of lines 14 and 19)
1,755,981,065
1,723,660,697
21
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.1)
ReportOnlyOnAnAnnualBasisNoQuarterlyAbstract
Report only on an Annual Basis no Quarterly
22
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
(b)(c)
163,556
23
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
(d)(e)
1,697,917
(i)(j)
622,862
24
DividendsReceived
(Less) Dividends Received (Debit)
25
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
25.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
26
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year
(f)(g)
1,861,474


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:


End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: DividendsDeclaredCommonStock

 

CASH DISTRIBUTION

$

55,000,000

SUBSIDIARY INCOME TAX DISTRIBUTION

 

(189,000)

TOTAL DISTRIBUTION FROM RETAINED EARNINGS

$

54,811,000

(b) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 22, Column: c, Value: 0
(c) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 22, Column: c, Value: 0
(d) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: c, Value: 0
(e) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: c, Value: 0
(f) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 26, Column: c, Value: 0
(g) Concept: UnappropriatedUndistributedSubsidiaryEarnings
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 26, Column: c, Value: 0
(h) Concept: DividendsDeclaredCommonStock

 

CASH DISTRIBUTION

$

100,000,000

SUBSIDIARY INCOME TAX DISTRIBUTION

 

(589,437)

TOTAL DISTRIBUTION FROM RETAINED EARNINGS

$

99,410,563

(i) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings, Row: 23, Column: d, Value: 0
(j) Concept: EquityInEarningsOfSubsidiaryCompanies
Duplicate fact discrepancy. Schedule: 118 - Schedule - Retained Earnings - Adjustments to Retained Earnings, Row: 23, Column: d, Value: 0

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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 25) 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 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 114)
146,638,731
107,809,741
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
73,988,746
68,620,347
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of (Specify) (footnote details)
(a)
373,032
(o)
368,079
6
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
10,227,067
112,211,388
7
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustments (Net)
8
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(b)
9,210,324
(p)
8,551,140
9
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(c)
36,700,340
(q)
15,366,437
10
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
11
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
98,010,489
35,386,751
12
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
18,942,700
(r)
629,691
13
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
3,776,785
5,461,254
14
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
19,781,659
18,365,710
15
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
1,697,917
622,862
16
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other Adjustments to Cash Flows from Operating Activities
16.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (footnote details):
(e)
27,741,938
(s)
27,170,617
18
NetCashProvidedByUsedInOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 16)
100,219,352
205,479,881
20
CashFlowsFromInvestmentActivitiesAbstract
Cash Flows from Investment Activities:
21
ConstructionAndAcquisitionOfPlantIncludingLandAbstract
Construction and Acquisition of Plant (including land):
22
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Gross Additions to Utility Plant (less nuclear fuel)
(f)
560,888,234
(t)
344,013,295
23
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
24
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
25
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
26
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(g)
19,781,659
(u)
18,365,710
27
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other Construction and Acquisition of Plant, Investment Activities
27.1
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Other (footnote details):
28
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 22 thru 27)
(h)
541,106,575
(v)
325,647,585
30
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
31
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
33
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Associated and Subsidiary Companies
(i)
1,824,402,228
(w)
608,058,930
34
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Associated and Subsidiary Companies
36
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
(j)
1,001,277,315
(x)
645,521,634
38
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
(k)
11,738,454
(y)
12,240,745
39
ProceedsFromSalesOfInvestmentSecurities
Proceeds from Sales of Investment Securities (a)
40
LoansMadeOrPurchased
Loan Made or Purchased
41
CollectionsOnLoans
Collections on Loans
43
NetIncreaseDecreaseInReceivablesInvestingActivities
Net (Increase) Decrease in Receivables
44
NetIncreaseDecreaseInInventoryInvestingActivities
Net (Increase) Decrease in Inventory
45
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities
Net (Increase) Decrease in Allowances Held for Speculation
46
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
20,098,493
69,815,250
47
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other Adjustments to Cash Flows from Investment Activities:
47.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Other (footnote details):
(l)
7,440,512
(z)
14,554,465
49
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 28 thru 47)
1,388,627,923
216,055,911
51
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
52
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
53
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Proceeds from Issuance of Long-Term Debt (b)
993,440,000
54
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Proceeds from Issuance of Preferred Stock
55
ProceedsFromIssuanceOfCommonStockFinancingActivities
Proceeds from Issuance of Common Stock
56
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Net Increase in Debt (Long Term Advances)
56.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (footnote details):
(m)
349,779,571
(aa)
109,987,006
56.2
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (footnote details):
57
NetIncreaseInShortTermDebt
Net Increase in Short-term Debt (c)
59
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total of lines 53 thru 58)
1,343,219,571
109,987,006
61
PaymentsForRetirementAbstract
Payments for Retirement
62
PaymentsForRetirementOfLongTermDebtFinancingActivities
Payments for Retirement of Long-Term Debt (b)
63
PaymentsForRetirementOfPreferredStockFinancingActivities
Payments for Retirement of Preferred Stock
64
PaymentsForRetirementOfCommonStockFinancingActivities
Payments for Retirement of Common Stock
65
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other Retirements
65.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other (footnote details):
66
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
67
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other Adjustments to Financing Cash Flows
68
DividendsOnPreferredStock
Dividends on Preferred Stock
69
DividendsOnCommonStock
Dividends on Common Stock
(n)
54,811,000
(ab)
99,410,563
70
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 59 thru 69)
1,288,408,571
10,576,443
73
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
74
NetIncreaseDecreaseInCashAndCashEquivalents
(Total of line 18, 49 and 71)
413
76
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
78
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
413


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:


End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

 

 

DEBT DISCOUNT AND EXPENSE

$

285,106

UNAMORTIZED PREM/DISC ON LONG-TERM DEBT

 

87,926

 

$

373,032

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 9210324
(c) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -36700340
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -18942700
(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

ASSET RETIREMENT OBLIGATION REMOVAL COSTS

$

(1,199,316)

NET TRANSPORTATION AND EXCHANGE RECEIVABLE IMBALANCE

 

226,406

ACCRUED INSURANCE

 

(1,259)

SPECIAL DEPOSITS

 

97,551

CUSTOMER DEPOSITS

 

4,400,168

DEFERRED REGULATORY COMMISSION EXPENSE

 

1,093,956

PREPAYMENTS

 

3,596,721

PREPAID FIRM TRANSPORTATION

 

(238,140)

SUSPENSE PROJECTS

 

(523,734)

CLEARING

 

(476,122)

ASSET RETIREMENT OBLIGATION

 

18,400,674

LGA/LGS STORAGE PRICE DIFFERENTIAL

 

326,995

ACCRUED ENVIRONMENTAL COSTS

 

(59,154)

(GAIN) LOSS ON INVESTMENTS

 

1,423,503

OTHER, NET

 

673,689

 

$

27,741,938

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -560888234
(g) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -19781659
(h) Concept: CashOutflowsForPlant
Original value: -541106575
(i) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -1824402228
(j) Concept: DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies

 

REPAYMENT OF NOTE ADVANCES

$

1,000,277,315

RETURN OF INVESTMENT IN SUBSIDIARIES

 

1,000,000

 

$

1,001,277,315

(k) Concept: PurchaseOfInvestmentSecurities
Original value: -11738454
(l) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

NET RETIREMENTS

$

(5,241,571)

CONTRIBUTIONS AND ADVANCES FOR CONSTRUCTION COSTS

 

12,744,732

OTHER, NET

 

(62,649)

 

$

7,440,512

(m) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

 

CAPITAL CONTRIBUTION FROM WILLIAMS PARTNERS OPERATING, LLC (WPO)

$

340,000,000

DEBT ISSUE COSTS

 

(9,024,808)

PROCEEDS FROM LEASE OBLIGATION

 

18,804,379

 

$

349,779,571

(n) Concept: DividendsOnCommonStock
Original value: -54811000
(o) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

 

DEBT DISCOUNT AND EXPENSE

$

327,484

 

LOSS ON REACQUIRED DEBT

 

40,595

 

 

$

368,079

(p) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 8551140
(q) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -15366437
(r) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -629691
(s) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

ASSET RETIREMENT OBLIGATION REMOVAL COSTS

$

(222,243)

NET TRANSPORTATION AND EXCHANGE RECEIVABLE IMBALANCE

 

(5,898,184)

ACCRUED INSURANCE

 

(40,083)

SPECIAL DEPOSITS

 

91,710

CUSTOMER DEPOSITS

 

(32,369,870)

DEFERRED REGULATORY COMMISSION EXPENSE

 

1,063,677

PREPAYMENTS

 

5,098,078

PREPAID FIRM TRANSPORTATION

 

(238,140)

SUSPENSE PROJECTS

 

(742,411)

CLEARING

 

(849,508)

ASSET RETIREMENT OBLIGATION

 

11,527,682

LGA/LGS STORAGE PRICE DIFFERENTIAL

 

(1,230,722)

ACCRUED ENVIRONMENTAL COSTS

 

(70,407)

