Document

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.

10-K 1 spl2018form10-k.htm 10-K Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 333-192373

Sabine Pass Liquefaction, LLC

(Exact name of registrant as specified in its charter)



Delaware	27-3235920
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 1900
Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (713) 375-5000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

The registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x

Note: As of January 1, 2018, the registrant is a voluntary filer not subject to the filing requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Act.



Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable

Documents incorporated by reference: None

SABINE PASS LIQUEFACTION, LLC

TABLE OF CONTENTS



PART I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	9
Item 1B. Unresolved Staff Comments	19
Item 3. Legal Proceedings	19
Item 4. Mine Safety Disclosure	20
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	21
Item 6. Selected Financial Data	21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	32
Item 8. Financial Statements and Supplementary Data	33
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	61
Item 9A. Controls and Procedures	61
Item 9B. Other Information	61
PART III
Item 10. Directors, Executive Officers and Company Governance	62
Item 11. Executive Compensation	62
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	62
Item 13. Certain Relationships and Related Transactions, and Manager Independence	62
Item 14. Principal Accountant Fees and Services	62
PART IV
Item 15. Exhibits and Financial Statement Schedules	63
Item 16. Form 10-K Summary	68
Signatures	69

DEFINITIONS

As used in this annual report, the terms listed below have the following meanings:

Common Industry and Other Terms



Bcf		billion cubic feet
Bcf/d		billion cubic feet per day
Bcf/yr		billion cubic feet per year
Bcfe		billion cubic feet equivalent
DOE		U.S. Department of Energy
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
FTA countries		countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
non-FTA countries		countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC		U.S. Securities and Exchange Commission
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

Entity Abbreviations



Cheniere		Cheniere Energy, Inc.
Cheniere Investments		Cheniere Energy Investments, LLC
Cheniere Marketing		Cheniere Marketing, LLC and subsidiaries
Cheniere Partners		Cheniere Energy Partners, L.P.
Cheniere Terminals		Cheniere LNG Terminals, LLC
CTPL		Cheniere Creole Trail Pipeline, L.P.
SPLNG		Sabine Pass LNG, L.P.

Unless the context requires otherwise, references to “SPL,” the “Company,” “we,” “us” and “our” refer to Sabine Pass Liquefaction, LLC.

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:


•	statements that we expect to commence or complete construction of our natural gas liquefaction project, or any expansions or portions thereof, by certain dates, or at all;

•

statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;


•	statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;


•	statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any such EPC or other contractor, and anticipated costs related thereto;


•	statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;


•	statements regarding counterparties to our commercial contracts, construction contracts, and other contracts;


•	statements regarding our planned development and construction of additional Trains, including the financing of such Trains;


•	statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;


•	statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and


•	any other statements that relate to non-historical or future information.

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

PART I


ITEMS 1. AND 2.	BUSINESS AND PROPERTIES

General

We are a Delaware limited liability company formed by Cheniere Partners in June 2010 to own, develop and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the pre-existing regasification facilities owned and operated by SPLNG. Our vision is to provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. We plan to construct up to six 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 mtpa of LNG per Train. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of Cheniere Partners. Cheniere Partners, a publicly traded limited partnership, is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses.

Our Business Strategy

Our primary business strategy is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:


•	achieving the date of first commercial delivery for our SPA customers;


•	safely, efficiently and reliably maintaining and operating our Trains;


•	completing construction and commencing operation of Train 5 of the Liquefaction Project;


•	making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;


•	obtaining the requisite long-term commercial contracts and financing to reach a final investment decision (“FID”) regarding Train 6 of the Liquefaction Project; and


•	further expanding and optimizing the Liquefaction Project by leveraging existing infrastructure.

Liquefaction Facilities

We are developing, constructing and operating the Liquefaction Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3 and 4 of the Liquefaction Project and commenced operating activities in May 2016, September 2016, March 2017 and October 2017, respectively. Train 5 of the Liquefaction Project is undergoing commissioning and the following table summarizes the status as of December 31, 2018:



		Train 5
Overall project completion percentage		99.7%
Completion percentage of:
Engineering		100%
Procurement		100%
Subcontract work		98.0%
Construction		99.6%
Date of expected substantial completion		1Q 2019

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:


•	Trains 1 through 4—FTA countries for a 30-year term, which commenced on May 15, 2016, and non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).


•	Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).


•	Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, we received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we were authorized but unable to export during any portion of the initial 20-year export period of such order.

In January 2018, the DOE issued orders authorizing us to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2018, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

Customers

We have entered into fixed price SPAs with terms of at least 20 years (plus extension rights) with six third parties for Trains 1 through 5 of the Liquefaction Project, to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity from these Trains. Under these SPAs, the customers will purchase LNG from us for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fees under our SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Under our SPA with BG Gulf Coast LNG, LLC (“BG”), BG has contracted for volumes related to Trains 3 and 4, for which the obligation to make volumes related to Train 3 available to BG has commenced and the obligation to make volumes related to Train 4 available to BG is expected to commence approximately one year after the date of first commercial delivery under our SPA with GAIL (India) Limited (“GAIL”) for Train 4.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.2 billion for Trains 1 through 3 and the SPA with GAIL for Train 4, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 under the SPA with BG and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

The annual contracted cash flows from fixed fees of each buyer of LNG under our third-party SPAs that constitute more than 10% of the aggregate fixed fees under all our SPAs are:


•	approximately $720 million from BG, which is guaranteed by BG Energy Holdings Limited;


•	approximately $550 million from Korea Gas Corporation (“KOGAS”);


•	approximately $550 million from GAIL; and


•	approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.).

We also have SPAs with Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A., and Centrica plc with annual aggregate fixed fees of approximately $590 million. In addition, Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers.

During the year ended December 31, 2018, four customers, BG, Naturgy, KOGAS and GAIL, individually accounted for more than 10% of our total revenues from external customers at 30%, 23%, 24% and 20%, respectively. During the year ended December 31, 2017, three customers, BG, Naturgy and KOGAS, individually accounted for more than 10% of our total third-party revenues at 43%, 30% and 25%, respectively. During the year ended December 31, 2016, BG individually accounted for 77% of our total revenues from external customers.

