FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 2-A: Annual Report of Non-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)

Cheniere Creole Trail Pipeline, L.P.

Year/Period of Report:

End of:

2018

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

GENERAL INFORMATION

Purpose
FERC Forms 2, 2-A, and 3-Q are designed to collect financial and operational information from 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.
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.

What and Where to Submit

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 .
The Corporate Officer Certification must be submitted electronically as part of the FERC Form 2 and 3-Q filings.
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

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:

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

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

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.
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

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).
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

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.
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.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions.
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, submit the electronic filing using the form submission only. Please explain the reason for the resubmission in a footnote to the data field.
Footnote and further explain accounts or pages as necessary.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Report all gas volumes in Dth unless the schedule specifically requires the reporting in another unit of measurement.

DEFINITIONS

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).
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.
Dekatherm – A unit of heating value equivalent to 10 therms or 1,000,000 Btu.
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-A REPORT OF MAJOR NATRURAL GAS COMPANIES
Identification
01 Exact Legal Name of Respondent Cheniere Creole Trail Pipeline, L.P.		02 Year/ Period of Report End of: 2018 / Q4
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) 700 Milam Street, Suite 1900, Houston, Texas 77002
05 Name of Contact Person Lane Dawson		06 Title of Contact Person Controller
07 Address of Contact Person (Street, City, State, Zip Code) 700 Milam Street, Suite 1900, Houston, Texas 77002
08 Telephone of Contact Person, Including Area Code 713-375-5223	09 This Report is An Original / A Resubmission (1) ☑ An Original (2) ☐ A Resubmission	10 Date of Report (Mo, Da, Yr) 04/18/2019
11 Name of Officer Having Custody of the Books of Account Leonard Travis		12 Title of Officer Chief Accounting Officer
13 Address of Officer Where Books of Accounts Are Kept (Street, City, State, Zip Code) 700 Milam Street, Suite 1900, Houston, Texas, 77002
14 Name of State Where Respondent is Incorporated DE	15 Date of Incorporation (Mo, Da, Yr) 12/27/2004	16 If applicable Reference Law Incorporated Under
17 Explanation of Manner and Extent of Corporate Control (If the respondent controls or is controlled by any other corporation, business trust, or similar organization) Cheniere Creole Trail Pipeline, L.P. ("CTPL"), a Delaware limited partnership, is a Houston based partnership formed with one general partner, Cheniere Pipeline GP Interests, LLC, and one limited partner, Cheniere Energy Investments, LLC ("Cheniere Investments"), both of which are wholly owned subsidiaries of Cheniere Energy Partners, L.P. ("Cheniere Partners").


Annual 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 Leonard Travis	12 Title Chief Accounting Officer
13 Signature Leonard Travis	14 Date Signed 04/18/2019
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:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

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	ScheduleSecurityHoldersAndVotingPowersAbstract Security Holders and Voting Powers	107	12-96
2	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108	12-96
3	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
4	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114	REV 06-04
5	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accumulated Comprehensive Income and Hedging Activities	117	NEW 06-02
6	ScheduleStatementOfRetainedEarningsAbstract Statement of Retained Earnings for the Year	118	REV 06-04
7	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120	REV 06-04
	BalanceSheetSupportingSchedulesAssetsAndOtherDebitsAbstract BALANCE SHEET SUPPORTING SCHEDULES (Assets and Other Debits)
8	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122.1	REV 12-07
9	ScheduleGasPlantInServiceAbstract Gas Plant in Service	204	12-96
10	ScheduleGeneralInformationOnPlantAndOperationsAbstract General Information on Plant and Operations	211.1	12-96
11	ScheduleGasPropertyAndCapacityLeasedFromOthersAbstract Gas Property and Capacity Leased from Others	212	12-96
	ScheduleGasPropertyAndCapacityLeasedToOthersAbstract Gas Property and Capacity Leased to Others	213	12-96
12	ScheduleNonTraditionalRateTreatmentAffordedNewProjectsAbstract Non-Traditional Rate Treatment Afforded New Projects	217	NEW 12-07
13	ScheduleAccumulatedProvisionForDepreciationOfGasUtilityPlantAbstract Accumulated Provision for Depreciation of Gas Utility Plant	219	12-96
14	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232	REV 12-07
	BalanceSheetSupportingSchedulesLiabilitiesAndOtherCreditsAbstract BALANCE SHEET SUPPORTING SCHEDULES (Liabilities and Other Credits)
15	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234	REV 12-07
16	ScheduleCapitalStockAndLongTermDebtDataAbstract Capital Stock and Long-Term Debt Data	250	12-96
17	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid And Charged During Year, Distribution Of Taxes Charged	262	REV 12-07
18	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property (Account 282)	274	REV 12-07
19	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other (Account 283)	276	REV 12-07
20	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278	REV 12-07
	IncomeAccountSupportingSchedulesAbstract INCOME ACCOUNT SUPPORTING SCHEDULES
21	ScheduleGasOperatingRevenuesAbstract Gas Operating Revenues	300	REV 12-07
22	ScheduleOtherGasRevenuesAbstract Other Gas Revenues	308	12-96
23	ScheduleDiscountedRateServicesAndNegotiatedRateServicesAbstract Discounted Rate Services And Negotiated Rate Services	313	NEW 12-07
24	ScheduleGasOperationAndMaintenanceExpensesAbstract Gas Operation And Maintenance Expenses	317	12-96
25	ScheduleEmployeePensionsAndBenefitsAbstract Employee Pensions And Benefits (Account 926)	352	NEW 12-07
26	ScheduleChargesForOutsideProfessionalAndOtherConsultativeServicesAbstract Charges For Outside Professional And Other Consultative Services	357	REVISED
27	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions With Associated (Affiliated) Companies	358	NEW 12-07
	StatisticalDataAbstract GAS PLANT STATISTICAL DATA
28	ScheduleGasAccountNaturalGasAbstract Gas Account - Natural Gas	520	REV 01-11
29	ScheduleShipperSuppliedGasForTheCurrentQuarterAbstract Shipper Supplied Gas for the Current Quarter	521	REVISED 02-11
30	ScheduleSystemMapsAbstract System Maps	522.1	REV. 12-96

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Security Holders and Voting Powers

Give the names and addresses of the 10 security holders of the respondent who, at the date of the latest closing of the stock book or compilation of list of stockholders of the respondent, prior to the end of the year, had the highest voting powers in the respondent, and state the number of votes that each could cast on that date if a meeting were held. If any such holder held in trust, give in a footnote the known particulars of the trust (whether voting trust, etc.), duration of trust, and principal holders of beneficiary interests in the trust. If the company did not close the stock book or did not compile a list of stockholders within one year prior to the end of the year, or if since it compiled the previous list of stockholders, some other class of security has become vested with voting rights, then show such 10 security holders as of the close of the year. Arrange the names of the security holders in the order of voting power, commencing with the highest. Show in column (a) the titles of officers and directors included in such list of 10 security holders.
If any security other than stock carries voting rights, explain in a supplemental statement how such security became vested with voting rights and give other important details concerning the voting rights of such security. State whether voting rights are actual or contingent; if contingent, describe the contingency.
If any class or issue of security has any special privileges in the election of directors, trustees or managers, or in the determination of corporate action by any method, explain briefly in a footnote.
Furnish details concerning any options, warrants, or rights outstanding at the end of the year for others to purchase securities of the respondent or any securities or other assets owned by the respondent, including prices, expiration dates, and other material information relating to exercise of the options, warrants, or rights. Specify the amount of such securities or assets any officer, director, associated company, or any of the 10 largest security holders is entitled to purchase. This instruction is inapplicable to convertible securities or to any securities substantially all of which are outstanding in the hands of the general public where the options, warrants.

1. Give date of the latest closing of the stock book prior to end of year, and, in a footnote, state the purpose of such closing:

2. State the total number of votes cast at the latest general meeting prior to the end of year for election of directors of the respondent and number of such votes cast by proxy.

Total:

By Proxy:

3. Give the date and place of such meeting:

Line No.

Name (Title) and Address of Security Holder

(a)

VOTING SECURITIES

4. Number of votes as of (date):

Total Votes

(b)

Common Stock

(c)

Preferred Stock

(d)

Other

(e)

TOTAL votes of all voting securities

TOTAL number of security holders

TOTAL votes of security holders listed below

(a)

Cheniere Energy Investments, LLC

700 Milam, Suite 1900

Houston, Texas 77002

(b)

Cheniere Pipeline GP Interests, LLC

700 Milam, Suite 1900

Houston, Texas 77002

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: NameTitleAndAddressOfSecurityHolder

100% LP Interest

(b) Concept: NameTitleAndAddressOfSecurityHolder

0% GP Interest

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

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. 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. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. Purchase or sale of an operating unit or system: 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. 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. 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. 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. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. State the estimated annual effect and nature of any important wage scale changes during the year. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder, 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. 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. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
1. None 2. None 3. None 4. None 5. None 6. None 7. None 8. None 9. None 10. None 11. None 12. None 13. Not Applicable

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

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	714,575,991	704,139,273
3	ConstructionWorkInProgress Construction Work in Progress (107)	200-201	63,119	85,729
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Total of lines 2 and 3)	200-201	714,639,110	704,225,002
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Provision for Depr., Amort., Depl. (108, 111, 115)		172,447,015	152,876,419
6	UtilityPlantNet Net Utility Plant (Total of line 4 less 5)		542,192,095	551,348,583
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)		542,192,095	551,348,583
11	OtherGasPlantAdjustments Utility Plant Adjustments (116)	122
12	GasStoredBaseGas Gas Stored-Base Gas (117.1)	220
13	SystemBalancingGas System Balancing Gas (117.2)	220
14	GasStoredInReservoirsAndPipelinesNoncurrent Gas Stored in Reservoirs and Pipelines-Noncurrent (117.3)	220
15	GasOwedToSystemGas Gas Owed to System Gas (117.4)	220	89,246	21,511
16	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
17	NonutilityProperty Nonutility Property (121)
18	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Provision for Depreciation and Amortization (122)
19	InvestmentInAssociatedCompanies Investments in Associated Companies (123)	222-223
20	InvestmentInSubsidiaryCompanies Investments in Subsidiary Companies (123.1)	224-225
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)
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)
31	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
32	Cash Cash (131)
33	SpecialDeposits Special Deposits (132-134)
34	WorkingFunds Working Funds (135)		5,000	5,000
35	TemporaryCashInvestments Temporary Cash Investments (136)	222-223	43,245	43,233
36	NotesReceivable Notes Receivable (141)
37	CustomerAccountsReceivable Customer Accounts Receivable (142)
38	OtherAccountsReceivable Other Accounts Receivable (143)
39	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Provision for Uncollectible Accounts - Credit (144)
40	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
41	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Associated Companies (146)		10,937,400	10,741,543
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)		1,741,392	1,557,166
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)
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
54	Prepayments Prepayments (165)	230	430,774	471,480
55	AdvancesForGas Advances for Gas (166 thru 167)
56	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
57	RentsReceivable Rents Receivable (172)
58	AccruedUtilityRevenues Accrued Utility Revenues (173)
59	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		198,825	542,753
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 Assets - Hedges (176)
64	CurrentAndAccruedAssets TOTAL Current and Accrued Assets (Total of lines 32 thru 63)		13,356,636	13,361,175
65	DeferredDebitsAbstract DEFERRED DEBITS
66	UnamortizedDebtExpense Unamortized Debt Expense (181)
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	999,068	3,125,345
70	PreliminarySurveyAndInvestigationCharges Preliminary Survey and Investigation Charges (Electric)(183)
71	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2)		4,616,342	4,615,629
72	ClearingAccounts Clearing Accounts (184)
73	TemporaryFacilities Temporary Facilities (185)
74	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	1,775,164	1,843,233
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		32,889,400
79	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
80	DeferredDebits TOTAL Deferred Debits (Total of lines 66 thru 79)		7,390,574	42,473,607
81	AssetsAndOtherDebits TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80)		562,850,059	607,161,854

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

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	559,360,590	568,704,132
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
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118-119
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250-251
14	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	117
15	ProprietaryCapital TOTAL Proprietary Capital (Total of lines 2 thru 14)		559,360,590	568,704,132
16	LongTermDebtAbstract LONG TERM DEBT
17	Bonds Bonds (221)	256-257
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
21	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)	258-259
22	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Dr (226)	258-259
23	CurrentPortionOfLongTermDebt (Less) Current Portion of Long-Term Debt
24	LongTermDebt TOTAL Long-Term Debt (Total of lines 17 thru 23)
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases-Noncurrent (227)
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)
35	OtherNoncurrentLiabilities TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34)
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	CurrentPortionOfLongTermDebt Current Portion of Long-Term Debt
38	NotesPayable Notes Payable (231)
39	AccountsPayable Accounts Payable (232)		154,155	265,264
40	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
41	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		2,570,149	3,991,286
42	CustomerDeposits Customer Deposits (235)
43	TaxesAccrued Taxes Accrued (236)	262-263	498,510	491,785
44	InterestAccrued Interest Accrued (237)
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	266,655	819,987
50	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)
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)		3,489,469	5,568,322
56	DeferredCreditsAbstract DEFERRED CREDITS
57	CustomerAdvancesForConstruction Customer Advances for Construction (252)
58	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)
59	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
60	OtherDeferredCredits Other Deferred Credits (253)	269
61	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278
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)			(a) 32,529,278
65	AccumulatedDeferredIncomeTaxesOther Accumulated Deferred Income Taxes - Other (283)			(b) 360,122
66	DeferredCredits TOTAL Deferred Credits (Total of lines 57 thru 65)			32,889,400
67	LiabilitiesAndOtherCredits TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66)		562,850,059	607,161,854