(GAIN) LOSS ON INVESTMENTS

 

(3,629,528)

POTENTIAL ASSESSMENTS

 

10,000

OTHER, NET

 

329,332

 

$

(27,170,617)

(t) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -344013295
(u) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -18365710
(v) Concept: CashOutflowsForPlant
Original value: -325647585
(w) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -608058930
(x) Concept: DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies

 

REPAYMENT OF NOTE ADVANCES

$

644,021,634

RETURN OF INVESTMENT IN SUBSIDIARIES

 

1,500,000

 

$

645,521,634

(y) Concept: PurchaseOfInvestmentSecurities
Original value: -12240745
(z) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

NET RETIREMENTS

$

(2,131,436)

CONTRIBUTIONS AND ADVANCES FOR CONSTRUCTION COSTS

 

13,485,902

INSURANCE PROCEEDS

 

3,200,000

OTHER, NET

 

(1)

 

$

14,554,465

(aa) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

CAPITAL CONTRIBUTION FROM WPO

$

110,000,000

DEBT ISSUE COSTS

 

(12,994)

 

$

109,987,006

(ab) Concept: DividendsOnCommonStock
Original value: -99410563

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Notes to Financial Statements
  1. Provide important disclosures regarding the Balance Sheet, Statement of Income for the Year, Statement of Retained Earnings for the Year, and Statement of Cash Flow, or any account thereof. Classify the disclosures according to each financial statement, providing a subheading for each statement except where a disclosure is applicable to more than one statement. The disclosures must be on the same subject matters and in the same level of detail that would be required if the respondent issued general purpose financial statements to the public or shareholders.
  2. Furnish details as to any significant contingent assets or liabilities existing at year end, and briefly explain any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or a claim for refund of income taxes of a material amount initiated by the utility. Also, briefly explain any dividends in arrears on cumulative preferred stock.
  3. Furnish details on the respondent's pension plans, post-retirement benefits other than pensions (PBOP) plans, and post-employment benefit plans as required by instruction no. 1 and, in addition, disclose for each individual plan the current year's cash contributions. Furnish details on the accounting for the plans and any changes in the method of accounting for them. Include details on the accounting for transition obligations or assets, gains or losses, the amounts deferred and the expected recovery periods. Also, disclose any current year's plan or trust curtailments, terminations, transfers, or reversions of assets. Entities that participate in multiemployer postretirement benefit plans (e.g. parent company sponsored pension plans) disclose in addition to the required disclosures for the consolidated plan, (1) the amount of cost recognized in the respondent’s financial statements for each plan for the period presented, and (2) the basis for determining the respondent’s share of the total plan costs.
  4. Furnish details on the respondent’s asset retirement obligations (ARO) as required by instruction no. 1 and, in addition, disclose the amounts recovered through rates to settle such obligations. Identify any mechanism or account in which recovered funds are being placed (i.e. trust funds, insurance policies, surety bonds). Furnish details on the accounting for the asset retirement obligations and any changes in the measurement or method of accounting for the obligations. Include details on the accounting for settlement of the obligations and any gains or losses expected or incurred on the settlement.
  5. Provide a list of all environmental credits received during the reporting period.
  6. Provide a summary of revenues and expenses for each tracked cost and special surcharge.
  7. Where Account 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 item. See General Instruction 17 of the Uniform System of Accounts.
  8. Explain concisely any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  9. Disclose details on any significant financial changes during the reporting year to the respondent or the respondent's consolidated group that directly affect the respondent's gas pipeline operations, including: sales, transfers or mergers of affiliates, investments in new partnerships, sales of gas pipeline facilities or the sale of ownership interests in the gas pipeline to limited partnerships, investments in related industries (i.e., production, gathering), major pipeline investments, acquisitions by the parent corporation(s), and distributions of capital.
  10. Explain concisely unsettled rate proceedings where a contingency exists such that the company may need to refund a material amount to the utility's customers or that the utility may receive a material refund with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency relates and the tax effects and explain the major factors that affect the rights of the utility to retain such revenues or to recover amounts paid with respect to power and gas purchases.
  11. Explain concisely significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and summarize the adjustments made to balance sheet, income, and expense accounts.
  12. Explain concisely only those significant 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 approximate dollar effect of such changes.
  13. 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.
  14. 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.
  15. 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.

 

1. BASIS OF PRESENTATION

In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we,” “us” or “our.”

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At March 31, 2018, Williams owns a 74 percent limited partner interest in WPZ.

On May 17, 2018, Williams and WPZ announced an agreement under which Williams will acquire all of the outstanding public common units of WPZ. The merger is expected to close in the fall of 2018, subject to standard closing conditions, including the requisite approval of Williams' shareholders. Following consummation of the merger, WPZ will become a wholly owned subsidiary of Williams, and Transco will be wholly owned by Williams.

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of their investment.

These financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than generally accepted accounting principles (GAAP). As a result, the following disclosure may not be consistent with the disclosure in our 2017 annual report on Form 10-K and our 2018 quarterly report on Form 10-Q.

The most significant difference between GAAP and the financial statements presented herein are: (i) the deferral of certain costs and revenues, (ii) the classification of certain accounts in our financial statements, (iii) subsidiaries are reflected on the equity method whereas GAAP requires that all controlled subsidiaries be consolidated, (iv) the inclusion and classification of income taxes in a partnership’s or limited liability company’s financial statements, (v) the classification of assets held for sale as plant in service in our balance sheet, (vi) purchase price allocations related to the acquisition of Transco by Williams in 1995.

The acquisition of Transco by Williams was accounted for using the purchase method of accounting and an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. However, our purchase price allocation assigned to property, plant and equipment and the related adjustments to deferred taxes and amortization are not reflected in the FERC financial statements included herein. These financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2017 FERC Form No. 2

The preparation of financial statements in conformity with the FERC regulatory basis of accounting requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) deferred and other income taxes.

Accounting Standards Issued and Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our financial statements from those under the previous revenue standard (See Note 2).

Accounting Standards Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01) Per ASU 2018-01, land easements and right-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease and permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases”. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.

In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted Improvements”, which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. We expect to adopt ASU 2016-02 effective January 1, 2019.

We are in the process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Balance Sheet for operating leases. We are also evaluating ASU 2016-02's currently available and proposed practical expedients on adoption.

 

2. REVENUE RECOGNITION

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying ASC 980 "Regulated Operations" (Topic 980), we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

  • Guaranteed transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

    • Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer.

In situations where we consider the integrated package of services a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services and represents a single performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to transfer these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Product Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances.

Revenue by Category

Our revenue disaggregation by major service line includes natural gas sales, natural gas transportation, natural gas storage, and other, which are included in gas operating revenues on the Statement of Income.

 

Contract Liabilities

Our contract liability consists of an advance payment from a customer for which future service is to be provided under the contract. This amount has been deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and is classified as current or non-current according to when such amounts are expected to be recognized.

The following table presents a reconciliation of the beginning and ending balance of our contract liability for the three months ended March 31, 2018:

 

2018

 

(Thousands)

Balance at January 1

$

11,838

 

Payments received and deferred

 

Recognized in revenue

(238

)

Balance at March 31

$

11,600

 

The following table presents the amount of the contract liability balance as of March 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:

 

(Thousands)

2018 (remainder)

$

728

 

2019

966

 

2020

968

 

2021

966

 

2022

966

 

2023

966

 

Thereafter

6,040

 

 

 

 

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges and consideration received prior to March 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of March 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

 

 

(Thousands)

2018 (remainder)

$

1,284,187

 

2019

1,576,306

 

2020

1,482,893

 

2021

1,205,683

 

2022

1,095,132

 

2023

961,398

 

Thereafter

8,308,794

 

Total

$

15,914,393

 

Accounts Receivable

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers' financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Receivables from contracts with customers are included within customer accounts receivable, other accounts receivable and accounts receivable from associated companies and receivables that are not related to contracts with customers are included with notes receivable from associated companies in our Balance Sheet.

3. RATE AND REGULATORY MATTERS

On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

4. CONTINGENT LIABILITIES

Station 62 Incident

On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.

In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV.

The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.

We are a defendant in lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At March 31, 2018, we had a balance of approximately $3.9 million for the expense portion of these estimated costs, $1.8 million recorded in miscellaneous current and accrued liabilities and $2.1 million recorded in other deferred credits in the accompanying Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in miscellaneous accrued liabilities and $2.2 million recorded in other deferred credits in the accompanying Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to net utility plant in the Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Balance Sheet until collected through rates. At March 31, 2018, we had a balance of approximately $1.9 million of uncollected environmental related regulatory assets, recorded in other regulatory assets in the accompanying Balance Sheet. At December 31, 2017, we had a balance of approximately $2.2 million of uncollected environmental related regulatory assets, recorded in other regulatory assets in the accompanying Balance Sheet.

For the quarter ended March 31, 2018, we purchased the following credits for the Meadows Reliability Enhancement Project: 3.99 credits from Marsh Resources Mitigation Bank for $933,332 and Riparian credits for $478,500.