Natural Gas Transportation, Storage and Supply

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. We have also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2018, we had secured up to approximately 3,464 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

We have entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.

The total contract price of the EPC contract for Train 5 of the Liquefaction Project is approximately $3.1 billion reflecting amounts incurred under change orders through December 31, 2018. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs, including, in each case, estimated owner’s costs and contingencies. The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for an optional third marine berth.

Final Investment Decision on Train 6

We have issued limited notices to proceed to Bechtel for the commencement of certain engineering, procurement and site works for Train 6 of the Liquefaction Project and a schedule for completion has been established. FID and full notice to proceed for Train 6 of the Liquefaction Project will be contingent upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct Train 6.

Terminal Use Agreements

We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.0 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use our reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.

of $256 million, $190 million and $61 million, respectively, for the TUA Fees and cost of sales—affiliate of $32 million, $23 million and $5 million, respectively, for cargo loading services incurred under the TUA.

Additionally, we have entered into a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 3, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total’s capacity. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2018 and 2017, we recorded $30 million and $23 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Governmental Regulation

The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. This regulatory requirement increases the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

Federal Energy Regulatory Commission

The design, construction and operation of the Liquefaction Project and the export of LNG are highly regulated activities. In order to site, construct and operate the Liquefaction Project, we received and are required to maintain authorizations from the FERC under Section 3 of the Natural Gas Act of 1938, as amended (the “NGA”), as well as several other material governmental and regulatory approvals.

The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other federal or state agency’s authorities or responsibilities related to LNG terminals. The FERC issued final orders in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the Liquefaction Project (and related facilities). Subsequently, the FERC issued written approval to commence site preparation work for Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the Liquefaction Project, and in August 2013, the FERC issued an order approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in an order issued in April 2015 and an order denying rehearing issued in June 2015. These orders are not subject to appellate court review.

In 2002, the FERC concluded that it would apply light-handed regulation over the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with the FERC, as distinguished from the requirements applied to FERC-regulated natural gas pipelines. The EPAct codified the FERC’s policy, but those provisions expired on January 1, 2015. Nonetheless, we see no indication that the FERC intends to modify its longstanding policy of light-handed regulation of LNG terminals.

Several other material governmental and regulatory approvals and permits will be required throughout the life of our Liquefaction Project. In addition, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional FERC and other regulatory agency approvals as construction progresses. To date, we have been able to obtain these approvals as needed and the need for these approvals has not materially affected our construction progress. Throughout the life

of the Liquefaction Project, we will be subject to regular reporting requirements to the FERC and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities.

DOE Export License

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal as discussed in Our Liquefaction Project. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Exports of natural gas to FTA countries are “deemed to be consistent with the public interest” and authorization to export LNG to FTA countries shall be granted by the DOE without “modification or delay.” FTA countries which currently import LNG include Canada, Chile, Colombia, Dominican Republic, Israel, Jordan, Mexico, Panama, Singapore and South Korea. Exports of natural gas to non-FTA countries are considered by the DOE in the context of a comment period whereby interveners are provided the opportunity to assert that such authorization would not be consistent with the public interest.

Other Governmental Permits, Approvals and Authorizations

The construction and operation of the Liquefaction Project require additional federal permits, orders, approvals and consultations required by federal agencies, including the U.S. Department of Transportation (“DOT”), Advisory Council on Historic Preservation, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, Environmental Protection Agency (the “EPA”) and U.S. Department of Homeland Security.

Three significant permits are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit (the “Section 10/404 Permit”), the Clean Air Act Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”), of which the latter two permits are issued by the Louisiana Department of Environmental Quality (“LDEQ”).

The Sabine Pass LNG terminal’s Section 10/404 Permit authorizing construction of Trains 1 through 4 was received from the USACE in March 2012. A modification to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, was issued by the USACE in June 2015. The USACE acted in the capacity as a cooperating agency in the review process under the National Environmental Policy Act of 1969. The LDEQ issued amended PSD and Title V Permits in September 2017 to reflect certain facility modifications, updated emissions and as-built capacity factors. In October 2018, Sabine Pass LNG Terminal applied to the LDEQ for another amendment to its PSD and Title V Permits to reflect certain facility modifications and as-built reconciliation revisions.

LDEQ issued a modification of the wastewater discharge permit to Sabine Pass LNG Terminal in December 2017 to include wastewaters generated with respect to the anticipated operations of Trains 5 and 6 of the Liquefaction Project.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The regulatory regime created by the Dodd-Frank Act is designed primarily to (1) regulate certain participants in the swaps markets, including entities falling within the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authority of the CFTC and the SEC regarding the derivatives markets. Most of the regulations are already in effect, while other rules and regulations, including the proposed margin rules, position limits, and commodity clearing requirements, remain to be finalized or effectuated. Therefore, the impact of those rules and regulations on our business continues to be uncertain.

A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules, as it finds necessary and appropriate, imposing new position limits on certain physical commodity futures

contracts and options thereon, as well as economically equivalent swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price discovery function with respect to certain markets. In that regard, the CFTC has re-proposed position limits rules that would modify and expand the applicability of limits on speculative positions in certain physical commodity futures contracts, and economically equivalent futures, options and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging and other types of transactions. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

Pursuant to rules adopted by the CFTC, certain interest rate swaps and index credit default swaps must be cleared through a derivatives clearing organization and executed on an exchange or swap execution facility. The CFTC has not yet proposed to designate swaps in any other asset classes, including swaps relating to physical commodities, for mandatory clearing and trade execution, but could do so in the future. Although we expect to qualify for the end-user exception from the mandatory clearing and exchange-trading requirements applicable to any swaps that we enter into to hedge our commercial risks, the mandatory clearing and exchange-trading requirements may apply to other market participants, including our counterparties (who may be registered as Swap Dealers), with respect to other swaps, and the application of such rules may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require Swap Dealers and Major Swap Participants, including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules, which, as to the collection of initial margin, are being phased in, do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Any new rules or changes to existing rules promulgated under the Dodd-Frank Act could (1) impair the availability of derivatives, (2) materially increase the cost of, or decrease the liquidity of, the derivatives we use to hedge, (3) significantly alter the terms and conditions of derivatives and (4) potentially increase our exposure to less creditworthy counterparties. Further, any resulting reduction in the use of derivatives could make cash flow more volatile and less predictable, which in turn could adversely affect our ability to plan for and fund capital expenditures.

Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

Environmental Regulation

The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

Clean Air Act (“CAA”)

The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of the Liquefaction Project, will be materially and adversely affected by any such requirements.

In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the economy. This rule requires mandatory reporting of greenhouse gas (“GHG”) emissions from stationary sources, including fuel combustion sources. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. The Obama Administration took several actions intended to limit GHG emissions, including regulating emissions from new and existing Electricity Generating Units and from new and modified oil and gas operations. The timing, extent and impact of these rules and other Obama Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is published in the Federal Register. Many of the Trump Administration’s efforts to rollback Obama Administration actions have been challenged in court.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Coastal Zone Management Act (“CZMA”)

The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act (“CWA”)

The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ).

Resource Conservation and Recovery Act (“RCRA”)

The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. In the event such wastes are generated in connection with the Liquefaction Project, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If the Liquefaction Project may adversely affect a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.

In July 2018, the U.S. Fish and Wildlife Service (the “FWS”) announced a series of proposed changes to the rules implementing the ESA, including proposed revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The proposed revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions. It is not possible at this time to predict how such changes, if adopted, would impact our business.

In addition, in December 2017, the Department of Interior’s (“DOI’s”) Solicitor’s Office issued an official opinion that the Migratory Bird Treaty Act’s broad prohibition on “taking” migratory birds applies only to affirmative actions and does not include incidental taking. In April 2018 the FWS issued guidance consistent with the DOI’s opinion. The opinion has been challenged in court.

Market Factors and Competition

If and when we need to replace any existing SPA or enter into new SPAs, we will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world. Cheniere is currently developing a natural gas liquefaction facility near Corpus Christi, Texas and Corpus Christi Liquefaction, LLC (“CCL”) has entered into fixed price SPAs generally with terms of 20 years (plus extension rights) for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial agreements with respect to this natural gas liquefaction facility that might otherwise have been entered into with respect to Train 6. Revenues associated with any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA discussed above, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us.

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell any quantities of LNG available under the SPAs with Cheniere Marketing, or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and economic growth in developing countries. In addition, Cheniere’s ability to obtain additional funding to execute its business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and Cheniere’s ability to access capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International Energy Agency to grow by approximately 19 trillion cubic feet (“Tcf”) between 2017 and 2025, with LNG’s share growing from about 10% in 2017 to about 15% of the global gas market in 2025. Wood Mackenzie Limited forecasts that global demand for LNG will increase by approximately 60%, from approximately 287 mtpa, or 13.8 Tcf in 2017, to approximately 461 mtpa, or 22.1 Tcf, in 2025, and that LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 413 mtpa in 2025, resulting in a market need for construction of an additional approximately 48 mtpa of LNG production. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

Our LNG business has limited exposure to the decline in oil prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. We have contracted an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity for Trains 1 through 5 of the Liquefaction Project with third-party customers. As of January 31, 2019, U.S. natural gas prices indicate that LNG exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term, medium-term and short-term contracting of LNG from our terminal.

Employees

We have no employees. We have contracts with subsidiaries of Cheniere and Cheniere Partners for operations, maintenance and management services. As of January 31, 2019, Cheniere and its subsidiaries had 1,372 full-time employees, including 483 employees who directly supported the Liquefaction Project.

Available Information

Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.


ITEM 1A.	RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The risk factors in this report are grouped into the following categories:


•	Risks Relating to Our Financial Matters; and


•	Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business.

Risks Relating to Our Financial Matters

Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

As of December 31, 2018, we had zero cash and cash equivalents, $756 million of current restricted cash and $13.7 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs), excluding $425 million of outstanding letters of credit. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project, and we anticipate needing to incur additional debt to finance the construction of Train 6 of the Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

We have not been profitable historically. We may not achieve profitability or generate positive operating cash flow in the future.

We had a net loss of $193 million for the year ended December 31, 2016, and in prior years. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues, or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.

We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. Any delays beyond the expected development period for our Trains could cause, and could increase the level of, our operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete and operate the applicable Train.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by our customers to make the payments under long-term contracts. As of December 31, 2018, we had SPAs with seven third-party customers. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their respective SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the SPA.

Each of our customer contracts is subject to termination under certain circumstances.

Each of our SPAs contains various termination rights allowing our customers to terminate their SPAs, including, without limitation: (1) upon the occurrence of certain events of force majeure; (2) if we fail to make available specified scheduled cargo quantities; and (3) delays in the commencement of commercial operations. We may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.

Our use of hedging arrangements may adversely affect our future operating results or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements could expose us to risk of financial loss in some circumstances, including when:


•	expected supply is less than the amount hedged;


•	the counterparty to the hedging contract defaults on its contractual obligations; or


•	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities like us that participate in that market may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our Liquefaction Project.

The CFTC has re-proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. To the extent the revised CFTC position limits proposal becomes final, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

Under the Dodd-Frank Act and the rules adopted thereunder, we may be required to clear through a derivatives clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain trading platforms or exchanges. The CFTC has designated certain interest

rate swaps and index credit default swaps for mandatory clearing, but has not yet finalized rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks, if we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could be required to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. Our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

The Dodd-Frank Act also imposes other regulatory requirements on swaps market participants, including end users of swaps, such as regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and major swap participants. Together with the Basel III capital requirements on certain swaps market participants, the regulatory requirements of the Dodd-Frank Act and the rules thereunder relating to swaps and derivatives market participants could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter and reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. (and non-U.S.) regulatory developments in connection with these activities will not be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.

Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business

Operation of the Liquefaction Project involves significant risks.