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

Duplicate fact discrepancy. Schedule: 274 - Schedule - Accumulated Deferred Income Taxes - Other Property (Account 282) - Classified by Business Activities, Row: 7, Column: b, Value: -32529278

(b) Concept: AccumulatedDeferredIncomeTaxesOther

Duplicate fact discrepancy. Schedule: 276 - Schedule - Accumulated Deferred Income Taxes - Other (Account 283) - Classified by Business Activities, Row: 7, Column: b, Value: -360122

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Statement of Income
Quarterly 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. 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. 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. If additional columns are needed place them in a footnote. Annual or Quarterly, if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility 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. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. 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. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting 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. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	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	81,690,583	81,761,865					81,690,583	81,761,865
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	317-325	15,119,510	17,921,217					15,119,510	17,921,217
5	MaintenanceExpense Maintenance Expenses (402)	317-325	1,012,947	776,752					1,012,947	776,752
6	DepreciationExpense Depreciation Expense (403)	336-338	19,093,292	17,830,210					19,093,292	17,830,210
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336-338
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336-338	971,940	1,137,852					971,940	1,137,852
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)		2,205,300	936,432					2,205,300	936,432
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		2,479,023	2,691,563					2,479,023	2,691,563
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262-263	10,175,474	5,779,497					10,175,474	5,779,497
15	IncomeTaxesUtilityOperatingIncome Income Taxes-Federal (409.1)	262-263
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes-Other (409.1)	262-263		167,800						167,800
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision of Deferred Income Taxes (410.1)	234-235		1,872,454						1,872,454
18	ProvisionForDeferredIncomeTaxesCreditUtilityOperatingIncome (Less) Provision for Deferred Income Taxes-Credit (411.1)	234-235		1,872,454						1,872,454
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adjustment-Net (411.4)
20	GainsFromDispositionOfPlant (Less) Gains from Disposition of Utility Plant (411.6)
21	LossesFromDispositionOfUtilityPlant Losses from Disposition of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Total of lines 4 thru 24)		46,099,440	41,858,197					46,099,440	41,858,197
26	NetUtilityOperatingIncome Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to line 27)		35,591,143	39,903,668					35,591,143	39,903,668
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
37	InterestAndDividendIncome Interest and Dividend Income (419)			79
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Total of lines 31 thru 40)			79
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)	340
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		426
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Expenditures for Certain Civic, Political and Related Activities (426.4)
49	OtherDeductions Other Deductions (426.5)			2,934
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)	340	426	2,934
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
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)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		426	2,855
61	InterestChargesAbstract INTEREST CHARGES
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)
63	AmortizationOfDebtDiscountAndExpense Amortization of Debt Disc. and Expense (428)	258-259
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reacquired Debt (428.1)
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
68	OtherInterestExpense Other Interest Expense (431)	340
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Credit (432)
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		35,590,717	39,900,813
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)		35,590,717	39,900,813

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Statement of Accumulated Comprehensive Income and Hedging Activities
Report in columns (b) (c) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
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
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)								39,900,813
5	Balance of Account 219 at End of Preceding Quarter/Year
6	Balance of Account 219 at Beginning of Current Year
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)								35,590,717
10	Balance of Account 219 at End of Current Quarter/Year

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Statement of Retained Earnings
Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock.
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
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)
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)
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)
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)
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)
23	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
24	DividendsReceived (Less) Dividends Received (Debit)
25	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Other Changes (Explain)
25.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Other Changes (Explain)
26	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Statement of Cash Flows
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 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)	35,590,717	39,900,813
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	19,093,292	17,830,210
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of (Specify) (footnote details)	(a) 971,940	(j) 1,137,852
6	DeferredIncomeTaxesNet Deferred Income Taxes (Net)
7	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustments (Net)
8	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	(b) 195,857
9	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	(c) 116,491	(k) 115,760
10	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
11	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	1,909,974	1,514,798
12	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	(d) 2,126,277	(l) 1,755,130
13	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities
14	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction
15	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
16	OtherAdjustmentsToCashFlowsFromOperatingActivities Other Adjustments to Cash Flows from Operating Activities
16.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (footnote details):	(e) 20,137	(m) 1,016,738
18	NetCashProvidedByUsedInOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 16)	55,580,041	59,761,041
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) 574,789	(n) 599,528
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
27	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other Construction and Acquisition of Plant, Investment Activities
27.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (footnote details):	(g) 58,877
28	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 22 thru 27)	(h) 515,912	(o) 599,528
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
34	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Associated and Subsidiary Companies
36	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
38	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
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
47	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other Adjustments to Cash Flows from Investment Activities:
47.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (footnote details):
49	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 28 thru 47)	515,912	599,528
51	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
52	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
53	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Proceeds from Issuance of Long-Term Debt (b)
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):	(i) 55,064,117	(p) 59,209,368
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)	55,064,117	59,209,368
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
70	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 59 thru 69)	55,064,117	59,209,368
73	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
74	NetIncreaseDecreaseInCashAndCashEquivalents (Total of line 18, 49 and 71)	12	47,855
76	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	48,233	96,088
78	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	48,245	48,233

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

Amortization of Utility Plant $ 971,940

Total $ 971,940

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities

Original value: -195857

Original value: -116491

(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities

Original value: 2126277

(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Other, net $ 20,137

Total $ 20,137

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Original value: -574789

(g) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities

Original value: 58877

(h) Concept: CashOutflowsForPlant

Original value: -515912

(i) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

Contributions from Cheniere Partners $ 29,426,000

Distributions to Cheniere Partners (84,490,117)

Total $ (55,064,117)

(j) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

Amortization of Utility Plant $ 1,137,852

Total $ 1,137,852

(k) Concept: NetIncreaseDecreaseInInventoryOperatingActivities

Original value: 115760

(l) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities

Original value: -1755130

(m) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Account receivable from Associated Companies $ 1,850,827

Non-Cash Contribution – Income Tax 167,800

Other (1,001,889)

Total $ 1,016,738

(n) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Original value: -599528

(o) Concept: CashOutflowsForPlant

Original value: -599528

(p) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

Contributions from Cheniere Partners $ 22,533,000

Distributions to Cheniere Partners (81,742,368)

Total $ (59,209,368)

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Notes to Financial Statements

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.
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.
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.
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.
Provide a list of all environmental credits received during the reporting period.
Provide a summary of revenues and expenses for each tracked cost and special surcharge.
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.
Explain concisely any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
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.
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.
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.
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.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Creole Trail Pipeline, L.P. (“CTPL”), a Delaware limited partnership, is a Houston based partnership formed with one general partner, Cheniere Pipeline GP Interests, LLC, and one limited partner, Cheniere Energy Investments, LLC (“Cheniere Investments”), both of which are wholly owned subsidiaries of Cheniere Energy Partners, L.P. (“Cheniere Partners”). Cheniere Partners is a publicly-traded Delaware limited partnership (NYSE American: CQP) formed by Cheniere Energy, Inc. (“Cheniere”). Unless the context requires otherwise, references to “we,” “us” and “our” refer to CTPL.

We were formed to own and operate a 94-mile pipeline (the “Creole Trail Pipeline”) interconnecting the Sabine Pass liquefied natural gas (“LNG”) terminal with a number of large interstate pipelines. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“SPL”). Cheniere Partners plans to construct up to six industrial trains comprised of refrigerant compressor loops used to cool natural gas into LNG (“Trains”), which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train and run rate adjusted nominal production capacity of approximately 4.5 to 4.9 million tonnes per annum (“mtpa”) of LNG per Train. Cheniere Partners also owns and operates regasification facilities at the Sabine Pass LNG terminal through its wholly owned subsidiary, Sabine Pass LNG, L.P. (“SPLNG”), which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 billion cubic feet equivalent (“Bcfe”), two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 billion cubic feet per day (“Bcf/d”).

SPL has entered into transportation precedent and negotiated rate agreements with us to secure firm pipeline transportation capacity, which supplement enabling agreements and long-term natural gas supply contracts SPL has executed with third parties to secure natural gas feedstock for the Liquefaction Project.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying Financial Statements of CTPL have been prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission, (“FERC”), as set forth in the applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States (“GAAP”). Creole Trail’s accounting policies generally conform to the accounting and reporting guidance for regulated companies. The most significant differences between GAAP and the financial statements presented herein are: (1) classification of certain accounts on the balance sheet, statement of income and statement of cash flows and (2) certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying Financial Statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. As a result of retrospectively adopting ASU 2016-18, Statement of Cash Flows (topic 230), our Statement of Cash Flow now reconciles the balance of total cash, cash equivalents and restricted cash from the beginning of the period to the end of the period. This resulted in changes to previously reported cash flows from operating, investing and financing activities.

We have evaluated subsequent events through April 17, 2019, the date the Financial Statements were available to be issued.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the recoverability of property, plant and equipment, regulatory assets and liabilities, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value.

Revenue Recognition

We transport natural gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission (“FERC”). The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Our revenues are derived from agreements for the receipt and delivery of natural gas at points along the pipeline system as specified in each shipper’s individual transportation contract. See Note 4—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We did not have any cash and cash equivalents as of December 31, 2018 and 2017, since our operations are funded through contributions from Cheniere Partners or contractually restricted as to usage or withdrawal.

Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of both December 31, 2018 and 2017, the balance of restricted cash consisted of funds reserved for the payment of short-term operating expenses.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did not recognize any impairment expense related to accounts receivable during the years ended December 31, 2018 and 2017.

Inventory

Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost is removed from the account, and the resulting gains or losses are recorded to accumulated depreciation.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We did not recognize any impairment expense related to property, plant and equipment during the years ended December 31, 2018 and 2017.

Regulated Natural Gas Pipelines

The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.

Items that may influence our assessment are:

inability to recover cost increases due to rate caps and rate case moratoriums;
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
excess capacity;
increased competition and discounting in the markets we serve; and
impacts of ongoing regulatory initiatives in the natural gas industry.

Concentration of Credit Risk

SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which is our only customer. We are dependent on SPL’s creditworthiness and its willingness to perform under its agreements with us.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

We have not recorded an ARO associated with retirement of the Creole Trail Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Income Taxes

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as follows (in thousands):

December 31,

		2018		2017
Natural gas pipeline costs

Transmission

697,288

686,974

General Plant		2,340			2,218
Intangible Plant		14,948			14,948

Construction Work in Progress		63		86
Accumulated depreciation		(172,447)		(152,876)

Total Utility Plant, net

$ 542,192

$ 551,350

Depreciation expense during the years ended December 31, 2018 and 2017 was $19.6 million and $19.0 million, respectively.

Our natural gas pipeline cost is depreciated using the straight-line depreciation method with an estimated useful life of 40 years. Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 4—REVENUES FROM CONTRACTS WITH CUSTOMERS

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the Sabine Pass LNG terminal. These agreements have a primary term through September 2036, with the right for SPL to extend the term of the agreements for up to two consecutive ten-year terms. Thereafter, the agreements continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. SPL has continuous access to its firm transportation capacity during the contract term but has no ability to defer unused capacity to future periods. SPL pays fixed fees of approximately $82 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that SPL actually transports.

Because we are continuously available to provide transportation service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to SPL on a continuous basis over time. Because our rights to consideration correspond directly with the value of the incremental service performed, we have elected to recognize revenue when we have the right to invoice SPL for services performed to date, which results in a substantially straight-line recognition pattern over the term of the contract.

Transaction Price Allocated to Future Performance Obligations

Because our sales contract with SPL has a long-term duration, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2018 and 2017:

December 31, 2018

December 31, 2017

Unsatisfied Weighted Average Unsatisfied Weighted Average

Transaction Price Recognition Transaction Price Recognition

(in billions) Timing (years) (1) (in billions) Timing (years) (1)

Revenues—affiliate

1.4

1.5

(1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We omit from the table above all variable consideration expected to be recognized through our use of the right to invoice election.

NOTE 5—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Income for the years ended December 31, 2018 and 2017 (in thousands):

Year Ended December 31,

2018

2017

Revenues—affiliate

Transportation Agreements

81,687

81,660

Other agreements		4			102
Total revenues—affiliate		81,691			81,762

Operating and maintenance expense—affiliate

Services Agreements	9,290		9,789
Operational Balancing Agreements	(733	)	2,299
Total operating and maintenance expense—affiliate	8,557		12,088

General and administrative expense—affiliate

Services Agreements

780

1,336

We had $4.1 million and $3.9 million of advances to affiliates and $2.6 million and $4.0 million of accrued liabilities—affiliate as of December 31, 2018 and 2017, respectively, under the services agreements described below.

Services Agreements

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain the Creole Trail Pipeline. We are required to reimburse the Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments meets its obligations under the O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the O&M Agreement are required to be remitted to such subsidiary.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

Operational Balancing Agreements

We have Operational Balancing Agreements (“OBAs”) with SPLNG and SPL that provide for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for Henry Hub, Louisiana pricing published in “Gas Daily’s-Daily Price Survey” for each day of the month following termination. The SPLNG OBA became effective following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, and the SPL OBA became effective in April 2015. As of December 31, 2018 and 2017, we had $0.1 million and zero, respectively, of other current assets—affiliate and $14 thousand and $0.6 million, respectively, of other current liabilities—affiliate under the operational balancing agreements.

Transportation Agreements

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the Sabine Pass LNG terminal. See Note 4—Revenues from Contracts with Customers for information regarding these agreements. As of both December 31, 2018 and 2017, we had $6.8 million of accounts receivable—affiliate under the transportation agreement.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after May 2013.