For the quarter ended March 31, 2017, we did not earn, develop, or purchase environmental credits.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

5. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC, are party to a credit agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to WPZ under this credit facility is $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At March 31, 2018, no letters of credit have been issued and no loans were outstanding under the credit facility.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At March 31, 2018, WPZ had no commercial paper outstanding under the commercial paper program.

Long-Term Debt Due Within One Year

The long-term debt due within one year at March 31, 2018 is associated with the $250 million of 6.05 percent notes maturing on June 15, 2018.

Issuance of Long-Term Debt

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private placement. We intend to use the net proceeds to retire our $250 million of 6.05 percent senior unsecured notes due June 2018, and for general purposes, including the funding of capital expenditures. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. We are obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

6. ARO TRUST

Available-for-Sale Investments

We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.

Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):

 

March 31, 2018

 

December 31, 2017

 

Amortized

Cost Basis

 

Fair

Value

 

Amortized

Cost Basis

 

Fair

Value

Cash and Money Market Funds

$

24.3

 

 

$

24.3

 

 

$

12.6

 

 

$

12.6

 

U.S. Equity Funds

35.9

 

 

50.0

 

 

35.9

 

 

50.5

 

International Equity Funds

20.7

 

 

24.4

 

 

20.7

 

 

24.6

 

Municipal Bond Funds

46.8

 

 

46.3

 

 

46.8

 

 

46.9

 

Total

$

127.7

 

 

$

145.0

 

 

$

116.0

 

 

$

134.6

 

7. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

 

 

 

 

 

 

Fair Value Measurements Using

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

Prices In

 

 

 

 

 

 

 

 

 

 

Active

 

Significant

 

 

 

 

 

 

 

 

Market for

 

Other

 

Significant

 

 

 

 

 

 

Identical

 

Observable

 

Unobservable

 

 

Carrying

 

Fair

 

Assets

 

Inputs

 

Inputs

 

 

Amount

 

Value

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

 

 

 

(Millions)

 

 

 

 

Assets (liabilities) at March 31, 2018:

 

 

 

 

 

 

 

 

 

 

Measured on a recurring basis:

 

 

 

 

 

 

 

 

 

 

ARO Trust investments

$

145.0

$

145.0

$

145.0

$

-

$

-

 

 

 

 

 

 

 

 

 

 

 

Additional disclosures:

 

 

 

 

 

 

 

 

 

 

Long-term debt - including current portion

 

 

(3,221.0)

 

 

(3,483.1)

 

 

-

 

 

(3,483.1)

 

 

-

 

 

 

 

 

 

 

 

 

 

 

Assets (liabilities) at December 31, 2017:

 

 

 

 

 

 

 

 

 

 

Measured on a recurring basis:

 

 

 

 

 

 

 

 

 

 

ARO Trust investments

$

134.6

$

134.6

$

134.6

$

-

$

-

 

 

 

 

 

 

 

 

 

 

 

Additional disclosures:

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

(2,227.5)

 

(2,653.2)

 

-

 

(2,653.2)

 

-

 

 

 

 

 

 

 

 

 

 

 

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in other special funds in the Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 for more information regarding the ARO Trust.

Long-term debt — The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the three months ended March 31, 2018 or 2017.

8. TRANSACTIONS WITH AFFILIATES

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At March 31, 2018 and December 31, 2017, our advances to WPZ totaled approximately $1,330.5 million and $506.4 million, respectively. These advances are represented by demand notes and are classified as notes receivable from associated companies in the accompanying Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At March 31, 2018, the interest rate was 1.54 percent.

In January 2018, our subsidiary, TransCardinal made a distribution to us of $1.0 million. In April 2018, our subsidiaries, TransCarolina and TransCardinal made an additional distribution of $0.1 million and $0.9 million, respectively.

In January 2017, our subsidiaries, TransCarolina and TransCardinal made distributions to us of $0.5 million and $1.0 million, respectively. In April 2017, TransCarolina and TransCardinal made an additional distribution of $0.5 million and $1.5 million, respectively.

Included in gas operating revenues in the accompanying Statement of Income are revenues received from affiliates of $1.8 million and $3.3 million for the three months ended March 31, 2018 and 2017, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in operation expenses in the accompanying Statement of Income are cost of gas purchased from affiliates of $1.9 million and $1.1 million for the three months ended March 31, 2018 and 2017, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $91.5 million and $82.4 million in the three months ended March 31, 2018 and 2017, respectively, for these services. Such expenses are primarily included in operation and maintenance expenses in the accompanying Statement of Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.0 million and $0.9 million for the three months ended March 31, 2018 and 2017, respectively.

We made equity distributions totaling $54.8 million and $99.4 million during the three months ended March 31, 2018 and 2017, respectively. During April 2018, we made an additional distribution of $134.8 million.

Our parent made contributions to us totaling $340.0 million and $110.0 million in the three months ended March 31, 2018 and 2017, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

9. OTHER

In 2017, we recorded a capital lease obligation associated with the Dalton lateral. At March 31, 2018, we had liabilities of $247.7 million in Obligations Under Capital Leases-Noncurrent and $1.6 million in Obligations Under Capital Leases-Current and an asset of $249.3 million in Utility Plant.

 

10. STATEMENT OF CASH FLOW

 

 

3/31/2018

 

3/31/2017

Account 131 Cash

$ -

 

$ 413

Account 135 Working Funds

-

 

-

Cash and Equivalent at End of Year

$ -

 

$ 413

 

For the three months ended March 31, 2018 and 2017, we paid $57.8 million and $53.9 million, respectively, for interest (net of amount capitalized).

 

For the three months ended March 31, 2018 and 2017, we paid income taxes of $0.2 million and $0.6 million, respectively.

 



Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion
Line No.
Item
(a)
Total Company For the Current Quarter/Year
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Common
(f)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlantInServiceAbstract
In Service
3
UtilityPlantInServiceClassified
Plant in Service (Classified)
9,116,856,258
9,116,856,258
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
249,352,129
249,352,129
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
3,330,113,151
3,330,113,151
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
TOTAL Utility Plant (Total of lines 3 thru 7)
12,696,321,538
12,696,321,538
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
11
ConstructionWorkInProgress
Construction Work in Progress
1,672,475,547
1,672,475,547
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
13
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 8 thru 12)
14,368,797,085
14,368,797,085
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
5,439,547,226
5,439,547,226
15
UtilityPlantNet
Net Utility Plant (Total of lines 13 and 14)
8,929,249,859
8,929,249,859
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
5,337,184,521
5,337,184,521
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
102,362,705
102,362,705
22
DepreciationAmortizationAndDepletionUtilityPlantInService
TOTAL In Service (Total of lines 18 thru 21)
5,439,547,226
5,439,547,226
23
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract
Leased to Others
24
DepreciationUtilityPlantLeasedToOthers
Depreciation
25
AmortizationAndDepletionUtilityPlantLeasedToOthers
Amortization and Depletion
26
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers
TOTAL Leased to Others (Total of lines 24 and 25)
27
DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract
Held for Future Use
28
DepreciationUtilityPlantHeldForFutureUse
Depreciation
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
TOTAL Held for Future Use (Total of lines 28 and 29)
31
AbandonmentOfLeases
Abandonment of Leases (Natural Gas)
32
AmortizationOfPlantAcquisitionAdjustment
Amortization of Plant Acquisition Adjustment
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
TOTAL Accum. Provisions (Should agree with line 14 above)(Total of lines 22, 26, 30, 31, and 32)
5,439,547,226
5,439,547,226


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Gas Plant in Service and Accumulated Provision for Depreciation by Function
  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
54,630,957
25,214,416
2
Productions-Manufactured Gas
3
Production and Gathering-Natural Gas
155,585,995
119,618,671
4
Products Extraction-Natural Gas
5
Underground Gas Storage
371,593,920
158,348,913
6
Other Storage Plant
73,346,774
50,201,409
7
Base Load LNG Terminaling and Processing Plant
8
Transmission
11,565,459,100
4,714,485,955
9
Distribution
10
General
475,704,792
371,677,862
11
TOTAL (total of lines 1 thru 10)
12,696,321,538
5,439,547,226