As more fully discussed in these Risk Factors, the Liquefaction Project faces operational risks, including the following:


•	the facilities’ performing below expected levels of efficiency;


•	breakdown or failures of equipment;


•	operational errors by vessel or tug operators;


•	operational errors by us or any contracted facility operator;


•	labor disputes; and


•	weather-related interruptions of operations.

Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.

Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel or any future EPC contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the Liquefaction Project is fully constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our customers.

Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. In particular, each of our SPAs provides that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our ability to complete development of Train 6 will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.

We will require significant additional funding to be able to commence construction of Train 6, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development of Train 6, and we may not be able to complete our business plan. Even if we are able to obtain funding, the funding may be inadequate to cover any increases in costs or delays in completion of Train 6, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more future customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction Project, higher construction costs, and the deferral of the dates on which payments are due to us under the SPAs, all of which could adversely affect us.

In August and September of 2005, Hurricanes Katrina and Rita, respectively, damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal. In September 2008, Hurricane Ike struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced minor damage. In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations.

Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Project and related infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of the Liquefaction Project could impede operations and construction and could have a material adverse effect on us.

The design, construction and operation of the Liquefaction Project and the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and export LNG. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of six Trains and related facilities, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We will be required to obtain similar approvals and permits with respect to any expansion or modification of the Liquefaction Project. We cannot control the outcome of the FERC’s or the DOE’s review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, including as a result of untimely notices or filings, we may not be able to recover our investment in the Liquefaction Project. Additionally, government disruptions, such as a U.S. government shutdown, may delay or halt our ability to obtain and maintain necessary approvals and permits. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are entirely dependent on Cheniere and Cheniere Partners, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.

As of January 31, 2019, Cheniere and its subsidiaries had 1,372 full-time employees, including 483 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere and Cheniere Partners to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate liquefaction facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including the natural gas liquefaction facility it is developing and constructing near Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.

Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.

A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damages.

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could

generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.

We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, we have a TUA with SPLNG under which SPLNG derives economic benefits, we have entered into a transportation agreement with a subsidiary of Cheniere Partners to transport natural gas to the Liquefaction Project and Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently developing and constructing a natural gas liquefaction facility near Corpus Christi, Texas and CCL has entered into fixed price SPAs with third parties for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to Train 6.

We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future transportation, interconnection and gas balancing agreements with one or more Cheniere-affiliated natural gas pipelines as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.

We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.

We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.

Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:


•	design and engineer each Train to operate in accordance with specifications;


•	engage and retain third-party subcontractors and procure equipment and supplies;


•	respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;


•	attract, develop and retain skilled personnel, including engineers;


•	post required construction bonds and comply with the terms thereof;


•	manage the construction process generally, including coordinating with other contractors and regulatory agencies; and


•	maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Liquefaction Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Liquefaction Project or result in a contractor’s unwillingness to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement,

we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of the Liquefaction Project, and these estimates may prove to be inaccurate.

We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Liquefaction Project. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

If third-party pipelines and other facilities interconnected to our facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third-party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions could be restricted, thereby reducing our revenues, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of the Liquefaction Project is and will be subject to the inherent risks associated with this type of operation, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:


•	competitive liquefaction capacity in North America;


•	insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;


•	insufficient LNG tanker capacity;


•	weather conditions;


•	reduced demand and lower prices for natural gas;


•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;


•	decreased oil and natural gas exploration activities, which may decrease the production of natural gas;


•	cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;


•	changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;


•	changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;


•	political conditions in natural gas producing regions;


•	adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and


•	cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction Project will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Political instability in foreign countries that import natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.

In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.

As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or from the Liquefaction Project on a commercial basis. Any significant impediment to the ability to deliver LNG from the United States generally, or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Various economic and political factors could negatively affect the development, construction and operation of the Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Commercial development of a liquefaction facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:


•	increased construction costs;


•	economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for liquefaction projects on commercially reasonable terms;


•	decreases in the price of LNG, which might decrease the expected returns relating to investments in liquefaction projects;


•	the inability of project owners or operators to obtain governmental approvals to construct or operate liquefaction facilities;


•	political unrest or local community resistance to the siting of liquefaction facilities due to safety, environmental or security concerns; and


•	any significant explosion, spill or similar incident involving a liquefaction facility or LNG vessel.

There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our business and our customers because of:


•	an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;


•	political or economic disturbances in the countries where the vessels are being constructed;


•	changes in governmental regulations or maritime self-regulatory organizations;


•	work stoppages or other labor disturbances at the shipyards;


•	bankruptcy or other financial crisis of shipbuilders;


•	quality or engineering problems;


•	weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and


•	shortages of or delays in the receipt of necessary construction materials.

We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.

We have contracted for firm capacity for our natural gas feedstock transportation requirements for Trains 1 through 5 of the Liquefaction Project. We cannot control the regulatory and permitting approvals or third parties’ construction times. If and when we need to replace one or more of our agreements with these interconnecting pipelines, we may not be able to do so on commercially reasonable terms or at all, which could impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.

The Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs with respect to Train 6. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from the Liquefaction Project are diverse and include, among others:


•	increases in worldwide LNG production capacity and availability of LNG for market supply;


•	increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;


•	increases in the cost to supply natural gas feedstock to the Liquefaction Project;


•	decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;


•	decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;


•	increases in capacity and utilization of nuclear power and related facilities; and


•	displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

Terrorist attacks, cyber incidents or military campaigns may adversely impact our business.

A terrorist attack, cyber incident or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident or cyber incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, cyber incidents or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the Sabine Pass LNG terminal, including the Pipeline Hazardous Materials Safety Administration (“PHMSA”), to issue compliance orders, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

In October 2015, the EPA promulgated a final rule to implement the Obama Administration’s Clean Power Plan, which is designed to reduce GHG emissions from power plants in the United States. In February 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is published in the Federal Register. The Trump Administration announced in June 2017 that the United States would withdraw from the Paris Accord, an international agreement within the United Nations Framework Convention on Climate Change under which the Obama Administration committed the United States to reducing its economy-wide GHG emission by 26-28% below 2005 levels by 2025. Other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, a carbon emissions tax, or cap-and-trade programs. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG terminal could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Substantially all of our anticipated revenue in 2019 will be dependent upon one facility, the Liquefaction Project located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Project or in the LNG industry would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

We may incur impairments to long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, reduced estimates of future cash flows for our business or disruptions to our business could lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

LDEQ Matter

Certain of Cheniere’s subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated

Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

PHMSA Matter

In February 2018, PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. We continue to work with PHMSA and other appropriate regulatory authorities to address the matters identified in the Consent Order. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.