NOTE 6—INCOME TAXES

On January 1, 2018,we prospectively adopted FERC’s Revised Policy Statement issued on March 15, 2018 along with subsequent guidance issued on July 18, 2018 and November 15, 2018. As a result, we prospectively eliminated our tax allowance and ADIT through the statement of income. Specifically, in order to eliminate the ADIT from our balance sheet effective January 1, 2018, we eliminated $32.5 million of ADIT Liabilities - Other Property (Account 282), $0.4 million of ADIT Liabilities - other (Account 283), $32.9 million of ADIT Assets (Account 190) resulting in a $131.0 million debit and corresponding credit to Provision for Deferred Income Tax (Account 410.1 and 411.1). The elimination of ADIT from our balance sheet resulted in zero impact to the income statement because we had previously established a valuation allowance to fully offset our net deferred tax assets as of December 31, 2017. We had not previously recorded any excess or deficient ADIT amounts in Accounts 182.3 or 254.

Income Tax Disclosures under FERC’s 2005 Income Tax Policy were as follows:

Income tax provision included in our reported net income consisted of the following (in thousands):


		2017
Current:

Federal

—

State		168
Total current		168


Deferred:

Federal		—
State		—
Total deferred		—

Total income tax provision

168

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:


		2017

U.S. federal statutory tax rate	35.0	%
State tax rate	7.9	%
U.S. tax reform rate change	118.0	%
Other	—	%
Valuation allowance	(160.5	)%
Effective tax rate	0.4	%

Significant components of our deferred tax assets at December 31, 2017 were as follows (in thousands):


		2017
Deferred tax assets
Net operating loss carryforward

Federal

94,748

State	36,248
Less: valuation allowance	(98,107	)
Total net deferred tax asset	32,889


Deferred tax liabilities

Property, plant and equipment	(32,529	)
Other	(360	)
Total deferred tax liabilities	(32,889	)

Net deferred tax assets

—

At December 31, 2017, we had federal and state net operating loss (“NOL”) carryforwards of approximately $451.2 million and $453.1 million, respectively. These NOL carryforwards will expire between 2022 and 2036.

Due to the uncertainty of realizing the tax benefits related to our NOL carryforwards and our other deferred tax assets, we have established a valuation allowance to fully offset our net deferred tax assets as of December 31, 2017.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21% beginning January 1, 2018. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. Specifically, we reduced our ADIT Liabilities - Other Property (Account 282) by $15.7 million, reduced our ADIT Liabilities - other (Account 283) by $0.2 million, and reduced our ADIT Assets (Account 190) by $15.9 million resulting in no impact to the current period income tax expense. The remeasurement of ADIT resulted in no impact to the income statement because we had previously established a valuation allowance to fully offset our net deferred tax assets as of December 31, 2017. We did not record any excess or deficient ADIT amounts in Accounts 182.3 or 254.

NOTE 7—LEASES

During each of the years ended December 31, 2018 and 2017, we recognized rental expense for all operating leases of $0.4 million related primarily to land sites and office space. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.

Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands):

Years Ending December 31,

Operating Leases (1)

2019

294

2020	294
2021	294
2022	320
2023	294
Thereafter	9,532

Total

11,028

Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

NOTE 8—COMMITMENTS AND CONTINGENCIES

Services Agreements

We have certain services agreements with affiliates. See Note 5—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 5—Related Party Transactions for additional information regarding this agreement.

Guarantees

Certain subsidiaries of Cheniere Partners, including us, have unconditionally guaranteed the debt obligations of Cheniere Partners. See Note 10—Guarantees for information regarding these guarantees.

Lease Commitments

We have various operating lease commitments. See Note 7—Leases for information regarding these agreements.

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of

business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2018, there were no threatened or pending legal matters that would have a material impact on our results of operations, financial position or cash flows.

NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION

In 2018, CTPL received a non-cash contribution of $10.1 million from an affiliate in the form of conveyed utility plant assets. The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $0.2 million and $0.4 million as of December 31, 2018 and 2017, respectively.

NOTE 10—GUARANTEES

We and each of Cheniere Partners’ subsidiaries other than SPL unconditionally guarantee the Cheniere Partners' Credit facilities ("CQP Facilities"). The CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the CQP Credit Facilities. The CQP Credit Facilities will mature on February 25, 2020. Additionally, Cheniere Partners’ debt obligations under the CQP Credit Facilities are secured by a first priority lien on substantially all of its assets and the assets of the CQP Guarantors, including us, except for certain excluded properties. As of December 31, 2018, only a $115 million revolving credit facility, which is currently undrawn, remained as part of the CQP credit facilities.

Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and an aggregate principal amount of $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes” and together with the 2025 CQP Senior Notes, the “CQP Senior Notes”) in September 2017 and 2018, respectively. The CQP Senior Notes are jointly and severally guaranteed by the each of Cheniere Partners’ subsidiaries other than SPL (the “CQP Guarantors”), with Sabine Pass LNG-LP, LLC subject to certain conditions that will govern its guarantee. The CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2018, we have no liability recorded related to these guarantees.

NOTE 11—REGULATORY EVENTS

Recent FERC Developments

On March 15, 2018, the FERC issued (i) a revised policy statement (the “Revised Policy Statement”) regarding the treatment of income taxes for ratemaking purposes for Master Limited Partnerships (“MLPs”), (ii) a Notice of Proposed Rulemaking (“NOPR”) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the Revised Policy Statement could have on a pipeline's return on equity assuming a single-issue adjustment to a pipeline’s rates, and (iii) a Notice of Inquiry (“NOI”) seeking comment on how the FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. On July 18, 2018, the FERC issued (1) an order dismissing rehearing requests related to the Revised Policy Statement (the “Order”) and (2) a final rule (the “Final Rule”) adopting and revising procedures from, and clarifying aspects of the NOPR. On November 15, 2018, the FERC issued a policy statement (“Excess ADIT Policy Statement”) on the accounting and ratemaking treatment of accumulated deferred income taxes and treatment following the sale or retirement of an asset addressing certain issues raised in the NOI issued March 15, 2018 (collectively, the “FERC Actions”). Each of the FERC Actions is further described below.

FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates

In its Revised 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 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.

On July 18, 2018, the FERC issued the Order dismissing the requests for rehearing and clarification of the Revised Policy Statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the Revised Policy Statement may eliminate previously ADIT from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. However, the FERC stated that the Revised Policy Statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications.

CTPL adopted the FERC Actions effective January 1, 2018 and prospectively eliminated CTPL’s tax allowance and ADIT through the statements of income. See Note 6—Income Taxes for further discussion of the impact of adoption of the FERC Actions

NOI Regarding the Effect of Tax Reform on Commission-Jurisdictional Rates

In its NOI, the FERC sought comments on the additional impacts of Tax Cuts and Jobs Act (“Tax Reform”) on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action.

As noted above, the FERC's Order dismissing requests for rehearing provided guidance that an MLP pipeline no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously ADIT from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers.

The Excess ADIT Policy Statement addressed how to disclose reversals of ADIT account balances in FERC’s annual financial report filings. The Excess ADIT Policy Statement also stated that, for those pipelines that continue to have an income tax allowance, excess/deficient ADIT associated with an asset that is sold or retired after December 31, 2017 must continue to be amortized in rates even after the sale or retirement of the asset.

Final Rule on FERC Rate Changes for Interstate Natural Gas Companies

The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantifies the isolated rate impact of Tax Reform on FERC Regulated pipelines and the impact of the revised policy statement on pipelines held by MLPs. Pipelines filing the one-time report provided four options: (1) make a limited filing under Section 4 of the Natural Gas Act to reduce rates for the impact of the Tax Reform; (2) commit to file a general Section 4 rate case in the near future; (3) file an explanation why no rate change is needed, or (4) take no further action other than filing the required Form 501-G report. On December 6, 2018, CTPL filed its respective FERC Form No. 501-G, which included explanation as to why no adjustment to pipeline rates was warranted at this time. On March 20, 2019, FERC acknowledge that CTPL had complied with the reporting requirement, and closed its FERC Form No. 501-G proceeding without taking any further action.

NOTE 12—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018:

Standard

Description

Expected Date of Adoption

Effect on our Financial Statements or Other Significant Matters

ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto

This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.

January 1, 2019

We will adopt this standard on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard will not have a material impact on our Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard.

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard

Description

Expected Date of Adoption

Effect on our Financial Statements or Other Significant Matters

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto

This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).

January 1, 2018

We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 5—Revenues from Contracts with Customers for additional disclosures.

ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)

This standard requires an entity to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.

December 31, 2018

As a result of adopting this standard, our Statements of Cash Flows now reconciles the balance of total cash, cash equivalents and restricted cash from the beginning of the period to the end of the period. This resulted in changes to previously reported cash flows from operating, investing and financing activities.