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Other Regulatory Assets (Account 182.3)
  1. Report below the details called for concerning other regulatory assets which are created through the ratemaking actions of regulatory agencies (and not includable in other accounts).
  2. For regulatory assets being amortized, show period of amortization in column (b).
  3. Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $250,000, whichever is less) may be grouped by classes.
  4. Report separately any "Deferred Regulatory Commission Expenses" that are also reported on pages 350-351, Regulatory Commission Expenses.
  5. Provide in column (c), for each line item, the regulatory citation where authorization for the regulatory asset has been granted (e.g. Commission Order, state commission order, court decision).
Line No.
DescriptionAndPurposeOfOtherRegulatoryAssets
Description and Purpose of Other Regulatory Assets
(a)
AmortizationPeriodOtherRegulatoryAssets
Amortization Period
(b)
CitationAuthorizationForOtherRegulatoryAssets
Regulatory Citation
(c)
OtherRegulatoryAssets
Balance at Beginning Current Quarter/Year
(d)
IncreaseDecreaseInOtherRegulatoryAssets
Debits
(e)
OtherRegulatoryAssetsWrittenOffAccountCharged
Written off During Quarter/Year Account Charged
(f)
OtherRegulatoryAssetsWrittenOffRecovered
Written off During Period Amount Recovered
(g)
OtherRegulatoryAssetsWrittenOffDeemedUnrecoverable
Written off During Period Amount Deemed Unrecoverable
(h)
OtherRegulatoryAssets
Balance at End of Current Quarter/Year
(i)
1
Environmental Costs
2
(a)
(Amortized through 01/31/2019)
2,238,377
298,632
1,939,745
3
(b)
Cash-Out Deferral
42,507,288
557,815
43,065,103
4
Fuel Tracker - Transportation, Storage Deferral,
5
(c)
and Carrying Costs
59,550,254
11,025,647
3,055,266
67,520,635
6
(d)
LNG Fuel Tracker and Carrying Costs
1,854,699
211,993
2,066,692
7
Deferred Tax Liability Related to AFUDC
8
(e)
(03/01/2013 - 07/15/2050)
111,178,310
6,576,315
413,937
117,340,688
9
Deferred Tax Liability Related to an Increase
10
in the Effective Tax Rate Including Current
11
(f)
(03/01/2007 - 06/30/2021)
3,757,906
269,445
3,488,461
12
Eminence Abandonment Costs
13
(g)
(03/01/2013 - 03/01/2028)
49,465,532
1,091,841
48,373,691
14
(h)
Asset Retirement Obligation - Tracker
167,479,015
57,846,151
49,782,922
175,542,244
15
Asset Retirement Obligation - ARO Trust
16
(i)
Withdrawal Deferral
1,196,164
3,946
1,192,218
17
(j)
Deferred Gas Costs
6,000,000
11,217,578
7,683,878
9,533,700
40
TOTAL
445,227,545
87,435,499
62,599,867
470,063,177


FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

DOCKET NO. RP12-993

AMORTIZATION PERIOD THROUGH JANUARY 2019

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 15

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF SECTION 38.5

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FER GAS TARIFF SECTION 38.5

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC ACCOUNTING GUIDANCE AI93-5-000, ACCOUNTING FOR INCOME TAXES

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

SOUTH GEORGIA NATURAL GAS CO., FERC DOCKET RP77-32 (1978)

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

DOCKET NO. RP12-993

AMORTIZATION PERIOD OF 15 YEARS, THROUGH MARCH 1, 2028

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

RP12-993 RATE CASE SETTLEMENT, REGULATORY ASSET FOR ARO RETIREMENT EXPENDITURES IN EXCESS OF SETTLED CAP FOR EACH INDIVIDUAL ARO

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

RP12-993 RATE CASE SETTLEMENT, DISBURSEMENTS FROM THE TRUST WILL BE LIMITED BASED ON ESTABLISHED CRITERIA IN SETTLEMENT, ANY SPENDING IN EXCESS OF ESTABLISHED AMOUNTS ARE DEFERRED

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 15


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Other Regulatory Liabilities (Account 254)
  1. Report below the details called for concerning other regulatory liabilities which are created through the ratemaking actions of regulatory agencies (and not includable in other amounts).
  2. For regulatory liabilities being amortized, show period of amortization in column (a).
  3. Minor items (5% of the Balance at End of Year for Account 254 or amounts less than $250,000, whichever is less) may be grouped by classes.
  4. Provide in a footnote, for each line item, the regulatory citation where the respondent was directed to refund the regulatory liability (e.g. Commission Order, state commission order, court decision).
Line No.
DescriptionAndPurposeOfOtherRegulatoryLiabilities
Description and Purpose of Other Regulatory Liabilities
(a)
OtherRegulatoryLiabilities
Balance at Beginning of Current Quarter/Year
(b)
OtherRegulatoryLiabilityAccountOffsettingCredits
Written off during Quarter/Period Account Credited
(c)
OtherRegulatoryLiabilityWrittenOffRefunded
Written off During Period Amount Refunded
(d)
OtherRegulatoryLiabilityWrittenOffDeemedNonRefundable
Written off During Period Amount Deemed Non-Refundable
(e)
OtherRegulatoryLiabilityAdditions
Credits
(f)
OtherRegulatoryLiabilities
Balance at End of Current Quarter/Year
(g)
1
Deferred Collections - Post Retirement
2
(a)
Benefits Other Than Pensions
65,431,312
2,111,077
67,542,389
3
Unamortized Payable - Post Retirement
4
Benefits Other Than Pensions
5
(b)
(03/2013 - 05/2020)
8,505,383
635,576
7,869,807
6
Sentinel Meter Station Depreciation
7
Expense
8
(c)
(07/2014 - 10/2063)
6,295,570
25,592
62,761
6,332,739
9
(d)
Overrun Penalty Revenue Sharing
347,033
185,852
161,181
10
(e)
Operational Flow Order Penalty Deferral
43,450
43,450
11
(f)
Unauthorized Takes
76,127
50,636
25,491
12
Electric Power Trackers and Carrying
13
(g)
Costs
13,282,244
3,485,385
1,766,858
11,563,717
14
Collections in Excess of Pension
15
(h)
Funding Obligation
32,518,947
4,007,272
36,526,219
16
(i)
Deferred Gas Cost
168,408
1,939,707
2,108,115
17
(j)
Deferred Tax Adjustment
840,396,422
840,396,422
45
Total
966,684,630
6,322,748
10,099,533
970,461,415


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993, DEFERRED BALANCE TRANSFERRED TO BE AMORTIZED OVER 8.2 YEARS

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. CP08-31-001

DOCKET NO. CP08-31-002

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 41.5

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

RELATES TO THE ESTABLISHMENT OF A REGULATORY LIABILITY AS A RESULT OF THE TAX CUT AND JOBS ACT ENACTED ON DECEMBER 22, 2017.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Monthly Quantity & Revenue Data by Rate Schedule
  1. Reference to account numbers in the USofA is provided in parentheses beside applicable data. Quantities must not be adjusted for discounts.
  2. Total Quantities and Revenues in whole numbers.
  3. Report revenues and quantities of gas by rate schedule. Where transportation services are bundled with storage services, reflect only transportation Dth. When reporting storage, report Dth of gas withdrawn from storage and revenues by rate schedule.
  4. Revenues in Column (c) include transition costs from upstream pipelines. Revenue (Other) in Column (e) includes reservation charges received by the pipeline plus usage charges, less revenues reflected in Columns (c) and (d). Include in Column (e), revenue for Accounts 490-495.
  5. Enter footnotes as appropriate.
Line No.
Item
(a)
Month 1 Quantity
(b)
Month 1 Revenue Costs and Take-or-Pay
(c)
Month 1 Revenue (GRI & ACA)
(d)
Month 1 Revenue (Other)
(e)
Month 1 Revenue (Total)
(f)
Month 2 Quantity
(g)
Month 2 Revenue Costs and Take-or-Pay
(h)
Month 2 Revenue (GRI & ACA)
(i)
Month 2 Revenue (Other)
(j)
Month 2 Revenue (Total)
(k)
Month 3 Quantity
(l)
Month 3 Revenue Costs and Take-or-Pay
(m)
Month 3 Revenue (GRI & ACA)
(n)
Month 3 Revenue (Other)
(o)
Month 3 Revenue (Total)
(p)
1
Total Sales (480-488)
2,474
2,474
70,000
7,621
7,621
7,195
7,195
2
Transportation of Gas for Others (489.2 and 489..3)
3
FDLS
6,535,532
8,497
7,416,336
7,424,833
7,885,210
10,251
6,699,342
6,709,593
9,241,339
12,014
7,417,462
7,429,476
4
FT
474,833,932
460,432
137,366,121
137,826,553
388,826,597
369,792
123,150,970
123,520,762
436,068,671
417,113
134,490,934
134,908,047
5
FTG
22,059
29
8,874
8,903
2,291
3
922
925
8,742
12
3,516
3,528
6
FTP
463,638
58,775
58,775
453,025
57,430
57,430
490,636
62,233
62,233
7
ICTS
5,825,314
131,985
131,985
4,686,521
125,780
125,780
7,124,044
163,232
163,232
8
IT
37,116,631
26,328
2,433,952
2,460,280
28,855,560
20,773
1,449,084
1,469,857
31,856,520
24,043
1,516,807
1,540,850
9
Other
130,645
130,645
64,200
64,200
101,050
101,050
63
Total Transportation (Other than Gathering)
524,797,106
495,286
147,546,688
148,041,974
430,709,204
400,819
131,547,728
131,948,547
484,789,952
453,182
143,755,234
144,208,416
64
Storage (489.4)
65
10,051
10,051
9,079
9,079
10,051
10,051
66
3,611,671
1,685,053
1,685,053
1,565,670
1,428,164
1,428,164
1,962,969
1,588,379
1,588,379
67
13,493,785
5,109,670
5,109,670
10,293,116
4,520,613
4,520,613
12,014,313
5,017,612
5,017,612
68
151,425
103,598
103,598
12,598
91,666
91,666
67,593
101,756
101,756
69
802,725
802,725
689,014
689,014
778,957
778,957
70
3,105,327
1,008,397
1,008,397
2,491,717
903,405
903,405
2,323,698
989,912
989,912
71
2,745,261
689,531
689,531
2,619,005
756,396
756,396
1,525,058
688,950
688,950
72
1,912,483
1,227,542
1,227,542
1,859,680
1,113,092
1,113,092
2,211,335
1,237,356
1,237,356
73
14,247,419
1,539,557
1,539,557
6,594,038
1,310,465
1,310,465
5,673,263
1,444,955
1,444,955
74
88,197
88,197
3,534
3,534
4,345
4,345
90
Total Storage
39,267,371
12,087,927
12,087,927
25,435,824
10,825,428
10,825,428
25,778,229
11,853,583
11,853,583
91
Gathering (489.1)
92
Gathering-Firm
93
Gathering-Interruptible
1,092,267
289,890
289,890
915,348
241,935
241,935
1,169,644
310,081
310,081
94
Total Gathering (489.1)
1,092,267
289,890
289,890
915,348
241,935
241,935
1,169,644
310,081
310,081
95
Additional Revenues
96
Products Sales and Extraction (490-492)
97
Rents (493-494)
98
(495) Other Gas Revenues
2,576,997
4,022,026
4,022,026
3,102,488
11,024,271
11,024,271
1,492,101
4,181,788
4,181,788
99
(496) (Less) Provision for Rate Refunds
100
Total Additional Revenues
2,576,997
4,022,026
4,022,026
3,102,488
11,024,271
11,024,271
1,492,101
4,181,788
4,181,788
101
Total Operating Revenues (Total of Lines 1,63,90,94 & 100)
567,733,741
495,286
163,949,005
164,444,291
460,232,864
400,819
153,646,983
154,047,802
513,229,926
453,182
160,107,881
160,561,063