ITEM 4.	MINE SAFETY DISCLOSURE

Not applicable.

PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable.


ITEM 6.	SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited Financial Statements for the periods indicated (in millions). The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Financial Statements and the accompanying notes thereto included elsewhere in this report.



	Year Ended December 31,
	2018			2017			2016			2015			2014
Revenues (including transactions with affiliates)	$	6,126		$	4,024		$	833		$	—		$	—
Income (loss) from operations	1,520			781			50			(92		)	(119		)
Interest expense, net of capitalized interest	(589		)	(494		)	(186		)	(36		)	(24		)
Net income (loss)	944			250			(193		)	(266		)	(377		)



	December 31,
	2018		2017		2016		2015		2014
Property, plant and equipment, net	$	13,209	$	12,920	$	11,875	$	9,841	$	6,962
Total assets	14,967		14,206		12,883		10,433		7,818
Current debt	—		—		224		15		—
Long-term debt, net	13,500		13,477		11,649		9,206		6,390


ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects:


•	Overview of Business


•	Overview of Significant Events


•	Liquidity and Capital Resources


•	Contractual Obligations


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Estimates


•	Recent Accounting Standards

Overview of Business

We were formed by Cheniere Partners to develop, construct and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. Our vision is to provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. We plan to construct up to six 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 mtpa of LNG per Train.

Overview of Significant Events

Our significant accomplishments since January 1, 2018 and through the filing date of this Form 10-K include the following:

Strategic


•	In December 2018, we entered into a 20-year SPA with PETRONAS LNG Ltd., subject to conditions precedent including making a final investment decision (“FID”) for Train 6 of the Liquefaction Project, for the sale of approximately 1.1 mtpa of LNG on a free on board basis, with deliveries commencing following date of first commercial delivery for Train 6 of Liquefaction Project.


•	In November 2018, we entered into an EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for Train 6 of the Liquefaction Project. We also issued limited notices to proceed to Bechtel to commence early engineering, procurement and site works.

Operational


•	As of February 20, 2019, over 570 cumulative LNG cargoes have been produced, loaded and exported from the Liquefaction Project, with more than 270 cargoes in 2018 alone, with deliveries to 31 countries and regions worldwide.


•	In November 2018, we commenced production and shipment of LNG commissioning cargoes from Train 5 of the Liquefaction Project.

Financial


•	We reached the following contractual milestones:


◦	In June 2018, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC (“BG”) relating to Train 3 of the Liquefaction Project.


◦	In March 2018, the date of first commercial delivery was reached under the 20-year SPA with GAIL (India) Limited (“GAIL”) relating to Train 4 of the Liquefaction Project.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at December 31, 2018 and 2017 (in millions):



	December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	756		544
Available commitments under the $1.2 billion Working Capital Facility (“Working Capital Facility”)	775		470

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Financial Statements.

Liquefaction Facilities



		Train 5
Overall project completion percentage		99.7%
Completion percentage of:
Engineering		100%
Procurement		100%
Subcontract work		98.0%
Construction		99.6%
Date of expected substantial completion		1Q 2019

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:


•	Trains 1 through 4—FTA countries for a 30-year term, which commenced on May 15, 2016, and non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).


•	Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).


•	Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

Customers

We have entered into fixed price SPAs with terms of at least 20 years (plus extension rights) with six third parties for Trains 1 through 5 of the Liquefaction Project, to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity from these Trains. Under these SPAs, the customers will purchase LNG from us for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fees under our SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Under our SPA with BG, BG has contracted for volumes related to Trains 3 and 4, for which the obligation to make volumes related to Train 3 available to BG has commenced and the obligation to make volumes related to Train 4 available to BG is expected to commence approximately one year after the date of first commercial delivery under our SPA with GAIL for Train 4.

In addition, Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers.

Natural Gas Transportation, Storage and Supply

Construction

We have entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.

Final Investment Decision on Train 6

Terminal Use Agreements

Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. During the years ended December 31, 2018, 2017 and 2016, we recorded operating and maintenance expense—affiliate of $256 million, $190 million and $61 million, respectively, for the TUA Fees and cost of sales—affiliate of $32 million, $23 million and $5 million, respectively, for cargo loading services incurred under the TUA.

Additionally, we have entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 3 of the Liquefaction Project, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total’s capacity. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2018 and 2017, we recorded $30 million and $23 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Capital Resources

We currently expect that our capital resources requirements with respect to the Liquefaction Project will be financed through project debt and borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Train 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We began generating cash flows from operations from the Liquefaction Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3 and 4 subsequently achieved substantial completion in September 2016, March 2017 and October 2017, respectively. We realized offsets to LNG terminal costs of $94 million, $301 million and $201 million in the years ended December 31, 2018, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

The following table provides a summary of our capital resources from borrowings and available commitments for the Liquefaction Project, excluding equity contributions from Cheniere Partners and cash flows from operations (as described in Sources and Uses of Cash), at December 31, 2018 and 2017 (in millions):



	December 31,
	2018		2017
Senior notes (1)	$	13,650	$	13,650
Working Capital Facility outstanding balance	—		—
Letters of credit issued under Working Capital Facility	425		730
Available commitments under Working Capital Facility	775		470
Total capital resources from borrowings and available commitments	$	14,850	$	14,850

(1)

Includes 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 Senior Notes”) (collectively, the “Senior Notes”).

For additional information regarding our debt agreements related to the Liquefaction Project, see Note 10—Debt of our Notes to Financial Statements.

Senior Notes

The Senior Notes are secured on a pari passu first-priority basis by a security interest in all of our membership interests and substantially all of our assets.