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Plant in Service (Accounts 101, 102, 103, and 106)
Report below the original cost of gas plant in service according to the prescribed accounts. In addition to Account 101, Gas Plant in Service (Classified), this page and the next include Account 102, Gas Plant Purchased or Sold, Account 103, Experimental Gas Plant Unclassified, and Account 106, Completed Construction Not Classified-Gas. Include in column (c) and (d), as appropriate corrections of additions and retirements for the current or preceding year. Enclose in parenthesis credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c).Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year's unclassified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Account 101 and 106 will avoid serious omissions of respondent's reported amount for plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the zmounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirements of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give date of such filing.
Line No.	Account (a)	Balance at Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	IntangiblePlantAbstract INTANGIBLE PLANT
2	OrganizationAbstract 301 Organization
3	FranchiseAndConsentsAbstract 302 Franchise and Consents
4	MiscellaneousIntangiblePlantAbstract 303 MiscellaneousIntangiblePlant	14,947,879					14,947,879
5	IntangiblePlantRollforwardAbstract Total Intangible Plant (Total of lines 2 thru 4)	14,947,879					14,947,879
6	ProductionPlantAbstract PRODUCTION PLANT
7	NaturalGasProductionPlantAbstract Natural Gas Production and Gathering Plant
8	ProducingLandsRollforwardAbstract 325.1 Producing Lands
9	ProducingLeaseholdsRollforwardAbstract 325.2 Producing Leaseholds
10	GasRightsRollforwardAbstract 325.3 Gas Rights
11	RightsOfWayNaturalGasProductionAndGatheringPlantRollforwardAbstract 325.4 RIghts-of-Way
12	OtherLandAndLandRightsRollforwardAbstract 325.5 Other Land and Land Rights
13	GasWellStructuresRollforwardAbstract 326 Gas Well Structures
14	FieldCompressorStationStructuresRollforwardAbstract 327 Field Compressor Station Structures
15	FieldMeasuringAndRegulatingStationStructuresRollforwardAbstract 328 Field Measuring and Regulating Station Structures
16	OtherStructuresRollforwardAbstract 329 Other Structures
17	ProducingGasWellsWellConstructionRollforwardAbstract 330 Producing Gas Wells-Well Construction
18	ProducingGasWellsWellEquipmentRollforwardAbstract 331 Producing Gas Wells-Well Equipment
19	FieldLinesRollforwardAbstract 332 Field Lines
20	FieldCompressorStationEquipmentRollforwardAbstract 333 Field Compressor Station Equipment
21	FieldMeasuringAndRegulatingStationEquipmentRollforwardAbstract 334 Field Measuring and Regulating Station Equipment
22	DrillingAndCleaningEquipmentRollforwardAbstract 335 Drilling and Cleaning Equipment
23	PurificationEquipmentNaturalGasProductionPlantRollforwardAbstract 336 Purification Equipment
24	OtherEquipmentNaturalGasProductionAndGatheringPlantRollforwardAbstract 337 Other Equipment
25	UnsuccessfulExplorationAndDevelopmentCostsRollforwardAbstract 338 Unsuccessful Exploration and Development Costs
26	AssetRetirementCostsForNaturalGasProductionAndGatheringPlantRollforwardAbstract 339 Asset Retirement Costs for Natural Gas Production and Gathering Plant
27	NaturalGasProductionAndGatheringPlantAbstract Total Production and Gathering Plant (Total of lines 8 thru 26)
28	ProductsExtractionPlantAbstract PRODUCTS EXTRACTION PLANT
29	LandAndLandRightsProductsExtractionPlantRollforwardAbstract 340 Land and Land Rights
30	StructuresAndImprovementsProductsExtractionPlantRollforwardAbstract 341 Structures and Improvements
31	ExtractionAndRefiningEquipmentRollforwardAbstract 342 Extraction and Refining Equipment
32	PipeLinesRollforwardAbstract 343 Pipe Lines
33	ExtractedProductStorageEquipmentRollforwardAbstract 344 Extracted Products Storage Equipment
34	CompressorEquipmentProductsExtractionPlantRollforwardAbstract 345 Compressor Equipment
35	GasMeasuringAndRegulatingEquipmentRollforwardAbstract 346 Gas Measuring and Regulating Equipment
36	OtherEquipmentProductsExtractionPlantRollforwardAbstract 347 Other equipment
37	AssetRetirementCostsForProductsExtractionPlantRollforwardAbstract 348 Asset Retirement Costs for Products Extraction Plant
38	ProductsExtractionPlantRollforwardAbstract Total Products Extraction Plant (Total of lines 29 thru 37)
39	NaturalGasProductionPlantRollforwardAbstract Total Natural Gas Production Plant (Total of lines 27 and 38)
40	ManufacturedGasProductionPlantAbstract Manufactured Gas Production Plant (Submit supplementary information in a footnote)
41	NaturalGasProductionPlantAndManufacturedGasProductionPlantRollforwardAbstract Total Production Plant (Total of lines 39 and 40)
42	NaturalGasStorageAndProcessingPlantAbstract NATURAL GAS STORAGE AND PROCESSING PLANT
43	UndergroundStoragePlantAbstract Underground storage plant
44	LandRollforwardAbstract 350.1 Land
45	RightsOfWayNaturalGasStorageAndProcessingPlantRollforwardAbstract 350.2 Rights-of-Way
46	StructuresAndImprovementsUndergroundStoragePlantRollforwardAbstract 351 Structures and Improvements
47	WellsRollforwardAbstract 352 Wells
48	StorageLeaseholdsAndRightsRollforwardAbstract 352.1 Storage Leaseholds and Rights
49	ReservoirsRollforwardAbstract 352.2 Reservoirs
50	NonrecoverableNaturalGasRollforwardAbstract 352.3 Non-recoverable Natural Gas
51	LinesRollforwardAbstract 353 Lines
52	CompressorStationEquipmentUndergroundStoragePlantRollforwardAbstract 354 Compressor Station Equipment
53	MeasuringAndRegulatingEquipmentUndergroundStoragePlantRollforwardAbstract 355 Measuring and Regulating Equipment
54	PurificationEquipmentUndergroundStoragePlantRollforwardAbstract 356 Purification Equipment
55	OtherEquipmentUndergroundStoragePlantRollforwardAbstract 357 Other Equipment
56	AssetRetirementCostsForUndergroundStoragePlantRollforwardAbstract 358 Asset Retirement Costs for Underground Storage Plant
57	UndergroundStoragePlantRollforwardAbstract Total Underground Storage Plant (Total of lines 44 thru 56)
58	OtherStoragePlantAbstract Other Storage Plant
59	LandAndLandRightsOtherStoragePlantRollforwardAbstract 360 Land and Land Rights
60	StructuresAndImprovementsOtherStoragePlantRollforwardAbstract 361 Structures and Improvements
61	GasHoldersRollforwardAbstract 362 Gas Holders
62	PurificationEquipmentOtherStoragePlantRollforwardAbstract 363 Purification Equipment
63	LiquefactionEquipmentRollforwardAbstract 363.1 Liquefaction Equipment
64	VaporizingEquipmentRollforwardAbstract 363.2 Vaporizing Equipment
65	CompressorEquipmentOtherStoragePlantRollforwardAbstract 363.3 Compressor Equipment
66	MeasuringAndRegulatingEquipmentOtherStoragePlantRollforwardAbstract 363.4 Measuring and Regulating Equipment
67	OtherEquipmentOtherStoragePlantRollforwardAbstract 363.5 Other Equipment
68	AssetRetirementCostsForOtherStoragePlantRollforwardAbstract 363.6 Asset Retirement Costs for Other Storage Plant
69	OtherStoragePlantRollforwardAbstract Total Other Storage Plant (Total of lines 58 thru 68)
70	BaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantAbstract Base Load Liquefied Natural Gas Terminaling and Processing Plant
71	LandAndLandRightsBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.1 Land and Land Rights
72	StructuresAndImprovementsBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.2 Structures and Improvements
73	LngProcessingTerminalEquipmentRollforwardAbstract 364.3 LNG Processing Terminal Equipment
74	LngTransportationEquipmentRollforwardAbstract 364.4 LNG Transportation Equipment
75	MeasuringAndRegulatingEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.5 Measuring and Regulating Equipment
76	CompressorStationEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.6 Compressor Station Equipment
77	CommunicationEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.7 Communications Equipment
78	OtherEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.8 Other Equipment
79	AssetRetirementCostsForBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract 364.9 Asset Retirement Costs for Base Load Liquefied Natural Gas
80	BaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract Total Base Load Liquified Natural Gas , Terminating and Processing Plant (Total of lines 71 thru 79)
81	NaturalGasStorageAndProcessingPlantRollforwardAbstract Total Nat'l Gas Storage and Processing Plant (Total of lines 57, 69, and 80)
82	TransmissionPlantAbstract TRANSMISSION PLAN
83	LandAndLandRightsGasTransmissionPlantRollforwardAbstract 365.1 Land and Land Rights	500,000					500,000
84	RightsOfWayGasTransmissionPlantRollforwardAbstract 365.2 Rights-of-Way	27,234,730					27,234,730
85	StructuresAndImprovementsGasTransmissionPlantRollforwardAbstract 366 Structures and Improvements	1,808,544	85,964				1,894,508
86	MainsGasTransmissionPlantRollforwardAbstract 367 Mains	502,711,579			14,288		502,697,291
87	CompressorStationEquipmentGasTransmissionPlantRollforwardAbstract 368 Compressor Station Equipment	107,323,072	998				107,324,070
88	MeasuringAndRegulatingStationEquipmentRollforwardAbstract 369 Measuring and Regulating Station Equipment	47,201,342	10,130,234	66,707			57,264,869
89	CommunicationEquipmentTransmissionRollforwardAbstract 370 Communication Equipment	180,603					180,603
90	OtherEquipmentGasTransmissionPlantRollforwardAbstract 371 Other Equipment	13,977	178,077				192,054
91	AssetRetirementCostsForTransmissionPlantTransmissionPlantRollforwardAbstract 372 Asset Retirement Costs for Transmission Plant
92	TransmissionPlantRollforwardAbstract Total Transmission Plant (Total of line 81 thru 91)	686,973,847	10,395,273	66,707	14,288		697,288,125
93	DistributionPlantAbstract DISTRIBUTION PLANT
94	LandAndLandRightsGasDistributionPlantRollforwardAbstract 374 Land and Land Rights
95	StructuresAndImprovementsGasDistributionPlantRollforwardAbstract 375 Structures and Improvements
96	MainsGasDistributionPlantRollforwardAbstract 376 Mains
97	CompressorStationEquipmentGasDistributionPlantRollforwardAbstract 377 Compressor Station Equipment
98	MeasuringAndRegulatingStationEquipmentGeneralRollforwardAbstract 378 Measuring and Regulating Station Equipment-General
99	MeasuringAndRegulatingStationEquipmentCityGateCheckStationsRollforwardAbstract 379 Measuring and Regulating Station Equipment-City Gate
100	ServicesRollforwardAbstract 380 Services
101	MetersRollforwardAbstract 381 Meters
102	MeterInstallationsRollforwardAbstract 382 Meter Installations
103	HouseRegulatorsRollforwardAbstract 383 House Regulators
104	HouseRegulatoryInstallationsRollforwardAbstract 384 House Regulator Installations
105	IndustrialMeasuringAndRegulatingStationEquipmentRollforwardAbstract 385 Industrial Measuring and Regulating Station Equipment
106	OtherPropertyOnCustomersPremisesRollforwardAbstract 386 Other Property on Customers' Premises
107	OtherEquipmentGasDistributionPlantRollforwardAbstract 387 Other Equipment
108	AssetRetirementCostsForDistributionPlantDistributionPlantRollforwardAbstract 388 Asset Retirement Costs for Distribution Plant
109	DistributionPlantRollforwardAbstract Total Distribution Plant (Total of lines 94 thru 108)
110	GeneralPlantAbstract GENERAL PLANT
111	LandAndLandRightsRollforwardAbstract 389 Land and Land Rights
112	StructuresAndImprovementsRollforwardAbstract 390 Structures and Improvements
113	OfficeFurnitureAndEquipmentRollforwardAbstract 391 Office Furniture and Equipment	596,415		3,152			593,263
114	TransportationEquipmentRollforwardAbstract 392 Transportation Equipment	274,294	93,196		1		367,491
115	StoresEquipmentRollforwardAbstract 393 Stores Equipment
116	ToolsShopAndGarageEquipmentRollforwardAbstract 394 Tools, Shop, and Garage Equipment	1,243,784	112,198	79,801			1,276,181
117	LaboratoryEquipmentRollforwardAbstract 395 Laboratory Equipment
118	PowerOperatedEquipmentRollforwardAbstract 396 Power Operated Equipment	15,115					15,115
119	CommunicationEquipmentRollforwardAbstract 397 Communication Equipment	48,935					48,935
120	MiscellaneousEquipmentRollforwardAbstract 398 Miscellaneous Equipment	39,003		1			39,002
121	GeneralPlantExcludingOtherTangiblePropertyAndAssetRetirementCostsForGeneralPlantRollforwardAbstract Subtotal (Total of lines 111 thru 120)	2,217,546	205,394	82,954	1		2,339,987
122	OtherTangiblePropertyRollforwardAbstract 399 Other Tangible Property
123	AssetRetirementCostsForGeneralPlantGeneralPlantRollforwardAbstract 399.1 Asset Retirement Costs for General Plant
124	GeneralPlantRollforwardAbstract Total General Plant (Total of lines 121, 122, and 123)	2,217,546	205,394	82,954	1		2,339,987
125	GasPlantInServiceAndCompletedConstructionNotClassifiedGasRollforwardAbstract Total (Accounts 101 and 106)	704,139,272	10,600,667	149,661	14,287		714,575,991
126	GasPlantPurchasedRollforwardAbstract Gas Plant Purchased (See Instruction 8)
127	GasPlantSoldRollforwardAbstract (Less) Gas Plant Sold (See Instruction 8)
128	ExperimentalGasPlantUnclassifiedRollforwardAbstract Experimental gas plant unclassified
129	GasPlantInServiceRollforwardAbstract Total Gas Plant In Service (Total of lines 125 thru 128)	704,139,272	10,600,667	149,661	14,287		714,575,991

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

General Information on Plant and Operations
In the space below provide a brief description of the plant and operations of the respondent. State the name and location of the fields in which the respondent operates, the number of acres of operated gas lands, number of gas wells, miles of gathering lines, miles of transmission lines, number and capacity of compressor stations, and other information which will give a general idea of the size and nature of the facilities operated by the respondent in the production, gathering, transmission and storage of natural gas. Provide details covering any important changes in the scope of respondent's operations during the report year.

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Property and Capacity Leased from Others
Report below the information called for concerning gas property and capacity leased from others for gas operations. For all leases in which the average annual lease payment over the initial term of the lease exceeds $500,000, describe in column (c), if applicable: the property or capacity leased. Designate associated companies with an asterisk in column (b).
Line No.	LessorName Name of Lessor (a)	IndicationOfAssociatedCompany * (b)	LeaseDescription Description of Lease (c)	GasPropertyAndCapacityLeasePayment Lease Payments for Current Year (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45	Total

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Property and Capacity Leased to Others
For all leases in which the average lease income over the initial term of the lease exceeds $500,000 provide in column (c), a description of each facility or leased capacity that is classified as gas plant in service, and is leased to others for gas operations. In column (d) provide the lease payments received from others. Designate associated companies with an asterisk in column (b).
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (b)	LeaseDescription Description of Lease (c)	ProceedsFromGasPropertyAndCapacityLeasePayment Lease Payments for Current Year (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45	Total

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Non-Traditional Rate Treatment Afforded New Projects
The Commission’s Certificate Policy Statement provides a threshold requirement for existing pipelines proposing new projects is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers. See Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC P61,227 (1999); order clarifying policy, 90 FERC P61,128 (2000); order clarifying policy, 92 FERC P61,094 (2000) (Policy Statement). In column a, list the name of the facility granted non-traditional rate treatment. In column b, list the CP Docket Number where the Commission authorized the facility. In column c, indicate the type of rate treatment approved by the Commission (e.g. incremental, at risk) In column d, list the amount in Account 101, Gas Plant in Service, associated with the facility. In column e, list the amount in Account 108, Accumulated Provision for Depreciation of Gas Utility Plant, associated with the facility. In column f, list the amount in Account 190, Accumulated Deferred Income Tax; Account 281, Accumulated Deferred Income Taxes – Accelerated Amortization Property; Account 282, Accumulated Deferred Income Taxes – Other Property; Account 283, Accumulated Deferred Income Taxes – Other, associated with the facility. In column g, report the total amount included in the gas operations expense accounts during the year related to the facility (Account 401, Operation Expense). In column h, report the total amount included in the gas maintenance expense accounts during the year related to the facility. In column i, report the amount of depreciation expense accrued on the facility during the year. In column j, list any other expenses(including taxes) allocated to the facility. In column k, report the incremental revenues associated with the facility. Identify the volumes received and used for any incremental project that has a separate fuel rate for that project. Provide the total amounts for each column.
Line No.	LocationOrNameOfFacility Name of Facility (a)	CPDocketNumber CP Docket No. (b)	TypeOfRateTreatment Type of Rate Treatment (c)	GasPlantInServiceNonTraditionalRateTreatmentAffordedNewProjects Gas Plant in Service (d)	AccumulatedProvisionForDepreciationOfGasUtilityPlantNonTraditionalRateTreatmentAffordedNewProjects Accumulated Depreciation (e)	AccumulatedDeferredIncomeTaxesNonTraditionalRateTreatmentAffordedNewProjects Accumulated Deferred Income Taxes (f)	OperationExpenseNonTraditionalRateTreatmentAffordedNewProjects Operating Expense (g)	MaintenanceExpenseNonTraditionalRateTreatmentAffordedNewProjects Maintenance Expense (h)	DepreciationExpenseNonTraditionalRateTreatmentAffordedNewProjects Depreciation Expense (i)	OtherExpensesIncludingTaxesNonTraditionalRateTreatmentAffordedNewProjects Other Expenses (including taxes) (j)	IncrementalRevenuesNonTraditionalRateTreatmentAffordedNewProjects Incremental Revenues (k)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37	Gas Plant In Service