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Natural Gas Company- Gas Revenues and Dekatherms
  1. Report below in columns (b), (d) and (f) natural gas operating revenues for each prescribed account year to date.
  2. In column (f) report the quantity of Dekatherms sold of natural gas year to date.
Line No.
Title of Account
(a)
Total Operating Revenues Year to Date Current Qtr
(b)
Dekatherms of Natural Gas Year to Date Current Qtr
(c)
1 ResidentialSalesAbstract (480) Residential Sales
2 CommercialAndIndustrialSalesAbstract (481) Commercial and Industrial Sales
3 OtherSalesToPublicAuthoritiesAbstract (482) Other Sales to Public Authorities
4 SalesForResaleAbstract (483) Sales for Resale
5 InterdepartmentalSalesAbstract (484) Interdepartmental Sales
6 SalesOfGasNotInlcudingIntracompanyTransfersAbstract Total Sales (Lines 1 to 5)
7 IntracompanyTransfersAbstract (485) Intracompany Transfers
8 ForfeitedDiscountsAbstract (487) Forfeited Discounts
13,790
9 MiscellaneousServiceRevenuesAbstract (488) Miscellaneous Service Revenues
3,500
10 RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilitiesAbstract (489.1) Revenues from Transportation of Gas of Others Through Gathering Facilities
841,906
3,177,259
11 RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract (489.2) Revenues from Transportation of Gas of Others Through Transmission Facilities
424,198,936
1,440,296,262
12 RevenuesFromTransportationOfGasOfOthersThroughDistributionFacilitiesAbstract (489.3) Revenues from Transportation of Gas of Others Through Distribution Facilities
13 RevenuesFromStoringGasOfOthersAbstract (489.4) Revenues from Storing Gas of Others
34,766,937
90,481,424
14 SalesOfProductsExtractedFromNaturalGasAbstract (490) Sales of Prod. Ext. from Natural Gas
15 RevenuesFromNaturalGasProcessedByOthersAbstract (491) Revenues from Natural Gas Proc. by Others
16 IncidentalGasolineAndOilSalesAbstract (492) Incidental Gasoline and Oil Sales
17 RentFromGasPropertyAbstract (493) Rent from Gas Property
18 InterdepartmentalRentsAbstract (494) Interdepartmental Rents
19 OtherGasRevenuesAbstract (495) Other Gas Revenues
19,228,086
20 OperatingRevenuesBeforeProvisionForRateRefundsAbstract Subtotal:
479,053,155
21 ProvisionForRateRefundsAbstract (496) (Less) Provision for Rate Refunds
22 OperatingRevenuesAbstract TOTAL
479,053,155


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Gas Production and Other Gas Supply Expenses

Report the amount of gas production and other gas supply expenses year to date.

Line No.
Account
(a)
Year to Date
(b)
1
ProductionExpensesAbstract Production Expenses
2
ManufacturedGasProductionAbstract Manufactured Gas Production
3
ManufacturedGasProduction Total Manufactured Gas Production (700-742)
4
NaturalGasProductionAndGatheringPlantAbstract Natural Gas Production and Gathering
5
ProductionOperationExpense (750-760) Operation
775,168
6
ProductionMaintenanceExpense (761-769) Maintenance
42,956
7
NaturalGasProductionAndGatheringPlantExpense Total Natural Gas Production and Gathering (lines 5 and 6)
818,124
8
ProductionExtractionAbstract Production Extraction
9
ProductsExtractionOperationExpense (770-783) Operation
10
ProductsExtractionMaintenanceExpense (784-791) Maintenance
11
ProductsExtractionExpense Total Production Extraction (lines 9 and 10)
12
ExplorationAndDevelopment (795-798) Exploration and Development Expenses
13
OtherGasSupplyExpensesAbstract Other Gas Supply Expenses
14
OtherGasSupplyExpensesOperationAbstract Operation
15
NaturalGasWellHeadPurchases (800) Natural Gas Well Head Purchases
16
NaturalGasWellHeadPurchasesIntracompanyTransfers (800.1) Natural Gas Well Head Purchases, Intra company Transfers
17
NaturalGasFieldLinePurchases (801) Natural Gas Field Line Purchases
18
NaturalGasGasolinePlantOutletPurchases (802) Natural Gasoline Plant Outlet Purchases
19
NaturalGasTransmissionLinePurchases (803) Natural Gas Transmission Line Purchases
128,234,439
20
NaturalGasCityGatePurchases (804) Natural Gas City Gate Purchases
21
LiquefiedNaturalGasPurchases (804.1) Liquefied Natural Gas Purchases
22
OtherGasPurchases (805) Other Gas Purchases
23
PurchasedGasCostAdjustments (805.1) (Less) Purchase Gas Cost Adjustments
24
PurchasedGasOperationExpenses Total Purchased Gas (lines 15 through 23)
128,234,439
25
ExchangeGas (806) Exchange Gas
3,460,068
26
PurchasedGasExpensesAbstract Purchased Gas Expenses
27
WellExpensePurchasedGas (807.1) Well Expense - Purchased Gas
28
OperationOfPurchasedGasMeasuringStations (807.2) Operation of Purchased Gas Measuring Stations
29
MaintenanceOfPurchasedGasMeasuringStations (807.3) Maintenance of Purchased Gas Measuring Stations
30
PurchasedGasCalculationsExpenses (807.4) Purchased Gas Calculations Expenses
31
OtherPurchasedGasExpenses (807.5) Other Purchased Gas Expenses
32
PurchasedGasExpenses Total Purchased Gas Expenses (lines 27 thru 31)
33
GasWithdrawnFromStorageDebt (808.1) Gas Withdrawn from Storage-Debit
47,877,524
34
GasDeliveredToStorageCredit (808.2) (Less) Gas Delivered to Storage - Credit
26,325,846
35
WithdrawalsOfLiquefiedNaturalGasHeldForProcessingDebit (809.1) Withdrawals of Liquefield Natural Gas for Processing - Debit
36
DeliveriesOfNaturalGasForProcessingCredit (809.2) (Less) Deliveries of Natural Gas Processing - Credit
37
GasUsedInUtilityOperationAbstract Gas Used in Utility Operation - Credit
38
GasUsedForCompressorStationFuelCredit (810) Gas Used for Compressor Station Fuel - Credit
196,875
39
GasUsedForProductsExtractionCredit (811) Gas Used for Products Extraction - Credit
40
GasUsedForOtherUtilityOperationsCredit (812) Gas Used for Other Utility Operations - Credit
12,032,243
41
GasUsedInUtilityOperationCredit Total Gas Used in Utility Operations - Credit (Lines 38 thru 40)
12,229,118
42
OtherGasSupplyExpenses (813) Other Gas Supply Expense
12,576,813
43
OtherGasSupplyExpensesOperation Total Other Gas Supply Expenses (Lines 24, 25, 32, 33, thru 36, 42, less 41)
50,918,696
44
ProductionExpenses Total Production Expenses (Lines 3,7,11,12, and 43)
51,736,820


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Natural Gas Storage, Terminaling, Processing Services

Report the amount of natural gas storage, terminaling, processing, transmission and distribution expenses year to date.