At any time prior to three months before the respective dates of maturity for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes, in which case the time period is six months before the respective dates of maturity), we may redeem all or part of such series of the Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within three months of the respective maturity dates for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Both the indenture governing the 2037 Senior Notes (the “2037 Senior Notes Indenture”) and the common indenture governing the remainder of the Senior Notes (the “Indenture”) include restrictive covenants. We may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than our current outstanding indebtedness, including the Senior Notes and the Working Capital Facility. Under the 2037 Senior Notes Indenture and the Indenture, we may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. As of December 31, 2018, we were in compliance with all covenants related to the Senior Notes. Semi-annual principal payments for the 2037 Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025.

Working Capital Facility

In September 2015, we entered into the Working Capital Facility, which is intended to be used for loans (“Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. We may, from time to time, request increases in the commitments under the Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of December 31, 2018 and 2017, we had $775 million and $470 million of available commitments and $425 million

and $730 million aggregate amount of issued letters of credit under the Working Capital Facility, respectively. We did not have any amounts outstanding under the Working Capital Facility as of both December 31, 2018 and 2017.

The Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. Loans deemed made in connection with a draw upon a letter of credit have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the Working Capital Facility, (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2018, we were in compliance with all covenants related to the Working Capital Facility. Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as all of our membership interests on a pari passu basis with the Senior Notes.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years ended December 31, 2018, 2017 and 2016 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Year Ended December 31,
	2018			2017			2016
Operating cash flows	$	1,423		$	657		$	(130	)
Investing cash flows	(771		)	(1,279		)	(2,338		)
Financing cash flows	(440		)	808			2,637

Net increase in cash, cash equivalents and restricted cash	212			186			169
Cash, cash equivalents and restricted cash—beginning of period	544			358			189
Cash, cash equivalents and restricted cash—end of period	$	756		$	544		$	358

Operating Cash Flows

Our operating cash flows during the years ended December 31, 2018, 2017 and 2016 were net inflows of $1,423 million and $657 million and a net outflow of $130 million, respectively. The $766 million increase in operating cash inflows in 2018 compared to 2017 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the Liquefaction Project in 2018. We had four Trains operational for the entire year during the year ended December 31, 2018, we had two Trains operational for the entire year and two Trains operational partially during the year ended December 31, 2017 and two Trains operational partially during the year ended December 31, 2016. The $787 million increase in operating cash inflows in 2017 compared to 2016 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the Liquefaction Project in 2017. During the year ended December 31, 2016, Train 1 was operating for seven months and Train 2 was operating for less than four months.

Investing Cash Flows

Investing cash net outflows during the years ended December 31, 2018, 2017 and 2016 were $771 million, $1,279 million and $2,338 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the year ended December 31, 2016, we used $32 million primarily for payments to a municipal water district for water system enhancements to increase potable water supply to the Sabine Pass LNG terminal and payments made pursuant to the information technology services agreement for capital assets purchased on our behalf.

Financing Cash Flows

Financing cash net outflows during the year ended December 31, 2018 were $440 million, primarily as a result of:


•	$129 million of equity contributions from Cheniere Partners; and


•	$569 million of distributions to Cheniere Partners.

Financing cash net inflows during the year ended December 31, 2017 were $808 million, primarily as a result of:


•	issuances of senior notes for an aggregate principal amount of $2.15 billion;


•	$55 million of borrowings and $369 million of repayments made under the credit facilities we entered into in June 2015 (the “Credit Facilities”);


•	$110 million of borrowings and $334 million of repayments made under the Working Capital Facility;


•	$29 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;


•	$7 million of equity contributions from Cheniere Partners; and


•	$781 million of distributions to Cheniere Partners.

Financing cash net inflows during the year ended December 31, 2016 were $2,637 million, primarily as a result of:


•	$2.0 billion of borrowings under the Credit Facilities;


•	issuance of an aggregate principal amount of $1.5 billion of the 2026 Senior Notes in June 2016, which was used to prepay $1.3 billion of the outstanding borrowings under the Credit Facilities;


•	issuance of an aggregate principal amount of $1.5 billion of the 2027 Senior Notes in September 2016, which was used to prepay $1.2 billion of the outstanding borrowings under the Credit Facilities and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project;


•	$474 million of borrowings and $265 million of repayments made under the Working Capital Facility;


•	$42 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$1 million of equity contributions from Cheniere Partners.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2018 (in millions):



	Payments Due By Period (1)
	Total		2019		2020 - 2021		2022 - 2023		Thereafter
Debt (2)	$	13,650	$	—	$	2,000	$	2,500	$	9,150
Interest payments (2)	4,480		760		1,404		1,097		1,219
Construction obligations (3)	87		87		—		—		—
Purchase obligations (4)	7,931		2,495		2,388		1,396		1,652
Operating lease obligations	9		—		1		1		7
Obligations to affiliates (5)	6,546		372		743		743		4,688
Other obligations (6)	6		3		3		—		—
Total	$	32,709	$	3,717	$	6,539	$	5,737	$	16,716


(1)	Agreements in force as of December 31, 2018 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2018.


(2)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2018. See Note 10—Debt of our Notes to Financial Statements.


(3)	Construction obligations relate to the EPC contracts for the Liquefaction Project. The estimated remaining cost pursuant to our EPC contracts as of December 31, 2018 is included for Trains with respect to which we have made an FID to commence construction; the EPC contract termination amount is included for Trains with respect to which we have not

made an FID. A discussion of these obligations can be found at Note 14—Commitments and Contingencies of our Notes to Financial Statements.


(4)	Purchase obligations consist of contracts for which conditions precedent have been met, and primarily relate to natural gas supply, transportation and storage services for the Liquefaction Project. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly.

(5)

Obligations to affiliates relate to land subleased from SPLNG for the Liquefaction Project. Obligations arising through intercompany service agreements include TUA fees with SPLNG, including amounts assumed under the TURA, and only include the fixed fee portion and do not include variable fees. A discussion of these obligations can be found in Note 12—Related Party Transactions of our Notes to Financial Statements.


(6)	Other obligations primarily relate to agreements with certain local taxing jurisdictions, and are based on tax obligations as of December 31, 2018.