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Accumulated Provision for Depreciation of Gas Utility Plant (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, line 10, column (c), and that reported for gas plant in service, page 204-209, column (d), excluding retirements of nondepreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting. At lines 7 and 14, add rows as necessary to report all data. Additional rows should be numbered in sequence, e.g., 7.01, 7.02, etc.
Line No.	Item (a)	Total (c+d+e) (b)	Gas Plant in Service (c)	Gas Plant held for Future Use (d)	Gas Plant Leased to Others (e)
	Section A. BALANCES AND CHANGES DURING YEAR
1	Balance Beginning of Year	145,955,284	145,955,284
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	19,093,292	19,093,292
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs
5	ExpensesOfGasPlantLeasedToOthers (413) Expense of Gas Plant Leased to Others
6	TransportationExpensesClearing Transportation Expenses - Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Clearing (Specify) (footnote details):
9.1
10	DepreciationProvision TOTAL Deprec. Prov. for Year (Total of lines 3 thru 8)	19,093,292	19,093,292
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	(a) 90,069	(c) 90,069
13	CostOfRemovalOfPlant Cost of Removal
14	SalvageValueOfRetiredPlant Salvage (Credit)
15	NetChargesForRetiredPlant TOTAL Net Chrgs for Plant Ret. (Total of lines 12 thru 14)	(b) 90,069	(d) 90,069
16	Other Debit or Credit Items (Describe in footnote details)
17.1
18	Book Cost of Asset Retirement Costs
19	Balance End of Year (Total of lines 1,10,15,16 and 18)	164,958,507	164,958,507
	Section B. BALANCES AT END OF YEAR ACCORDING TO FUNCTIONAL CLASSIFICATIONS
21	AccumulatedDepreciationProductionsManufacturedGas Productions-Manufactured Gas
22	AccumulatedDepreciationProductionAndGatheringNaturalGas Production and Gathering-Natural Gas
23	AccumulatedDepreciationProductsExtractionNaturalGas Products Extraction-Natural Gas
24	AccumulatedDepreciationUndergroundGasStorage Underground Gas Storage
25	AccumulatedDepreciationOtherStorage Other Storage Plant
26	AccumulatedDepreciationBaseLoadLngTerminalingAndProcessingPlant Base Load LNG Terminaling and Processing Plant
27	AccumulatedDepreciationTransmission Transmission	162,835,537	162,835,537
28	AccumulatedDepreciationDistribution Distribution
29	AccumulatedDepreciationGeneral General	2,122,970	2,122,970
30	AccumulatedProvisionForDepreciationOfGasUtilityPlant TOTAL (Total of lines 21 thru 29)	164,958,507	164,958,507

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: BookCostOfRetiredPlant

Original value: -90069

(b) Concept: NetChargesForRetiredPlant

Original value: -90069

(d) Concept: NetChargesForRetiredPlant

Original value: -90069

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Other Regulatory Assets (Account 182.3)
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). For regulatory assets being amortized, show period of amortization in column (b). 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. Report separately any "Deferred Regulatory Commission Expenses" that are also reported on pages 350-351, Regulatory Commission Expenses. 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	(a) Deferred Fuel Account			3,125,345	1,999,917	407.3	4,126,194		999,068
40	TOTAL			3,125,345	1,999,917		4,126,194		999,068

FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 6.15 of the General Terms and Conditions of Creole Trail's FERC Gas Tarriff, First Revised Volumne No. 1

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Accumulated Deferred Income Taxes (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Changes During Year Amounts Debited to Account 410.1 (c)	Changes During Year, Amounts Credited to Account 411.1 (d)	Changes During Year Amounts Debited to Account 410.2 (e)	Changes During Year Amounts Credited to Account 411.2 (f)	Adjustments Debits Account No. (g)	Adjustments Debits Amount (h)	Adjustments Credits Account No. (i)	Adjustments Credits Amount (j)	Balance at End of Year (k)
1	Account 190
2	Electric
3	Gas	32,889,400	32,889,400
4	Other (Define)
5	Total (Total of lines 2 thru 4)	32,889,400	32,889,400
6	Other (Specify)
7	TOTAL Account 190 (Total of lines 5 thru 6)	32,889,400	32,889,400
8	Classification of TOTAL
9	Federal Income Tax	23,816,464	23,816,464
10	State Income Tax	9,072,937	9,072,937
11	Local Income Tax

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

CAPITAL STOCK DATA
Report below the details called for concerning common stock and long-term debt. The total amount outstanding reflected in column (f) for Capital Stock Data refers to total amount outstanding without reduction for amounts held by respondent.
Line No.	Class and Series of Stock (a)	Number of Shares Authorized (b)	Par Value Per Share of Par Value Stock (c)	Stated Value Per Share of Nonpar Stock (d)	Outstanding Per Balance Sheet, Share (e)	Outstanding Per Balance Sheet, Amount (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15


LONG-TERM DEBT
Line No.	Class and Series of Obligation (a)	Nominal Date of Issue (b)	Date of Maturity (c)	Outstanding Per Balance Sheet (d)	Interest for Year % Rate (e)	Interest for Year Amount (f)
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
	TOTAL

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes). Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b) amounts credited to the portion of prepaid taxes charged to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a footnote. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Show in columns (l) thru (s) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant, show the number of the appropriate balance sheet plant account or subaccount. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. Items under $250,000 may be grouped. Report in column (t) the applicable effective state income tax rate.
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction Tax Jurisdiction (c)	TaxYear Tax Year (d)	TaxesAccrued Balance at Beg. of Year Taxes Accrued (e)	PrepaidTaxes Balance at Beg. of Year Prepaid Taxes (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Balance at End of Year Taxes Accrued (Account 236) (j)	PrepaidTaxes Balance at End of Year Prepaid Taxes (Included in Acct 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	TaxesAccruedPrepaidAndCharged Gas (Account 408.1, 409.1) (m)	TaxesAccruedPrepaidAndCharged Other Utility Dept. (Account 408.1, 409.1) (n)	OtherIncomeAndDeductions Other Income and Deductions (Account 408.2, 409.2) (o)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (p)	OtherUtilityOperatingIncomeAssociatedWithTaxesOtherThanIncomeTaxes Other Utility Opn. Income (Account 408.1, 409.1) (q)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (r)	TaxesIncurredOther Other (s)	StateLocalIncomeTaxRate State/Local Income Tax Rate (t)
1	Ad Valorem
2	Louisiana						10,042,572	10,042,572					10,042,572
3	Total Ad Valorem Tax						10,042,572	10,042,572					10,042,572
4	Franchise
5	Delaware						300	300					300
6	Total Franchise Tax						300	300					300
7	Federal
8	FICA/Medicare						128,609	128,609					128,609
9	Unemployment						603	603					603
10	Penalty
11	Total Federal						129,212	129,212					129,212
12	State Unemployment
13	Texas						269	269					269
14	Louisiana						1,278	1,278					1,278
15	Total State Unemployment						1,547	1,547					1,547
16	Sales Use Tax
17	Louisiana				491,785		15,439	8,714		498,510			1,843						219,930
18	Texas						1,690	1,690											6,443
19	Total				491,785		17,129	10,404		498,510			1,843						(a) 226,373
40	Total				491,785		10,190,760	10,184,035		498,510			10,175,474						226,373

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: TaxesIncurredOther

Sales Use Tax - charged to FERC Accounts 107 CWIP, 101 Utility Plant, 154 Plant Materials and Operating Supplies or FERC Operations and Maintenance Expenses (401/402).

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Accumulated Deferred Income Taxes-Other Property (Account 282)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to property not subject to accelerated amortization. At Other (Specify), include deferrals relating to other income and deductions. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Changes During Year Amounts Debited to Account 410.1 (c)	Changes During Year Amounts Credited to Account 411.1 (d)	Changes During Year Amounts Debited to Account 410.2 (e)	Changes During Year Amounts Credited to Account 411.2 (f)	Adjustments Debits Account No. (g)	Adjustments Debits Amount (h)	Adjustments Credits Account No. (i)	Adjustments Credits Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric
3	Gas	32,529,278	32,529,278
4	Other (Define)
5	Total (Total of lines 2 thru 4)	32,529,278	32,529,278
6	Other (Specify)
7	TOTAL Account 282 (Total of lines 5 thru 6)	(a) 32,529,278	32,529,278
8	Classification of TOTAL
9	Federal Income Tax	23,555,685	23,555,685
10	State Income Tax	8,973,593	8,973,593
11	Local Income Tax

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

Duplicate fact discrepancy. Schedule: 274 - Schedule - Accumulated Deferred Income Taxes - Other Property (Account 282) - Classified by Business Activities, Row: 7, Column: b, Value: -32529278

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Accumulated Deferred Income Taxes-Other (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. At Other (Specify), include deferrals relating to other income and deductions. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Changes During Year Amounts Debited to Account 410.1 (c)	Changes During Year Amounts Credited to Account 411.1 (d)	Changes During Year Amounts Debited to Account 410.2 (e)	Changes During Year Amounts Credited to Account 411.2 (f)	Adjustments Debits Account No. (g)	Adjustments Debits Amount (h)	Adjustments Credits Account No. (i)	Adjustments Credits Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Gas	360,122	360,122
4	Other (Define)
5	Total (Total of lines 2 thru 4)	360,122	360,122
6	Other (Specify)
7	TOTAL Account 283 (Total of lines 5 thru 6)	(a) 360,122	360,122
8	Classification of TOTAL
9	Federal Income Tax	260,778	260,778
10	State Income Tax	99,344	99,344
11	Local Income Tax

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

Duplicate fact discrepancy. Schedule: 276 - Schedule - Accumulated Deferred Income Taxes - Other (Account 283) - Classified by Business Activities, Row: 7, Column: b, Value: -360122

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Other Regulatory Liabilities (Account 254)
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). For regulatory liabilities being amortized, show period of amortization in column (a). 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. 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 Fuel Account
45	Total

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Operating Revenues
Report below natural gas operating revenues for each prescribed account total. The amounts must be consistent with the detailed data on succeeding pages. Revenues in columns (b) and (c) include transition costs from upstream pipelines. Other Revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns (b) through (e). Include in columns (f) and (g) revenues for Accounts 480-495. If increases or decreases from previous year are not derived from previously reported figures, explain any inconsistencies in a footnote. On Page 108, include information on major changes during the year, new service, and important rate increases or decreases. Report the revenue from transportation services that are bundled with storage services as transportation service revenue.
Line No.	Title of Account (a)	Revenues for Transition Costs and Take-or-Pay Amount for Current Year (b)	Revenues for Transaction Costs and Take-or-Pay Amount for Previous Year (c)	Revenues for GRI and ACA Amount for Current Year (d)	Revenues for GRI and ACA Amount for Previous Year (e)	Other Revenues Amount for Current Year (f)	Other Revenues Amount for Previous Year (g)	Total Operating Revenues Amount for Current Year (h)	Total Operating Revenues Amount for Previous Year (i)	Dekatherm of Natural Gas Amount for Current Year (j)	Dekatherm of Natural Gas Amount for Previous Year (k)
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	IntracompanyTransfersAbstract (485) Intracompany Transfers
7	ForfeitedDiscountsAbstract (487) Forfeited Discounts
8	MiscellaneousServiceRevenuesAbstract (488) Miscellaneous Service Revenues
9	RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilitiesAbstract (489.1) Revenues from Transportation of Gas of Others Through Gathering Facilities
10	RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract (489.2) Revenues from Transportation of Gas of Others Through Transmission Facilities			563,169	509,869	81,124,286	81,149,904	81,687,455	81,659,773	433,207,088	364,191,972
11	RevenuesFromTransportationOfGasOfOthersThroughDistributionFacilitiesAbstract (489.3) Revenues from Transportation of Gas of Others Through Distribution Facilities
12	RevenuesFromStoringGasOfOthersAbstract (489.4) Revenues from Storing Gas of Others
13	SalesOfProductsExtractedFromNaturalGasAbstract (490) Sales of Prod. Ext. from Natural Gas
14	RevenuesFromNaturalGasProcessedByOthersAbstract (491) Revenues from Natural Gas Proc. by Others
15	IncidentalGasolineAndOilSalesAbstract (492) Incidental Gasoline and Oil Sales
16	RentFromGasPropertyAbstract (493) Rent from Gas Property
17	InterdepartmentalRentsAbstract (494) Interdepartmental Rents					3,128		3,128
18	OtherGasRevenuesAbstract (495) Other Gas Revenues						102,092		102,092
19	OperatingRevenuesBeforeProvisionForRateRefundsAbstract Subtotal:			563,169	509,869	81,127,414	81,251,996	81,690,583	81,761,865
20	ProvisionForRateRefundsAbstract (496) (Less) Provision for Rate Refunds
21	OperatingRevenuesAbstract TOTAL			563,169	509,869	81,127,414	81,251,996	81,690,583	81,761,865

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Other Gas Revenues (Account 495)
Report below transactions of $250,000 or more included in Account 495, Other Gas Revenues. Group all transactions below $250,000 in one amount and provide the number of items.
Line No.	Description of Transaction (a)	Amount (in dollars) (b)
1	CommissionsOnSaleOrDistributionOfGasOfOthers Commissions on Sale or Distribution of Gas of Others
2	CompensationForMinorOrIncidentalServicesProvidedForOthers Compensation for Minor or Incidental Services Provided for Others
3	ProfitOrLossOnSaleOfMaterialAndSuppliesNotOrdinarilyPurchasedForResale Profit or Loss on Sale of Material and Supplies not Ordinarily Purchased for Resale
4	SalesOfStreamWaterOrElectricityIncludingSalesOrTransfersToOtherDepartments Sales of Stream, Water, or Electricity, including Sales or Transfers to Other Departments
5	MiscellaneousRoyalties Miscellaneous Royalties
6	RevenuesFromDehydrationAndOtherProcessingOfGasOfOthers Revenues from Dehydration and Other Processing of Gas of Others except as provided for in the Instructions to Account 495
7	RevenuesForRightBenefitsReceivedFromOthersWhichAreRealizedThroughResearchDevelopmentAndDemonstrationVentures Revenues for Right and/or Benefits Received from Others which are Realized Through Research, Development, and Demonstration Ventures
8	GainsOnSettlementsOfImbalanceReceivablesAndPayables Gains on Settlements of Imbalance Receivables and Payables
9	RevenuesFromPenaltiesEarnedPursuantToTariffProvisionsIncludingPenaltiesAssociatedWithCashOutSettlements Revenues from Penalties earned Pursuant to Tariff Provisions, including Penalties Associated with Cash-out Settlements
10	RevenuesFromShipperSuppliedGas Revenues from Shipper Supplied Gas
11	Other revenues (Specify):
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40	TOTAL