Line No.
Account
(a)
Year to Date Quarter
(b)
1
NaturalGasStorageTerminalingAndProcessingExpensesAbstract NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES
2
UndergroundStorageExpensesAbstract UNDERGROUND STORAGE EXPENSES
3
UndergroundStorageOperationExpenses (814-826) Operations
19,833,912
4
UndergroundStorageMaintenanceExpenses (830-837) Maintenance
1,296,382
5
UndergroundStorageExpenses Total Underground Storage Expenses (Lines 3 and 4)
21,130,294
6
OtherStorageExpensesAbstract OTHER STORAGE EXPENSES
7
OtherStorageOperationExpenses (840-842.3) Operations
1,346,889
8
OtherStorageMaintenanceExpenses (843.1-843.9) Maintenance
23,079
9
OtherStorageExpenses Total Other Storage Expenses (lines 7 and 8)
1,369,968
10
LiquifiedNaturalGasTerminalingAndProcessingExpensesAbstract LIQUEFIED NATURAL GAS TERMINALING AND PROCESSING
11
LiquifiedNaturalGasTerminalingAndProcessingOperationExpenses (844.1-846.2) Operations
12
LiquifiedNaturalGasTerminalingAndProcessingMaintenanceExpenses (847.1-847.8) Maintenance
13
LiquifiedNaturalGasTerminalingAndProcessingExpenses Total Liquefied Natural Gas Terminaling and Processing (Lines 11 and 12)
14
TransmissionExpensesAbstract TRANSMISSION EXPENSES
15
TransmissionExpensesOperationAbstract Transmission Operation Expenses
16
OperationSupervisionAndEngineeringGasTransmissionExpenses (850) Operation Supervision and Engineering
12,725,367
17
SystemControlAndLoadDispatchingGas (851) System Control and Load Dispatching
871,243
18
CommunicationSystemExpenses (852) Communication System Expenses
1,245,747
19
CompressorStationLaborAndExpensesTransmissionExpenses (853) Compressor Station Labor and Expenses
10,998,144
20
GasForCompressorStationFuel (854) Gas for Compressor Station Fuel
2,617,232
21
OtherFuelAndPowerForCompressorStations (855) Other Fuel and Power for Compressor Stations
11,964,428
22
MainsExpenses (856) Mains Expenses
22,909,851
23
MeasuringAndRegulatingStationExpensesTransmissionExpenses (857) Measuring and Regulating Station Expenses
879,339
24
TransmissionAndCompressionOfGasByOthers (858) Transmission and Compression of Gas by Others
25
OtherExpensesGasTransmission (859) Other Expenses
1,123,287
26
RentsGasTransmissionExpense (860) Rents
860,875
27
TransmissionOperationExpense Total Transmission Operation Expenses (Lines 16 through 26)
60,961,049
28
TransmissionExpensesMaintenanceAbstract Transmission Maintenance Expenses
29
MaintenanceSupervisionAndEngineeringGasTransmissionExpenses (861) Maintenance Supervision and Engineering
13,309
30
MaintenanceOfStructuresAndImprovementsTransmissionExpenses (862) Maintenance of Structures and Improvements
1,384,242
31
MaintenanceOfMainsTransmissionExpenses (863) Maintenance of Mains
717,174
32
MaintenanceOfCompressorStationEquipmentTransmissionExpenses (864) Maintenance of Compressor Station Equipment
5,258,542
33
MaintenanceOfMeasuringAndRegulatingStationEquipment (865) Maintenance of Measuring and Regulating Equipment
311,578
34
MaintenanceOfCommunicationEquipmentGasTransmission (866) Maintenance of Communication Equipment
9,147
35
MaintenanceOfOtherEquipmentTransmissionExpenses (867) Maintenance of Other Equipment
62,992
36
TransmissionMaintenanceExpensesGas Total Transmission Maintenance Expenses (Lines 29 through 35)
7,756,984
37
TransmissionExpenses Total Transmission Expenses (lines 27 and 36)
68,718,033
38
DistributionExpensesAbstract DISTRIBUTION EXPENSES
39
DistributionOperationExpensesGas (870-881) Operation Expenses
40
DistributionMaintenanceExpenseGas (885-894) Maintenance
41
DistributionExpenses Total Distribution Expenses (Lines 39 and 40)
42
OperationAndMaintenanceExpensesIncludingNaturalGasStorageTerminalingAndProcessingExpensesTransmissionExpensesDistributionExpenses Total (lines 5,9,13,37 and 41)
91,218,295


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Gas Customer Accounts, Service, Sales, Administrative and General Expenses

Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.

Line No.
Account
(a)
Year to Date Quarter
(b)
1
CustomerAccountExpenses (901-905) Customer Accounts Expenses
27,750
2
CustomerServiceAndInformationalExpenses (907-910) Customer Service and Information Expenses
3
SalesExpenses (911-916) Sales Expenses
4
AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5
AdministrativeAndGeneralExpensesOperationAbstract Operations
6
AdministrativeAndGeneralSalaries 920 Administrative and General Salaries
8,877,082
7
OfficeSuppliesAndExpenses 921 Office Supplies and Expenses
679,649
8
AdministrativeExpensesTransferredCredit (Less) 922 Administrative Expenses Transferred-Credit
1,474,710
9
OutsideServicesEmployed 923 Outside Services Employed
13,164,503
10
PropertyInsurance 924 Property Insurance
3,492,688
11
InjuriesAndDamages 925 Injuries and Damages
618,774
12
EmployeePensionsAndBenefits 926 Employee Pensions and Benefits
5,367,954
13
FranchiseRequirements 927 Franchise Requirements
14
RegulatoryCommissionExpenses 928 Regulatory Commission Expenses
1,093,956
15
DuplicateChargesCredit (Less) 929 Duplicate Charges-Credit
16
GeneralAdvertisingExpenses 930.1 General Advertising Expenses
17
MiscellaneousGeneralExpenses 930.2 Miscellaneous General Expenses
16,372,427
18
RentsAdministrativeAndGeneralExpense 931 Rents
971,922
19
AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 through 18)
49,164,245
20
MaintenanceAbstract Maintenance
21
MaintenanceOfGeneralPlant 932 Maintenance of General Plant
22
AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)
49,164,245


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


Year/Period of Report:


End of:
2018
/
Q1
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 403.1, 404.1, 404.2, 404.3, 405) (Except Amort of Acqusition Adjustments)
  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.
Functional Classification
(a)
Depreciation Expense (Account 403)
(b)
Depreciation Expense for Asset Retirement Costs (Account 403.1)
(c)
Amortization and Depletion of Other Gas Plant (Accounts 404.1, 404.2 and 404.3)
(d)
Amortization of Other Gas Plant (Account 405)
(e)
Total (b to e)
(f)
1
Intangible Plant
256,754
256,754
2
Production Plant, Manufacturing Plant
3
Production and Gathering Plant - Natural Gas
498,974
48,806
547,780
4
Products Extraction - Natural Gas
5
Underground Gas Storage Plant
1,885,600
18,184
1,903,784
6
Other Storage Plant
397,869
397,869
7
Base Load LNG Terminaling and Processing Plant
8
Processing Plant
9
Transmission Plant
71,580,872
4,061,664
67,519,208
10
Distribution Plant
11
General Plant
2,340,498
1,022,853
3,363,351
12
Common Plant
13
Total
76,703,813
3,994,674
1,022,853
256,754
73,988,746