In addition, in the ordinary course of business, we maintain letters of credit and have certain cash restricted in support of certain performance obligations. As of December 31, 2018, we had $425 million aggregate amount of issued letters of credit under the Working Capital Facility and $756 million of current restricted cash. For more information, see Note 3—Restricted Cash of our Notes to Financial Statements.

Results of Operations

Our net income was $944 million in the year ended December 31, 2018, compared to $250 million in the year ended December 31, 2017. This $694 million increase in net income in 2018 was primarily a result of increased income from operations due to additional Trains operating between the periods and decreased loss on modification or extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

Our net loss was $193 million in the year ended December 31, 2016. This $443 million increase in net income in 2017 compared to 2016 was primarily a result of increased income from operations, which was partially offset by increased interest expense, net of amounts capitalized.

Revenues



	Year Ended December 31,
(in millions, except volumes)	2018		2017		Change			2016		Change
LNG revenues	$	4,827	$	2,635	$	2,192		$	539	$	2,096
LNG revenues—affiliate	1,299		1,389		(90		)	294		1,095
Total revenues	$	6,126	$	4,024	$	2,102		$	833	$	3,191

LNG volumes recognized as revenues (in TBtu)	955		684		271			151		533

2018 vs. 2017 and 2017 vs. 2016

We begin recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of the respective Trains. We had four Trains operational for the entire year during the year ended December 31, 2018, we had two Trains operational for the entire year and two Trains operational partially during the year ended December 31, 2017 and two Trains operational partially during the year ended December 31, 2016. The increase in revenues for each of the years was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of these Trains, as well as increased revenues per MMBtu. We expect our LNG revenues to increase in the future upon Train 5 of the Liquefaction Project becoming operational.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the years ended December 31, 2018, 2017 and 2016, we realized offsets to LNG terminal costs of $94 million corresponding to 13 TBtu of LNG, $301 million corresponding to 51 TBtu of LNG and $201 million corresponding to 45 TBtu of LNG, respectively, that were related to the sale of commissioning cargoes.

Operating costs and expenses



	Year Ended December 31,
(in millions)	2018		2017		Change			2016		Change
Cost of sales	$	3,403	$	2,317	$	1,086		$	416	$	1,901
Cost of sales—affiliate	32		23		9			7		16
Operating and maintenance expense	342		243		99			72		171
Operating and maintenance expense—affiliate	423		329		94			129		200
Development expense	2		2		—			—		2
Development expense—affiliate	—		—		—			1		(1		)
General and administrative expense	5		7		(2		)	7		—
General and administrative expense—affiliate	50		58		(8		)	68		(10		)
Depreciation and amortization expense	349		264		85			83		181
Total operating costs and expenses	$	4,606	$	3,243	$	1,363		$	783	$	2,460

2018 vs. 2017 and 2017 vs. 2016

Our total operating costs and expenses increased during the year ended December 31, 2018 from the years ended December 31, 2017 and 2016, primarily as a result of additional Trains that were operating between each of the periods.

Cost of sales increased during the year ended December 31, 2018 from the comparable periods in 2017 and 2016, primarily as a result of the increase in operating Trains between each of the periods. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. The increase during the year ended December 31, 2018 from the comparable period in 2017 was primarily related to the increase in the volume of natural gas feedstock related to our LNG sales. The increase during the year ended December 31, 2017 from the comparable period in 2016 was primarily related to the increase in both the volume and pricing of natural gas feedstock related to our LNG sales. Cost of sales also includes gains and losses from derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense (including affiliates) increased during the year ended December 31, 2018 from the comparable periods in 2017 and 2016, as a result of the increase in operating Trains between each of the periods. Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase during the year ended December 31, 2018 from the comparable periods in 2017 and 2016 was primarily related to TUA reservation charges paid to SPLNG and to Total from payments under the partial TUA assignment agreement, natural gas transportation and storage capacity demand charges paid to CTPL and third parties, third-party service and maintenance contract costs and payroll and benefit costs of operations personnel. Operating and maintenance expense (including affiliates) also includes insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the year ended December 31, 2018 from the comparable periods in 2017 and 2016 as a result of an increased number of operational Trains, as the assets related to the Trains of the Liquefaction Project began depreciating upon reaching substantial completion.

We expect our operating costs and expenses to generally increase in the future upon Train 5 of the Liquefaction Project achieving substantial completion, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense (income)



	Year Ended December 31,
(in millions)	2018			2017			Change			2016			Change
Interest expense, net of capitalized interest	$	589		$	494		$	95		$	186		$	308
Loss on modification or extinguishment of debt	—			42			(42		)	52			(10		)
Derivative loss, net	—			2			(2		)	6			(4		)
Other income	(13		)	(7		)	(6		)	(1		)	(6		)
Total other expense	$	576		$	531		$	45		$	243		$	288

2018 vs. 2017

Interest expense, net of capitalized interest, increased during the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily as a result of a decrease in the portion of total interest costs that could be capitalized as additional Trains of the Liquefaction Project completed construction between the periods. For the years ended December 31, 2018 and 2017, we incurred $791 million and $779 million of total interest cost, respectively, of which we capitalized $202 million and $285 million, respectively, which was primarily related to the construction of the Liquefaction Project.

Loss on modification or extinguishment of debt decreased during the year ended December 31, 2018, as compared to the year ended December 31, 2017. Loss on modification or extinguishment of debt recognized during the year ended December 31, 2017 was attributable to the $42 million write-off of debt issuance costs in March 2017 upon termination of the remaining available balance of $1.6 billion under the Credit Facilities in connection with the issuance of the 2028 Senior Notes and the 2037 Senior Notes.

2017 vs. 2016

Interest expense, net of capitalized interest, increased during the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily as a result of a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 4 of the Liquefaction Project completed construction and an increase in our indebtedness outstanding (before unamortized premium, discount and debt issuance costs), from $12.0 billion as of December 31, 2016 to $13.7 billion as of December 31, 2017. For the year ended December 31, 2016, we incurred $649 million of total interest cost, of which we capitalized $463 million, which was primarily related to the construction of the Liquefaction Project.