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Discounted Rate Services and Negotiated Rate Services
In column b, report the revenues from discounted rate services. In column c, report the volumes of discounted rate services. In column d, report the revenues from negotiated rate services. In column e, report the volumes of negotiated rate services.
Line No.	AccountDescription Account (a)	RevenueFromDiscountedRateServices Discounted Rate Services Revenue (b)	VolumesOfDiscountedRateServices Discounted Rate Services Volumes (c)	RevenuesFromNegotiatedRateServices Negotiated Rate Services Revenue (d)	VolumesOfNegotiatedRateServices Negotiated Rate Services Volumes (e)
1	Account 489.1, Revenues from transportation of gas of others through gathering facilities.
2	Account 489.2, Revenues from transportation of gas of others through transmission facilities.			81,687,455	433,207,088
3	Account 489.4, Revenues from storing gas of others.
4	Account 495, Other gas revenues.			3,128
40	Total			81,690,583	433,207,088

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Operation and Maintenance Expenses
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c)
1	ProductionExpensesAbstract 1. PRODUCTION EXPENSES
2	ManufacturedGasProductionAbstract A. Manufactured Gas Production
3	ManufacturedGasProduction Manufactured Gas Production (Submit Supplemental Statement)
4	NaturalGasProductionExpensesAbstract B. Natural Gas Production
5	NaturalGasProductionAndGatheringPlantAbstract B1. Natural Gas Production and Gathering
6	NaturalGasProductionAndGatheringOperationAbstract Operation
7	OperationSupervisionAndEngineeringNaturalGasProductionAndGathering 750 Operation Supervision and Engineering
8	ProductionMapsAndRecords 751 Production Maps and Records
9	GasWellsExpenses 752 Gas Well Expenses
10	FieldLinesExpenses 753 Field Lines Expenses
11	FieldCompressorStationExpenses 754 Field Compressor Station Expenses
12	FieldCompressorStationFuelAndPower 755 Field Compressor Station Fuel and Power
13	FieldMeasuringAndRegulatingStationExpenses 756 Field Measuring and Regulating Station Expenses
14	PurificationExpensesNaturalGasProductionAndGathering 757 Purification Expenses
15	GasWellRoyalties 758 Gas Well Royalties
16	OtherExpensesNaturalGasProductionAndGathering 759 Other Expenses
17	RentsNaturalGasProductionAndGathering 760 Rents
18	ProductionOperationExpense TOTAL Operation (Total of lines 7 thru 17)
19	NaturalGasProductionAndGatheringMaintenanceAbstract Maintenance
20	MaintenanceSupervisionAndEngineeringNaturalGasProductionAndGathering 761 Maintenance Supervision and Engineering
21	MaintenanceOfStructuresAndImprovementsNaturalGasProductionAndGathering 762 Maintenance of Structures and Improvements
22	MaintenanceOfProducingGasWells 763 Maintenance of Producing Gas Wells
23	MaintenanceOfFieldLines 764 Maintenance of Field Lines
24	MaintenanceOfFieldCompressorStationEquipment 765 Maintenance of Field Compressor Station Equipment
25	MaintenanceOfFieldMeasuringAndRegulatingStationEquipment 766 Maintenance of Field Measuring and Regulating Station Equipment
26	MaintenanceOfPurificationEquipment 767 Maintenance of Purification Equipment
27	MaintenanceOfDrillingAndCleaningEquipment 768 Maintenance of Drilling and Cleaning Equipment
28	MaintenanceOfOtherEquipmentNaturalGasProductionAndGathering 769 Maintenance of Other Equipment
29	ProductionMaintenanceExpense TOTAL Maintenance (Total of lines 20 thru 28)
30	ProductionOperationAndMaintenanceExpense TOTAL Natural Gas Production and Gathering (Total of lines 18 and 29)
31	ProductsExtractionAbstract B2. Products Extraction
32	NaturalGasProductionExtractionOperationAbstract Operation
33	OperationSupervisionAndEngineeringProductsExtraction 770 Operation Supervision and Engineering
34	OperationLaborNaturalGasProduction 771 Operation Labor
35	GasShrinkage 772 Gas Shrinkage
36	Fuel 773 Fuel
37	Power 774 Power
38	Materials 775 Materials
39	OperationSuppliesAndExpenses 776 Operation Supplies and Expenses
40	GasProcessedByOthers 777 Gas Processed by Others
41	RoyaltiesOnProductsExtracted 778 Royalties on Products Extracted
42	MarketingExpenses 779 Marketing Expenses
43	ProductsPurchasedForResale 780 Products Purchased for Resale
44	VariationInProductsInventory 781 Variation in Products Inventory
45	ExtractedProductsUsedByTheUtilityCredit (Less) 782 Extracted Products Used by the Utility-Credit
46	RentsProductsExtraction 783 Rents
47	ProductsExtractionOperationExpense TOTAL Operation (Total of lines 33 thru 46)
48	NaturalGasProductionExtractionMaintenanceAbstract Maintenance
49	MaintenanceSupervisionAndEngineeringProductsExtraction 784 Maintenance Supervision and Engineering
50	MaintenanceOfStructuresAndImprovementsProductsExtraction 785 Maintenance of Structures and Improvements
51	MaintenanceOfExtractionAndRefiningEquipment 786 Maintenance of Extraction and Refining Equipment
52	MaintenanceOfPipeLines 787 Maintenance of Pipe Lines
53	MaintenanceOfExtractedProductsStorageEquipment 788 Maintenance of Extracted Products Storage Equipment
54	MaintenanceOfCompressorEquipment 789 Maintenance of Compressor Equipment
55	MaintenanceOfGasMeasuringAndRegulatingEquipment 790 Maintenance of Gas Measuring and Regulating Equipment
56	MaintenanceOfOtherEquipmentProductsExtraction 791 Maintenance of Other Equipment
57	ProductsExtractionMaintenanceExpense TOTAL Maintenance (Total of lines 49 thru 56)
58	ProductsExtractionExpense TOTAL Products Extraction (Total of lines 47 and 57)
59	ExplorationAndDevelopmentExpensesAbstract C. Exploration and Development
60	ExplorationAndDevelopmentOperationAbstract Operation
61	DelayRentals 795 Delay Rentals
62	NonproductiveWellDrilling 796 Nonproductive Well Drilling
63	AbandonedLeases 797 Abandoned Leases
64	OtherExploration 798 Other Exploration
65	ExplorationAndDevelopmentOperatingExpense TOTAL Exploration and Development (Total of lines 61 thru 64)
66	OtherGasSupplyExpensesAbstract D. Other Gas Supply Expenses
67	OtherGasSupplyExpensesOperationAbstract Operation
68	NaturalGasWellHeadPurchases 800 Natural Gas Well Head Purchases
69	NaturalGasWellHeadPurchasesIntracompanyTransfers 800.1 Natural Gas Well Head Purchases, Intracompany Transfers
70	NaturalGasFieldLinePurchases 801 Natural Gas Field Line Purchases
71	NaturalGasGasolinePlantOutletPurchases 802 Natural Gas Gasoline Plant Outlet Purchases
72	NaturalGasTransmissionLinePurchases 803 Natural Gas Transmission Line Purchases
73	NaturalGasCityGatePurchases 804 Natural Gas City Gate Purchases
74	LiquefiedNaturalGasPurchases 804.1 Liquefied Natural Gas Purchases
75	OtherGasPurchases 805 Other Gas Purchases
76	PurchasedGasCostAdjustments (Less) 805.1 Purchases Gas Cost Adjustments
77	PurchasedGasOperationExpenses TOTAL Purchased Gas (Total of lines 68 thru 76)
78	ExchangeGas 806 Exchange Gas	512,316	1,826,493
79	PurchasedGasExpensesAbstract Purchased Gas Expenses
80	WellExpensePurchasedGas 807.1 Well Expense-Purchased Gas
81	OperationOfPurchasedGasMeasuringStations 807.2 Operation of Purchased Gas Measuring Stations
82	MaintenanceOfPurchasedGasMeasuringStations 807.3 Maintenance of Purchased Gas Measuring Stations
83	PurchasedGasCalculationsExpenses 807.4 Purchased Gas Calculations Expenses
84	OtherPurchasedGasExpenses 807.5 Other Purchased Gas Expenses
85	PurchasedGasExpenses TOTAL Purchased Gas Expenses (Total of lines 80 thru 84)
86	GasWithdrawnFromStorageDebt 808.1 Gas Withdrawn from Storage-Debit	155,461	758,043
87	GasDeliveredToStorageCredit (Less) 808.2 Gas Delivered to Storage-Credit	126,143	782,497
88	WithdrawalsOfLiquefiedNaturalGasHeldForProcessingDebit 809.1 Withdrawals of Liquefied Natural Gas for Processing-Debit
89	DeliveriesOfNaturalGasForProcessingCredit (Less) 809.2 Deliveries of Natural Gas for Processing-Credit
90	GasUsedInUtilityOperationAbstract Gas used in Utility Operation-Credit
91	GasUsedForCompressorStationFuelCredit 810 Gas Used for Compressor Station Fuel-Credit	8,299,107	6,446,186
92	GasUsedForProductsExtractionCredit 811 Gas Used for Products Extraction-Credit
93	GasUsedForOtherUtilityOperationsCredit 812 Gas Used for Other Utility Operations-Credit	1,341,731	5,259,218
94	GasUsedInUtilityOperationCredit TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 thru 93)	9,640,838	11,705,404
95	OtherGasSupplyExpenses 813 Other Gas Supply Expenses	1,466,285	5,229,114
96	OtherGasSupplyExpensesOperation TOTAL Other Gas Supply Exp. (Total of lines 77,78,85,86 thru 89,94,95)	8,657,551	4,674,251
97	ProductionExpenses TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96)	8,657,551	4,674,251
98	NaturalGasStorageTerminalingAndProcessingExpensesAbstract 2. NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES
99	UndergroundStorageExpensesAbstract A. Underground Storage Expenses
100	UndergroundStorageEpensesOperationAbstract Operation
101	OperationSupervisionAndEngineeringUndergroundStorageExpenses 814 Operation Supervision and Engineering
102	MapsAndRecords 815 Maps and Records
103	WellsExpenses 816 Wells Expenses
104	LinesExpenses 817 Lines Expense
105	CompressorStationExpenses 818 Compressor Station Expenses
106	CompressorStationFuelAndPowerUndergroundStorageExpenses 819 Compressor Station Fuel and Power
107	MeasuringAndRegulatingStationExpenses 820 Measuring and Regulating Station Expenses
108	PurificationExpensesUndergroundStorage 821 Purification Expenses
109	ExplorationAndDevelopment 822 Exploration and Development
110	GasLossesUndergroundStorageExpenses 823 Gas Losses
111	OtherExpensesUndergroundStorage 824 Other Expenses
112	StorageWellRoyalties 825 Storage Well Royalties
113	RentsUndergroundStorageExpenses 826 Rents
114	UndergroundStorageOperationExpenses TOTAL Operation (Total of lines of 101 thru 113)
115	UndergroundStorageEpensesMaintenanceAbstract Maintenance
116	MaintenanceSupervisionAndEngineeringUndergroundStorageExpenses 830 Maintenance Supervision and Engineering
117	MaintenanceOfStructuresAndImprovementsUndergroundStorageExpenses 831 Maintenance of Structures and Improvements
118	MaintenanceOfReservoirsAndWells 832 Maintenance of Reservoirs and Wells
119	MaintenanceOfLines 833 Maintenance of Lines
120	MaintenanceOfCompressorStationEquipmentUndergroundStorageExpenses 834 Maintenance of Compressor Station Equipment
121	MaintenanceOfMeasuringAndRegulatingStationEquipmentUndergroundStorageExpenses 835 Maintenance of Measuring and Regulating Station Equipment
122	MaintenanceOfPurificationEquipmentUndergroundStorageExpenses 836 Maintenance of Purification Equipment
123	MaintenanceOfOtherEquipmentUndergroundStorageExpenses 837 Maintenance of Other Equipment
124	UndergroundStorageMaintenanceExpenses TOTAL Maintenance (Total of lines 116 thru 123)
125	UndergroundStorageExpenses TOTAL Underground Storage Expenses (Total of lines 114 and 124)
126	OtherStorageExpensesAbstract B. Other Storage Expenses
127	OtherStorageExpensesOperationAbstract Operation
128	OperationSupervisionAndEngineeringOtherStorageExpenses 840 Operation Supervision and Engineering
129	OperationLaborAndExpenses 841 Operation Labor and Expenses
130	RentsOtherStorageExpenses 842 Rents
131	FuelOtherStorageExpenses 842.1 Fuel
132	PowerOtherStorageExpenses 842.2 Power
133	GasLossesOtherStorageExpenses 842.3 Gas Losses
134	OtherStorageOperationExpenses TOTAL Operation (Total of lines 128 thru 133)
135	OtherStorageExpensesMaintenanceAbstract Maintenance
136	MaintenanceSupervisionAndEngineeringOtherStorageExpenses 843.1 Maintenance Supervision and Engineering
137	MaintenanceOfStructuresAndImprovementsOtherStorageExpenses 843.2 Maintenance of Structures
138	MaintenanceOfGasHolders 843.3 Maintenance of Gas Holders
139	MaintenanceOfPurificationEquipmentOtherStorageExpenses 843.4 Maintenance of Purification Equipment
140	MaintenanceOfLiquefactionEquipmentOtherStorageExpenses 843.5 Maintenance of Liquefaction Equipment
141	MaintenanceOfVaporizingEquipmentOtherStorageExpenses 843.6 Maintenance of Vaporizing Equipment