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Gas Account - Natural Gas
  1. The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent.
  2. Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas.
  3. Enter in column (c) the year to date Dth as reported in the schedules indicated for the items of receipts and deliveries.
  4. Enter in column (d) the respective quarter’s Dth as reported in the schedules indicated for the items of receipts and deliveries.
  5. Indicate in a footnote the quantities of bundled sales and transportation gas and specify the line on which such quantities are listed.
  6. If the respondent operates two or more systems which are not interconnected, submit separate pages for this purpose.
  7. Indicate by footnote the quantities of gas not subject to Commission regulation which did not incur FERC regulatory costs by showing (1) the local distribution volumes another jurisdictional pipeline delivered to the local distribution company portion of the reporting pipeline (2) the quantities that the reporting pipeline transported or sold through its local distribution facilities or intrastate facilities and which the reporting pipeline received through gathering facilities or intrastate facilities, but not through any of the interstate portion of the reporting pipeline, and (3) the gathering line quantities that were not destined for interstate market or that were not transported through any interstate portion of the reporting pipeline.
  8. Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes reported on line No. 3 relate.
  9. Indicate in a footnote (1) the system supply quantities of gas that are stored by the reporting pipeline, during the reporting year and also reported as sales,transportation and compression volumes by the reporting pipeline during the same reporting year, (2) the system supply quantities of gas that are stored by the reporting pipeline during the reporting year which the reporting pipeline intends to sell or transport in a future reporting year, and (3) contract storage quantities.
  10. Also indicate the volumes of pipeline production field sales that are included in both the company's total sales figure and the company;s total transportation figure. Add additional information as necessary to the footnotes.
Line No.
Item
(a)
Ref. Page No. of (FERC Form Nos. 2/2-A)
(b)
Total Amount of Dth Year to Date
(c)
Current Three Months Ended Amount of Dth Quarterly Only
(d)
1
NameOfSystem
Name of System
2
QuantityOfNaturalGasReceivedByUtilityAbstract
GAS RECEIVED
3
QuantityOfNaturalGasReceivedByUtilityGasPurchases
Gas Purchases (Accounts 800-805)
(a)(b)
28,506,249
(n)(o)
28,506,249
4
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForGathering
Gas of Others Received for Gathering (Account 489.1)
303
3,177,259
3,177,259
5
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForTransmission
Gas of Others Received for Transmission (Account 489.2)
305
1,440,296,262
1,440,296,262
6
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForDistribution
Gas of Others Received for Distribution (Account 489.3)
301
7
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForContractStorage
Gas of Others Received for Contract Storage (Account 489.4)
307
90,481,424
90,481,424
8
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForProductionExtractionProcessing
Gas of Others Received for Production/Extraction/Processing (Account 490 and 491)
9
QuantityOfNaturalGasReceivedByUtilityExchangedGasReceivedFromOthers
Exchanged Gas Received from Others (Account 806)
328
6,430,000
6,430,000
10
QuantityOfNaturalGasReceivedByUtilityGasReceivedAsImbalances
Gas Received as Imbalances (Account 806)
328
7,087,787
7,087,787
11
QuantityOfNaturalGasReceivedByUtilityReceiptsOfUtilitysGasTransportedByOthers
Receipts of Respondent's Gas Transported by Others (Account 858)
332
12
QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage
Other Gas Withdrawn from Storage (Explain)
(c)(d)
11,124,541
(p)(q)
11,124,541
13
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsCompressorStationFuel
Gas Received from Shippers as Compressor Station Fuel
6,521,430
6,521,430
14
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor
Gas Received from Shippers as Lost and Unaccounted for
(e)(f)
2,832,313
(r)(s)
2,832,313
15
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
(g)(h)
753,453
(t)(u)
753,453
15.1
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
16
QuantityOfNaturalGasReceivedByUtility
Total Receipts (Total of lines 3 thru 15)
(i)
1,574,961,636
(v)
1,574,961,636
17
QuantityOfNaturalGasDeliveredByUtilityAbstract
GAS DELIVERED
18
QuantityOfNaturalGasDeliveredByUtilityGasSales
Gas Sales (Accounts 480-484)
19
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasGatheredForOthers
Deliveries of Gas Gathered for Others (Account 489.1)
303
3,177,259
3,177,259
20
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasTransportedForOthers
Deliveries of Gas Transported for Others (Account 489.2)
305
1,440,296,262
1,440,296,262
21
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasDistributedForOthers
Deliveries of Gas Distributed for Others (Account 489.3)
301
22
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfContractStorageGas
Deliveries of Contract Storage Gas (Account 489.4)
307
9,916,086
9,916,086
23
QuantityOfNaturalGasDeliveredByUtilityGasOfOthersDeliveredForProductionExtractionProcessing
Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491)
24
QuantityOfNaturalGasDeliveredByUtilityExchangeGasDeliveredToOthers
Exchange Gas Delivered to Others (Account 806)
328
6,430,000
6,430,000
25
QuantityOfNaturalGasDeliveredByUtilityGasDeliveredAsImbalances
Gas Delivered as Imbalances (Account 806)
328
7,181,375
7,181,375
26
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasToOthersForTransportation
Deliveries of Gas to Others for Transportation (Account 858)
332
27
QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage
Other Gas Delivered to Storage (Explain)
(j)(k)
6,106,125
(w)(x)
6,106,125
28
QuantityOfNaturalGasDeliveredByUtilityGasUsedForCompressorStationFuel
Gas Used for Compressor Station Fuel
509
9,629,095
9,629,095
29
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
(l)(m)
88,692,405
(y)(z)
88,692,405
29.1
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
30
QuantityOfNaturalGasDeliveredByUtility
Total Deliveries (Total of lines 18 thru 29)
1,571,428,607
1,571,428,607
31
GasLossesAndGasUnaccountedForGasAccountAbstract
GAS LOSSES AND GAS UNACCOUNTED FOR
32
GasAccountGasLossesAndGasUnaccountedForGasAccount
Gas Losses and Gas Unaccounted For
3,533,029
3,533,029
33
DeliveriesGasLossesAndUnaccountedForGasAccountAbstract
TOTALS
34
DeliveriesGasLossesAndUnaccountedForGasAccount
Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32)
1,574,961,636
1,574,961,636


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN C, INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

11,006,249

DTs

SYSTEM MANAGEMENT GAS PURCHASES

17,500,000

DTs

 

28,506,249

DTs

(b) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN D INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

11,006,249

DTs

SYSTEM MANAGEMENT GAS PURCHASES

17,500,000

DTs

 

28,506,249

DTs

(c) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

(5,194,160)

LSS

 

(421,869)

SS-2

 

(854,047)

S2

 

(1,035,941)

WSS

 

(5,428,862)

LNG

 

902,995

LGS

 

0

EMINENCE

 

1,138,959

LGA

 

(231,616)

TOTAL

 

(11,124,541)

(d) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

(5,194,160)

LSS

 

(421,869)

SS-2

 

(854,047)

S-2

 

(1,035,941)

WSS

 

(5,428,862)

LNG

 

902,995

LGS

 

0

EMINENCE

 

1,138,959

LGA

 

(231,616)

TOTAL

 

(11,124,541)

(e) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

IN THE FIRST QUARTER, 30.28% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2017 FUEL TRACKER FILING.

(f) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

FIRST QUARTER:

 

30.28% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2017 FUEL TRACKER FILING.

(g) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

753,453 DTs

(h) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

753,453 DTs

(i) Concept: QuantityOfNaturalGasReceivedByUtility

 

FOOTNOTE TO INSTRUCTION 5:

 

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC DOES NOT BUNDLE SALES AND TRANSPORTATION SERVICES.

 

FOOTNOTE TO INSTRUCTION 7:

 

ALL QUANTITIES OF GAS WERE SUBJECT TO COMMISSION REGULATION.

 

FOOTNOTE TO INSTRUCTION 9 (3):

 

CONTRACT STORAGE QUANTITIES ARE AS FOLLOWS:

 

RATE SCHEDULE

DTs

RATE SCHEDULE

DTs

ESS

4,131,578

S-2

1,680,050

GSS

15,900,957

SS-2

1,437,562

LGA

219,018

WSS

37,491,200

LNG

1,322,879

LSS

2,875,563

LGS

(62)

 

 

 

FOOTNOTE TO INSTRUCTION 10:

 

THERE ARE NO VOLUMES OF PIPELINE PRODUCTION FIELD SALES INCLUDED IN THE TOTAL SALES VOLUMES OR THE TOTAL TRANSPORTATION VOLUMES.

(j) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

(5,235,263)

LSS

 

(476,951)

SS-2

 

0

S-2

 

945

WSS

 

3,276,066

LGA

 

0

LGS

 

0

EMINENCE

 

(2,873,000)

LNG

 

(797,922)

TOTAL

 

(6,106,125)

(k) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

(5,235,263)

LSS

 

(476,951)

SS-2

 

0

S-2

 

945

WSS

 

3,276,066

LGA

 

0

LGS

 

0

EMINENCE

 

(2,873,000)

LNG

 

(797,922)

TOTAL

 

(6,106,125)

(l) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

7,620,458

INCREASE IN LINE PACK

 

331,794

CATHODIC PROTECTION

 

3,117

PURGING AND TESTING

 

171,698

CONTRACT STORAGE RECEIVED

 

90,481,424

CONTRACT STORAGE DELIVERED

 

(9,916,086)

TOTAL

 

88,692,405

(m) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

7,620,458

INCREASE IN LINE PACK

 

331,794

CATHODIC PROTECTION

 

3,117

PURGING AND TESTING

 

171,698

CONTRACT STORAGE RECEIVED

 

90,481,424

CONTRACT STORAGE DELIVERED

(9,916,086)

TOTAL

 

88,692,405

(n) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN C, INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

11,006,249

DTs

SYSTEM MANAGEMENT GAS PURCHASES

17,500,000

DTs

 

28,506,249

DTs

(o) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN D INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

11,006,249

DTs

SYSTEM MANAGEMENT GAS PURCHASES

17,500,000

DTs

 

28,506,249

DTs

(p) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

(5,194,160)

LSS

 

(421,869)

SS-2

 

(854,047)

S2

 

(1,035,941)

WSS

 

(5,428,862)

LNG

 

902,995

LGS

 

0

EMINENCE

 

1,138,959

LGA

 

(231,616)

TOTAL

 

(11,124,541)

(q) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

(5,194,160)

LSS

 

(421,869)

SS-2

 

(854,047)

S-2

 

(1,035,941)

WSS

 

(5,428,862)

LNG

 

902,995

LGS

 

0

EMINENCE

 

1,138,959

LGA

 

(231,616)

TOTAL

 

(11,124,541)

(r) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

IN THE FIRST QUARTER, 30.28% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2017 FUEL TRACKER FILING.