142	MaintenanceOfCompressorEquipmentOtherStorageExpenses 843.7 Maintenance of Compressor Equipment
143	MaintenanceOfMeasuringAndRegulatingEquipmentOtherStorageExpenses 843.8 Maintenance of Measuring and Regulating Equipment
144	MaintenanceOfOtherEquipmentOtherStorageExpenses 843.9 Maintenance of Other Equipment
145	OtherStorageMaintenanceExpenses TOTAL Maintenance (Total of lines 136 thru 144)
146	OtherStorageExpenses TOTAL Other Storage Expenses (Total of lines 134 and 145)
147	LiquifiedNaturalGasTerminalingAndProcessingExpensesAbstract C. Liquefied Natural Gas Terminaling and Processing Expenses
148	LiquefiedNaturalGasTerminalingAndProcessingExpensesOperationAbstract Operation
149	OperationSupervisionAndEngineeringLiquefiedNaturalGasTerminalingAndProcessingExpenses 844.1 Operation Supervision and Engineering
150	LngProcessingTerminalLaborAndExpenses 844.2 LNG Processing Terminal Labor and Expenses
151	LiquefactionProcessingLaborAndExpenses 844.3 Liquefaction Processing Labor and Expenses
152	LngTransportationLaborAndExpenses 844.4 Liquefaction Transportation Labor and Expenses
153	MeasuringAndRegulatingLaborAndExpenses 844.5 Measuring and Regulating Labor and Expenses
154	CompressorStationLaborAndExpensesLiquefiedNaturalGasTerminalingAndProcessingExpenses 844.6 Compressor Station Labor and Expenses
155	CommunicationSystemExpensesLiquefiedNaturalGasTerminalingAndProcessingExpenses 844.7 Communication System Expenses
156	SystemControlAndLoadDispatchingLiquefiedNaturalGasTerminalingAndProcessingExpenses 844.8 System Control and Load Dispatching
157	FuelLiquefiedNaturalGasTerminalingAndProcessingExpenses 845.1 Fuel
158	PowerLiquefiedNaturalGasTerminalingAndProcessingExpenses 845.2 Power
159	RentsLiquefiedNaturalGasTerminalingAndProcessing 845.3 Rents
160	DemurrageChargesLiquefiedNaturalGasTerminalingAndProcessingExpenses 845.4 Demurrage Charges
161	WharfageReceiptsCreditLiquefiedNaturalGasTerminalingAndProcessingExpenses (less) 845.5 Wharfage Receipts-Credit
162	ProcessingLiquefiedOrVaporizedGasByOthers 845.6 Processing Liquefied or Vaporized Gas by Others
163	GasLossesLiquefiedNaturalGasTerminalingAndProcessingExpenses 846.1 Gas Losses
164	OtherExpensesLiquefiedNaturalGasTerminalingAndProcessing 846.2 Other Expenses
165	LiquifiedNaturalGasTerminalingAndProcessingOperationExpenses TOTAL Operation (Total of lines 149 thru 164)
166	LiquefiedNaturalGasTerminalingAndProcessingExpensesMaintenanceAbstract Maintenance
167	MaintenanceSupervisionAndEngineeringLiquefiedNaturalGasTerminalingAndProcessingExpenses 847.1 Maintenance Supervision and Engineering
168	MaintenanceOfStructuresAndImprovementsLiquefiedNaturalGasTerminalingAndProcessingExpenses 847.2 Maintenance of Structures and Improvements
169	MaintenanceOfLngProcessingTerminalEquipment 847.3 Maintenance of LNG Processing Terminal Equipment
170	MaintenanceOfLngTransportationEquipment 847.4 Maintenance of LNG Transportation Equipment
171	MaintenanceOfMeasuringAndRegulatingEquipment 847.5 Maintenance of Measuring and Regulating Equipment
172	MaintenanceOfCompressorStationEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses 847.6 Maintenance of Compressor Station Equipment
173	MaintenanceOfCommunicationEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses 847.7 Maintenance of Communication Equipment
174	MaintenanceOfOtherEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses 847.8 Maintenance of Other Equipment
175	LiquifiedNaturalGasTerminalingAndProcessingMaintenanceExpenses TOTAL Maintenance (Total of lines 167 thru 174)
176	LiquifiedNaturalGasTerminalingAndProcessingExpenses TOTAL Liquefied Nat Gas Terminaling and Proc Exp (Total of lines 165 and 175)
177	NaturalGasStorageExpense TOTAL Natural Gas Storage (Total of lines 125, 146, and 176)
178	TransmissionExpensesAbstract 3. TRANSMISSION EXPENSES
179	TransmissionExpensesOperationAbstract Operation
180	OperationSupervisionAndEngineeringGasTransmissionExpenses 850 Operation Supervision and Engineering	5,829,593	5,286,841
181	SystemControlAndLoadDispatchingGas 851 System Control and Load Dispatching	1,220,020	1,522,423
182	CommunicationSystemExpenses 852 Communication System Expenses	141,706	137,505
183	CompressorStationLaborAndExpensesTransmissionExpenses 853 Compressor Station Labor and Expenses	2,044,426	2,386,278
184	GasForCompressorStationFuel 854 Gas for Compressor Station Fuel	8,299,107	6,446,835
185	OtherFuelAndPowerForCompressorStations 855 Other Fuel and Power for Compressor Stations
186	MainsExpenses 856 Mains Expenses	2,007,106	2,031,263
187	MeasuringAndRegulatingStationExpensesTransmissionExpenses 857 Measuring and Regulating Station Expenses	937,056	1,016,497
188	TransmissionAndCompressionOfGasByOthers 858 Transmission and Compression of Gas by Others
189	OtherExpensesGasTransmission 859 Other Expenses	87,100	242,298
190	RentsGasTransmissionExpense 860 Rents	362,546	389,237
191	TransmissionOperationExpense TOTAL Operation (Total of lines 180 thru 190)	20,928,660	19,459,177
192	TransmissionExpensesMaintenanceAbstract Maintenance
193	MaintenanceSupervisionAndEngineeringGasTransmissionExpenses 861 Maintenance Supervision and Engineering	104,635	100,492
194	MaintenanceOfStructuresAndImprovementsTransmissionExpenses 862 Maintenance of Structures and Improvements	126,075	104,460
195	MaintenanceOfMainsTransmissionExpenses 863 Maintenance of Mains	126,080	128,683
196	MaintenanceOfCompressorStationEquipmentTransmissionExpenses 864 Maintenance of Compressor Station Equipment	590,309	374,470
197	MaintenanceOfMeasuringAndRegulatingStationEquipment 865 Maintenance of Measuring and Regulating Station Equipment	28,583	33,661
198	MaintenanceOfCommunicationEquipmentGasTransmission 866 Maintenance of Communication Equipment	27,607	6,062
199	MaintenanceOfOtherEquipmentTransmissionExpenses 867 Maintenance of Other Equipment	9,658	28,924
200	TransmissionMaintenanceExpensesGas TOTAL Maintenance (Total of lines 193 thru 199)	1,012,947	776,752
201	TransmissionExpenses TOTAL Transmission Expenses (Total of lines 191 and 200)	21,941,607	20,235,929
202	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
203	DistributionExpensesOperationAbstract Operation
204	OperationSupervisionAndEngineeringDistributionExpenses 870 Operation Supervision and Engineering
205	DistributionLoadDispatching 871 Distribution Load Dispatching
206	CompressorStationLaborAndExpenses 872 Compressor Station Labor and Expenses
207	CompressorStationFuelAndPowerDistributionExpenses 873 Compressor Station Fuel and Power
208	MainsAndServicesExpenses 874 Mains and Services Expenses
209	MeasuringAndRegulatingStationExpensesGeneral 875 Measuring and Regulating Station Expenses-General
210	MeasuringAndRegulatingStationExpensesIndustrial 876 Measuring and Regulating Station Expenses-Industrial
211	MeasuringAndRegulatingStationExpensesCityGateCheckStations 877 Measuring and Regulating Station Expenses-City Gas Check Station
212	MeterAndHouseRegulatorExpenses 878 Meter and House Regulator Expenses
213	CustomerInstallationsExpenses 879 Customer Installations Expenses
214	OtherExpensesGasDistribution 880 Other Expenses
215	RentsDistributionExpense 881 Rents
216	DistributionOperationExpensesGas TOTAL Operation (Total of lines 204 thru 215)
217	DistributionExpensesMaintenanceAbstract Maintenance
218	MaintenanceSupervisionAndEngineeringDistributionExpenses 885 Maintenance Supervision and Engineering
219	MaintenanceOfStructuresAndImprovementsDistributionExpenses 886 Maintenance of Structures and Improvements
220	MaintenanceOfMains 887 Maintenance of Mains
221	MaintenanceOfCompressorStationEquipment 888 Maintenance of Compressor Station Equipment
222	MaintenanceOfMeasuringAndRegulatingStationEquipmentGeneral 889 Maintenance of Measuring and Regulating Station Equipment-General
223	MaintenanceOfMeasuringAndRegulatingStationEquipmentIndustrial 890 Maintenance of Meas. and Reg. Station Equipment-Industrial
224	MaintenanceOfMeasuringAndRegulatingStationEquipmentCityGateCheckStations 891 Maintenance of Meas. and Reg. Station Equip-City Gate Check Station
225	MaintenanceOfServices 892 Maintenance of Services
226	MaintenanceOfMetersAndHouseRegulators 893 Maintenance of Meters and House Regulators
227	MaintenanceOfOtherEquipmentGasDistribution 894 Maintenance of Other Equipment
228	DistributionMaintenanceExpenseGas TOTAL Maintenance (Total of lines 218 thru 227)
229	DistributionExpenses TOTAL Distribution Expenses (Total of lines 216 and 228)
230	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
231	CustomerAccountsExpensesOperationsAbstract Operation
232	SupervisionCustomerAccountExpenses 901 Supervision
233	MeterReadingExpenses 902 Meter Reading Expenses
234	CustomerRecordsAndCollectionExpenses 903 Customer Records and Collection Expenses
235	UncollectibleAccounts 904 Uncollectible Accounts
236	MiscellaneousCustomerAccountsExpenses 905 Miscellaneous Customer Accounts Expenses
237	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Total of lines 232 thru 236)
238	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
239	CustomerServiceAndInformationalExpensesOperationAbstract Operation
240	SupervisionCustomerServiceAndInformationExpenses 907 Supervision
241	CustomerAssistanceExpenses 908 Customer Assistance Expenses
242	InformationalAndInstructionalAdvertisingExpenses 909 Informational and Instructional Expenses
243	MiscellaneousCustomerServiceAndInformationalExpenses 910 Miscellaneous Customer Service and Informational Expenses
244	CustomerServiceAndInformationalExpenses TOTAL Customer Service and Information Expenses (Total of lines 240 thru 243)
245	SalesExpensesAbstract 7. SALES EXPENSES
246	SalesExpenseOperationAbstract Operation
247	SupervisionSalesExpense 911 Supervision
248	DemonstratingAndSellingExpenses 912 Demonstrating and Selling Expenses
249	AdvertisingExpenses 913 Advertising Expenses
250	MiscellaneousSalesExpenses 916 Miscellaneous Sales Expenses
251	SalesExpenses TOTAL Sales Expenses (Total of lines 247 thru 250)
252	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
253	AdministrativeAndGeneralExpensesOperationAbstract Operation
254	AdministrativeAndGeneralSalaries 920 Administrative and General Salaries	515,063	1,029,280
255	OfficeSuppliesAndExpenses 921 Office Supplies and Expenses	23,015	258,677
256	AdministrativeExpensesTransferredCredit (Less) 922 Administrative Expenses Transferred-Credit
257	OutsideServicesEmployed 923 Outside Services Employed	585,666	309,643
258	PropertyInsurance 924 Property Insurance	952,182	903,797
259	InjuriesAndDamages 925 Injuries and Damages	155,061	188,741
260	EmployeePensionsAndBenefits 926 Employee Pensions and Benefits	357,975	400,804
261	FranchiseRequirements 927 Franchise Requirements
262	RegulatoryCommissionExpenses 928 Regulatory Commission Expenses	233,882	44,765
263	DuplicateChargesCredit (Less) 929 Duplicate Charges-Credit
264	GeneralAdvertisingExpenses 930.1General Advertising Expenses		537
265	MiscellaneousGeneralExpenses 930.2Miscellaneous General Expenses	25,557	47
266	RentsAdministrativeAndGeneralExpense 931 Rents
267	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 254 thru 266)	2,848,401	3,136,291
268	MaintenanceAbstract Maintenance
269	MaintenanceOfGeneralPlant 932 Maintenance of General Plant
270	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 267 and 269)	2,848,401	3,136,291
271	OperationsAndMaintenanceExpensesGas TOTAL Gas O&M Expenses (Total of lines 97,177,201,229,237,244,251, and 270)	16,132,457	18,697,969

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Employee Pensions and Benefits (Account 926)
Report below the items contained in Account 926, Employee Pensions and Benefits.
Line No.	Expense (a)	Amount (in dollars) (b)
1	Pensions - defined benefit plans
2	Pensions - other
3	Post-retirement benefits other than pensions (PBOP)
4	Post-employment benefit plans
5	Other (Specify)
6	Medical, Dental and Vision Plans	244,630
7	Long Term Disability, Accidental Death & Dismemberment	10,925
8	401(K)	102,420
40	Total	357,975

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Charges for Outside Professional and Other Consultative Services
Report the information specified below for all charges made during the year included in any account (including plant accounts) for outside consultative and other professional services. These services include rate, management, construction, engineering, research, financial, valuation, legal, accounting, purchasing, advertising,labor relations, and public relations, rendered for the respondent under written or oral arrangement, for which aggregate payments were made during the year to any corporation partnership, organization of any kind, or individual (other than for services as an employee or for payments made for medical and related services) amounting to more than $250,000, including payments for legislative services, except those which should be reported in Account 426.4 Expenditures for Certain Civic, Political and Related Activities. (a) Name of person or organization rendering services. (b) Total charges for the year. Sum under a description “Other”, all of the aforementioned services amounting to $250,000 or less. Total under a description “Total”, the total of all of the aforementioned services. Charges for outside professional and other consultative services provided by associated (affiliated) companies should be excluded from this schedule and be reported on Page 358, according to the instructions for that schedule.
Line No.	NameOfPersonOrOrganizationRenderingProfessionalOrConsultativeServices Description (a)	ChargesForOutsideProfessionalAndOtherConsultativeServices Amount (in dollars) (b)
1	SOLAR TURBINES INC	464,797
2	DAVIES CONSTRUCTION INC	336,692
3	OTHER	2,481,209
4	Total	3,282,698
5	TOTAL

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Transactions with Associated (Affiliated) Companies
Report below the information called for concerning all goods or services received from or provided to associated (affiliated) companies amounting to more than $250,000. Sum under a description “Other”, all of the aforementioned goods and services amounting to $250,000 or less. Total under a description “Total”, the total of all of the aforementioned goods and services. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote the basis of the allocation.
Line No.	DescriptionOfTheGoodOrService Description of the Good or Service (a)	NameOfAssociatedAffiliatedCompany Name of Associated/Affiliated Company (b)	AccountsChargedOrCreditedTransactionsWithAssociatedAffiliatedCompanies Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Goods or Services Provided by Affiliated Company
2	Direct Charge, Labor, Benefits & Taxes	Cheniere LNG O&M Services, LLC	various	8,808,600
3	Direct Charge, Labor, Benefits & Taxes	Cheniere Energy Shared Services, Inc	various	444,716
4	Direct Charge, Labor, Benefits & Taxes	Cheniere Energy Investments, LLC		1,013,160
5	Total			10,266,476
19	TOTAL
20	Goods or Services Provided for Affiliated Company
21	Natural Gas Transporation Services	Sabine Pass Liquefaction, LLC	489.2	81,687,455
22	Total			81,687,455
40	TOTAL

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Gas Account - Natural Gas
The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent. Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas. Enter in column (c) the year to date Dth as reported in the schedules indicated for the items of receipts and deliveries. Enter in column (d) the respective quarter’s Dth as reported in the schedules indicated for the items of receipts and deliveries. Indicate in a footnote the quantities of bundled sales and transportation gas and specify the line on which such quantities are listed. If the respondent operates two or more systems which are not interconnected, submit separate pages for this purpose. 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. Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes reported on line No. 3 relate. 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. 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		Cheniere Creole Trail Pipeline, L.P.
2	QuantityOfNaturalGasReceivedByUtilityAbstract GAS RECEIVED
3	QuantityOfNaturalGasReceivedByUtilityGasPurchases Gas Purchases (Accounts 800-805)
4	QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForGathering Gas of Others Received for Gathering (Account 489.1)	303
5	QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForTransmission Gas of Others Received for Transmission (Account 489.2)	305	433,207,088	117,418,896
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
8	QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForProductionExtractionProcessing Gas of Others Received for Production/Extraction/Processing (Account 490 and 491)
9	QuantityOfNaturalGasReceivedByUtilityExchangedGasReceivedFromOthers Exchanged Gas Received from Others (Account 806)	328	3,944,430	2,204,319
10	QuantityOfNaturalGasReceivedByUtilityGasReceivedAsImbalances Gas Received as Imbalances (Account 806)	328
11	QuantityOfNaturalGasReceivedByUtilityReceiptsOfUtilitysGasTransportedByOthers Receipts of Respondent's Gas Transported by Others (Account 858)	332
12	QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage Other Gas Withdrawn from Storage (Explain)
13	QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsCompressorStationFuel Gas Received from Shippers as Compressor Station Fuel
14	QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor Gas Received from Shippers as Lost and Unaccounted for		3,933,841	1,066,236
15	QuantityOfNaturalGasReceivedByUtilityOther Other Receipts (Specify) (footnote details)		(a) 51,452
16	QuantityOfNaturalGasReceivedByUtility Total Receipts (Total of lines 3 thru 15)		441,136,811	120,689,451
17	QuantityOfNaturalGasDeliveredByUtilityAbstract GAS DELIVERED
18	QuantityOfNaturalGasDeliveredByUtilityGasSales Gas Sales (Accounts 480-484)
19	QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasGatheredForOthers Deliveries of Gas Gathered for Others (Account 489.1)	303
20	QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasTransportedForOthers Deliveries of Gas Transported for Others (Account 489.2)	305	433,207,088	117,418,896
21	QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasDistributedForOthers Deliveries of Gas Distributed for Others (Account 489.3)	301
22	QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfContractStorageGas Deliveries of Contract Storage Gas (Account 489.4)	307
23	QuantityOfNaturalGasDeliveredByUtilityGasOfOthersDeliveredForProductionExtractionProcessing Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491)
24	QuantityOfNaturalGasDeliveredByUtilityExchangeGasDeliveredToOthers Exchange Gas Delivered to Others (Account 806)	328	4,047,596	2,280,818
25	QuantityOfNaturalGasDeliveredByUtilityGasDeliveredAsImbalances Gas Delivered as Imbalances (Account 806)	328
26	QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasToOthersForTransportation Deliveries of Gas to Others for Transportation (Account 858)	332
27	QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage Other Gas Delivered to Storage (Explain)
28	QuantityOfNaturalGasDeliveredByUtilityGasUsedForCompressorStationFuel Gas Used for Compressor Station Fuel	509	2,642,276	727,089
29	GasUsedForOtherDeliveriesAndGasUsedForOtherOperations Other Deliveries and Gas Used for Other Operations		48,140	30,182
30	QuantityOfNaturalGasDeliveredByUtility Total Deliveries (Total of lines 18 thru 29)		439,945,100	120,456,985
31	GasLossesAndGasUnaccountedForGasAccountAbstract GAS LOSSES AND GAS UNACCOUNTED FOR
32	GasAccountGasLossesAndGasUnaccountedForGasAccount Gas Losses and Gas Unaccounted For		1,191,711	232,466
33	DeliveriesGasLossesAndUnaccountedForGasAccountAbstract TOTALS
34	DeliveriesGasLossesAndUnaccountedForGasAccount Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32)		441,136,811	120,689,451

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

FOOTNOTE DATA

(a) Concept: QuantityOfNaturalGasReceivedByUtilityOther

Linepack receipts

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Shipper Supplied Gas for the Current Quarter
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. 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). 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). Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h). Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement. 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. 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). 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). On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput. 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		334,587		334,587		1,081,051		1,081,051					805	805
5	Distribution
6	Storage
7	Total Shipper Supplied Gas		334,587		334,587		1,081,051		1,081,051
	LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9	Gathering
10	Production/Extraction/Processing
11	Transmission		223,932		223,932		723,524		723,524					854	810
12	Distribution
13	Storage
14	Total gas used in compressors		223,932		223,932		723,524		723,524
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		1,096		1,096		3,541		3,541					856	812
19	Distribution
20	Storage
21	Other Deliveries (specify) (footnote details)
22	Total Gas Used For Other Deliveries And Gas Used For Other Operations		1,096		1,096		3,541		3,541
23	LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24	Gathering
25	Production/Extraction/Processing
26	Transmission		26,028		26,028		84,096		84,096					813	812
27	Distribution
28	Storage
29	Other Deliveries (specify) (footnote details)
30	Total Gas Lost And Unaccounted For		26,028		26,028		84,096		84,096
30.1	NET EXCESS OR (DEFICIENCY)
31	Other Losses
32	Gathering
33	Production/Extraction/Processing
34	Transmission		83,531		83,531		269,889		269,889					4073	1823
35	Distribution
36	Storage
37	Total Net Excess Or (Deficiency)		83,531		83,531		269,889		269,889
38	DISPOSITION OF EXCESS GAS:
39	Gas sold to others
40	Gas used to meet imbalances		70,340		70,340		227,269		227,269					174	806
41	Gas added to system gas		13,191		13,191		42,620		42,620					1174	813
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		83,531		83,531		269,889		269,889
52	GAS ACQUIRED TO MEET DEFICIENCY:
53	System gas
54	Purchased gas
65	Total Gas Acquired To Meet Deficiency

SEPARATION OF FORWARDHAUL AND BACKHAUL THROUGHPUT
Line No.	Item (a)	Quarter Dth (b)
66	Forwardhaul Volume in Dths for the Quarter	117,418,896
67	Backhaul Volume in Dths for the Quarter
68	TOTAL (Lines 66 and 67)	117,418,896

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Shipper Supplied Gas for the Current Quarter
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. 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). 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). Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h). Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement. 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. 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). 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). On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput. 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		351,867		351,867		1,429,636		1,429,636					805	805
5	Distribution
6	Storage
7	Total Shipper Supplied Gas		351,867		351,867		1,429,636		1,429,636
8	LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9	Gathering
10	Production/Extraction/Processing
11	Transmission		247,425		247,425		1,005,288		1,005,288					854	810
12	Distribution
13	Storage
14	Total gas used in compressors		247,425		247,425		1,005,288		1,005,288
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		317		317		1,288		1,288					856	812
19	Distribution
20	Storage
21	Other Deliveries (specify) (footnote details)
22	Total Gas Used For Other Deliveries And Gas Used For Other Operations		317		317		1,288		1,288
23	LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24	Gathering
25	Production/Extraction/Processing
26	Transmission		125,047		125,047		508,066		508,066					813	812
27	Distribution
28	Storage
29	Other Deliveries (specify) (footnote details)
30	Total Gas Lost And Unaccounted For		125,047		125,047		508,066		508,066
30.1	NET EXCESS OR (DEFICIENCY)
31	Other Losses
32	Gathering
33	Production/Extraction/Processing
34	Transmission		20,922		20,922		85,006		85,006					1823	4074
35	Distribution
36	Storage
37	Total Net Excess Or (Deficiency)		20,922		20,922		85,006		85,006
38	DISPOSITION OF EXCESS GAS:
39	Gas sold to others
40	Gas used to meet imbalances
41	Gas added to system gas		1,593		1,593		6,472		6,472					1174	813
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		1,593		1,593		6,472		6,472
52	GAS ACQUIRED TO MEET DEFICIENCY:
53	System gas
54	Purchased gas
55.1	Gas used to meet Imbalances		22,515		22,515		91,478		91,478					806	242
65	Total Gas Acquired To Meet Deficiency		22,515		22,515		91,478		91,478

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

Shipper Supplied Gas for the Current Quarter
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. 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). 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). Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h). Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement. 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. 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). 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). On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput. 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		379,782		379,782		1,494,442		1,494,442					805	805
5	Distribution
6	Storage
7	Total Shipper Supplied Gas		379,782		379,782		1,494,442		1,494,442
8	LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9	Gathering
10	Production/Extraction/Processing
11	Transmission		255,732		255,732		1,006,305		1,006,305					854	810
12	Distribution
13	Storage
14	Total gas used in compressors		255,732		255,732		1,006,305		1,006,305
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		670		670		2,636		2,636					856	812
19	Distribution
20	Storage
21	Other Deliveries (specify) (footnote details)
22	Total Gas Used For Other Deliveries And Gas Used For Other Operations		670		670		2,636		2,636
23	LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24	Gathering
25	Production/Extraction/Processing
26	Transmission		81,391		81,391		320,274		320,274					813	812
27	Distribution
28	Storage
29	Other Deliveries (specify) (footnote details)
30	Total Gas Lost And Unaccounted For		81,391		81,391		320,274		320,274
30.1	NET EXCESS OR (DEFICIENCY)
31	Other Losses
32	Gathering
33	Production/Extraction/Processing
34	Transmission		41,989		41,989		165,227		165,227					4073	1823
35	Distribution
36	Storage
37	Total Net Excess Or (Deficiency)		41,989		41,989		165,227		165,227
38	DISPOSITION OF EXCESS GAS:
39	Gas sold to others
40	Gas used to meet imbalances		28,674		28,674		112,832		112,832					174	806
41	Gas added to system gas		13,315		13,315		52,395		52,395					1174	813
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		41,989		41,989		165,227		165,227
52	GAS ACQUIRED TO MEET DEFICIENCY:
53	System gas
54	Purchased gas
65	Total Gas Acquired To Meet Deficiency

Name of Respondent:

Cheniere Creole Trail Pipeline, L.P.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2019

Year/Period of Report:

End of:

2018

System Maps

Furnish five copies of a system map (one with each filed copy of this report) of the facilities operated by the respondent for the production, gathering, transportation, and sale of natural gas. New maps need not be furnished if no important change has occurred in the facilities operated by the respondent since the date of the maps furnished with a previous year's annual report. If, however, maps are not furnished for this reason, reference should be made in the space below to the year's annual report with which the maps were furnished.
Indicate the following information on the maps: (a) Transmission lines. (b) Incremental facilities. (c) Location of gathering areas. (d) Location of zones and rate areas. (e) Location of storage fields. (f) Location of natural gas fields. (g) Location of compressor stations. (h) Normal direction of gas flow (indicated by arrows). (i) Size of pipe. (j) Location of products extraction plants, stabilization plants, purification plants, recycling areas, etc. (k) Principal communities receiving service through the respondent's pipeline.
In addition, show on each map: graphic scale of the map; date of the facts the map purports to show; a legend giving all symbols and abbreviations used; designations of facilities leased to or from another company, giving name of such other company.
Maps not larger than 24 inches square are desired. If necessary, however, submit larger maps to show essential information. Fold the maps to a size not larger then this report. Bind the maps to the report.

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

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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit:

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

General Penalties

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