(s) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

FIRST QUARTER:

 

30.28% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2017 FUEL TRACKER FILING.

(t) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

753,453 DTs

(u) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

753,453 DTs

(v) Concept: QuantityOfNaturalGasReceivedByUtility

 

FOOTNOTE TO INSTRUCTION 5:

 

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC DOES NOT BUNDLE SALES AND TRANSPORTATION SERVICES.

 

FOOTNOTE TO INSTRUCTION 7:

 

ALL QUANTITIES OF GAS WERE SUBJECT TO COMMISSION REGULATION.

 

FOOTNOTE TO INSTRUCTION 9 (3):

 

CONTRACT STORAGE QUANTITIES ARE AS FOLLOWS:

 

RATE SCHEDULE

DTs

RATE SCHEDULE

DTs

ESS

4,131,578

S-2

1,680,050

GSS

15,900,957

SS-2

1,437,562

LGA

219,018

WSS

37,491,200

LNG

1,322,879

LSS

2,875,563

LGS

(62)

 

 

 

FOOTNOTE TO INSTRUCTION 10:

 

THERE ARE NO VOLUMES OF PIPELINE PRODUCTION FIELD SALES INCLUDED IN THE TOTAL SALES VOLUMES OR THE TOTAL TRANSPORTATION VOLUMES.

(w) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

(5,235,263)

LSS

 

(476,951)

SS-2

 

0

S-2

 

945

WSS

 

3,276,066

LGA

 

0

LGS

 

0

EMINENCE

 

(2,873,000)

LNG

 

(797,922)

TOTAL

 

(6,106,125)

(x) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

(5,235,263)

LSS

 

(476,951)

SS-2

 

0

S-2

 

945

WSS

 

3,276,066

LGA

 

0

LGS

 

0

EMINENCE

 

(2,873,000)

LNG

 

(797,922)

TOTAL

 

(6,106,125)

(y) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

7,620,458

INCREASE IN LINE PACK

 

331,794

CATHODIC PROTECTION

 

3,117

PURGING AND TESTING

 

171,698

CONTRACT STORAGE RECEIVED

 

90,481,424

CONTRACT STORAGE DELIVERED

 

(9,916,086)

TOTAL

 

88,692,405

(z) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

7,620,458

INCREASE IN LINE PACK

 

331,794

CATHODIC PROTECTION

 

3,117

PURGING AND TESTING

 

171,698

CONTRACT STORAGE RECEIVED

 

90,481,424

CONTRACT STORAGE DELIVERED

(9,916,086)

TOTAL

 

88,692,405


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 1
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
20,192
99,547
3,328,741
3,448,480
76,451
376,926
12,603,948
13,057,325
5
Distribution
6
Storage
123,400
123,400
467,242
467,242
7
Total Shipper Supplied Gas
20,192
99,547
3,452,141
3,571,880
76,451
376,926
13,071,190
(b)
13,524,567
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
20,978
103,431
3,458,593
(a)
3,583,002
79,433
391,629
13,095,617
13,566,679
12
Distribution
13
Storage
240,813
240,813
911,814
911,814
14
Total gas used in compressors
20,978
103,431
3,699,406
3,823,815
79,433
391,629
14,007,431
14,478,493
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
347
1,710
57,171
59,228
1,047
5,164
172,679
178,890
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
347
1,710
57,171
59,228
1,047
5,164
172,679
178,890
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
9,424
46,464
1,553,701
1,609,589
35,684
175,931
5,882,933
6,094,548
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
9,424
46,464
1,553,701
1,609,589
35,684
175,931
5,882,933
6,094,548
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
10,557
52,058
1,740,724
1,803,339
39,713
195,798
6,547,281
6,782,792
35
Distribution
36
Storage
117,413
117,413
444,573
444,573
37
Total Net Excess Or (Deficiency)
10,557
52,058
1,858,137
1,920,752
39,713
195,798
6,991,854
7,227,365
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
55.1
Gas Used to meet imbalances
10,557
52,058
1,858,137
1,920,752
39,713
195,798
6,991,854
7,227,365
65
Total Gas Acquired To Meet Deficiency
10,557
52,058
1,858,137
1,920,752
39,713
195,798
6,991,854
7,227,365

SEPARATION OF FORWARDHAUL AND BACKHAUL THROUGHPUT
Line No.
Item
(a)
Quarter
Dth (b)
66
Forwardhaul Volume in Dths for the Quarter
1,384,359,521
67
Backhaul Volume in Dths for the Quarter
59,114,000
68
TOTAL (Lines 66 and 67)
1,443,473,521


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
FOOTNOTE DATA

(a) Concept: GasUsedForCompressorStationFuelTransmission

 

THE FOLLOWING APPLIES TO ALL VOLUMES, FOR ALL MONTHS, IN LINES 11, 18, 26, 34, 40, AND 56:

 

VOLUMES WERE ALLOCATED PRORATA TO “DISCOUNTED RATE”, “NEGOTIATED RATE”, AND “RECOURSE RATE” BASED ON THE ACTUAL VOLUMES PRESENTED ON LINE 4.

(b) Concept: AmountCollectedShipperSuppliedGas

 

BASIS FOR VALUATION OF ALL GAS:

 

GAS IS VALUED MONTHLY AT A NGW INDEX PRICE WHEN THERE IS A NET EXCESS OF SHIPPER SUPPLIED GAS OR AT TRANSCO’S MONTHLY WACOG WHEN THERE IS A DEFICIENCY OF SHIPPER SUPPLIED GAS.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 2
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
17,344
59,329
2,471,067
2,547,740
48,082
164,467
6,850,041
7,062,590
5
Distribution
6
Storage
132,657
132,657
367,738
367,738
7
Total Shipper Supplied Gas
17,344
59,329
2,603,724
2,680,397
48,082
164,467
7,217,779
7,430,328
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
16,053
54,909
2,286,947
2,357,909
44,500
152,212
6,339,648
6,536,360
12
Distribution
13
Storage
178,438
178,438
494,648
494,648
14
Total gas used in compressors
16,053
54,909
2,465,385
2,536,347
44,500
152,212
6,834,296
7,031,008
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
335
1,146
47,726
49,207
991
3,391
141,244
145,626
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
335
1,146
47,726
49,207
991
3,391
141,244
145,626
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
7,342
25,112
1,045,932
1,078,386
20,352
69,614
2,899,428
2,989,394
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
7,342
25,112
1,045,932
1,078,386
20,352
69,614
2,899,428
2,989,394
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
6,386
21,838
909,538
937,762
17,761
60,750
2,530,279
2,608,790
35
Distribution
36
Storage
45,781
45,781
126,910
126,910
37
Total Net Excess Or (Deficiency)
6,386
21,838
955,319
983,543
17,761
60,750
2,657,189
2,735,700
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
55.1
Gas used to meet imbalances
6,386
21,838
955,319
983,543
17,761
60,750
2,657,189
2,735,700
65
Total Gas Acquired To Meet Deficiency
6,386
21,838
955,319
983,543
17,761
60,750
2,657,189
2,735,700


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report:

End of:
2018
/
Q1
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 3
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
17,187
90,993
2,841,026
2,949,206
48,513
256,825
8,018,796
8,324,134
5
Distribution
6
Storage
152,260
152,260
429,754
429,754
7
Total Shipper Supplied Gas
17,187
90,993
2,993,286
3,101,466
48,513
256,825
8,448,550
8,753,888
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
18,137
96,015
2,997,878
3,112,030
51,191
271,004
8,461,510
8,783,705
12
Distribution
13
Storage
156,903
156,903
442,859
442,859
14
Total gas used in compressors
18,137
96,015
3,154,781
3,268,933
51,191
271,004
8,904,369
9,226,564
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
387
2,048
63,945
66,380
1,034
5,472
170,856
177,362
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
387
2,048
63,945
66,380
1,034
5,472
170,856
177,362
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
4,925
26,072
814,057
845,054
13,901
73,589
2,297,675
2,385,165
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
4,925
26,072
814,057
845,054
13,901
73,589
2,297,675
2,385,165
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
6,262
33,142
1,034,854
1,074,258
17,613
93,240
2,911,245
3,022,098
35
Distribution
36
Storage
4,643
4,643
13,105
13,105
37
Total Net Excess Or (Deficiency)
6,262
33,142
1,039,497
1,078,901
17,613
93,240
2,924,350
3,035,203
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
55.1
Gas Used to meet imbalances
6,262
33,142
1,039,497
1,078,901
17,613
93,240
2,924,350
3,035,203
65
Total Gas Acquired To Meet Deficiency
6,262
33,142
1,039,497
1,078,901
17,613
93,240
2,924,350
3,035,203

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