Loss on modification or extinguishment of debt decreased during the year ended December 31, 2017, as compared to the year ended December 31, 2016. Loss on modification or extinguishment of debt recognized during the year ended December 31, 2016 was due to the $26 million write-off of debt issuance costs related to the prepayment of approximately $1.3 billion of outstanding borrowings under the Credit Facilities in June 2016 in connection with the issuance of the 2026 Senior Notes, in addition to the $26 million write-off of debt issuance costs related to the prepayment of outstanding borrowings and termination of commitments under the Credit Facilities of approximately $1.4 billion in September 2016 in connection with the issuance of the 2027 Senior Notes.

Derivative loss, net decreased during the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily due to a favorable shift in the long-term forward LIBOR curve between the periods, which was offset by the $7 million payment made in March 2017 upon the settlement of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under the Credit Facilities.

Off-Balance Sheet Arrangements

As of December 31, 2018, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our financial position or operating results.

Summary of Critical Accounting 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 valuation of derivative instruments and properties, plant and equipment. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Derivative Instruments

All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the

quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.

Our derivative instruments consist of financial commodity derivative contracts transacted in an over-the-counter market and index-based physical commodity contracts. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data. Valuation of our index-based physical commodity contracts is developed through the use of internal models which are impacted by inputs that may be unobservable in the marketplace, market transactions and other relevant data.

Gains and losses on derivative instruments are recognized in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as interest rates and commodity prices change.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 17—Recent Accounting Standards of our Notes to Financial Statements.


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):



	December 31, 2018					December 31, 2017
	Fair Value			Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(43	)	$	7	$	55	$	5

See Note 7—Derivative Instruments for additional details about our derivative instruments.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

SABINE PASS LIQUEFACTION, LLC



Management’s Report to the Member of Sabine Pass Liquefaction, LLC	34
Report of Independent Registered Public Accounting Firm	35
Balance Sheets	36
Statements of Operations	37
Statements of Member’s Equity (Deficit)	38
Statements of Cash Flows	39
Notes to Financial Statements	40
Supplemental Information to Financial Statements—Summarized Quarterly Financial Data	60

MANAGEMENT’S REPORT TO THE MEMBER OF SABINE PASS LIQUEFACTION, LLC

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Sabine Pass Liquefaction’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Sabine Pass Liquefaction maintained effective internal control over financial reporting as of December 31, 2018, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.

This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Management’s Certifications

The certifications of Sabine Pass Liquefaction’s Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.




By:	/s/ Jack A. Fusco	By:	/s/ Michael J. Wortley
	Jack A. Fusco		Michael J. Wortley
	Chief Executive Officer (Principal Executive Officer)		Manager and Chief Financial Officer (Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member

Sabine Pass Liquefaction, LLC:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2018 and 2017, the related statements of operations, member’s equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in Note 2 to the financial statements, the Company has changed its method of accounting for revenue recognition in 2018, 2017 and 2016 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

KPMG LLP

We have served as the Company’s auditor since 2014.

Houston, Texas

February 25, 2019

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)



	December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	756		544
Accounts and other receivables	346		189
Accounts receivable—affiliate	113		163
Advances to affiliate	210		26
Inventory	87		85
Other current assets	24		54
Other current assets—affiliate	21		21
Total current assets	1,557		1,082

Property, plant and equipment, net	13,209		12,920
Debt issuance costs, net	12		18
Non-current derivative assets	31		17
Other non-current assets, net	158		169
Total assets	$	14,967	$	14,206

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	11	$	8
Accrued liabilities	768		606
Due to affiliates	48		66
Deferred revenue	91		84
Derivative liabilities	66		—
Total current liabilities	984		764

Long-term debt, net	13,500		13,477
Non-current derivative liabilities	14		3
Other non-current liabilities	3		—

Commitments and contingencies (see Note 14)

Member’s equity (deficit)	466		(38		)
Total liabilities and member’s equity (deficit)	$	14,967	$	14,206

The accompanying notes are an integral part of these financial statements.

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in millions)



	Year Ended December 31,
	2018			2017			2016
Revenues
LNG revenues	$	4,827		$	2,635		$	539
LNG revenues—affiliate	1,299			1,389			294
Total revenues	6,126			4,024			833

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	3,403			2,317			416
Cost of sales—affiliate	32			23			7
Operating and maintenance expense	342			243			72
Operating and maintenance expense—affiliate	423			329			129
Development expense	2			2			—
Development expense—affiliate	—			—			1
General and administrative expense	5			7			7
General and administrative expense—affiliate	50			58			68
Depreciation and amortization expense	349			264			83
Total operating costs and expenses	4,606			3,243			783

Income from operations	1,520			781			50

Other income (expense)
Interest expense, net of capitalized interest	(589		)	(494		)	(186		)
Loss on modification or extinguishment of debt	—			(42		)	(52		)
Derivative loss, net	—			(2		)	(6		)
Other income	13			7			1
Total other expense	(576		)	(531		)	(243		)

Net income (loss)	$	944		$	250		$	(193	)

The accompanying notes are an integral part of these financial statements.

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF MEMBER’S EQUITY (DEFICIT)

(in millions)



	Sabine Pass LNG-LP, LLC			Total Member’s Equity (Deficit)
Balance at December 31, 2015	$	931		$	931
Capital contributions	1			1
Distributions	(253		)	(253		)
Net loss	(193		)	(193		)
Balance at December 31, 2016	486			486
Capital contributions	7			7
Distributions	(781		)	(781		)
Net income	250			250
Balance at December 31, 2017	(38		)	(38		)
Capital contributions	129			129
Distributions	(569		)	(569		)
Net income	944			944
Balance at December 31, 2018	$	466		$	466

The accompanying notes are an integral part of these financial statements.

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in millions)



	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities
Net income (loss)	$	944		$	250		$	(193	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	349			264			83
Amortization of debt issuance costs, deferred commitment fees, premium and discount	22			19			12
Loss on modification or extinguishment of debt	—			42			52
Total losses (gains) on derivatives, net	101			26			(36		)
Net cash used for settlement of derivative instruments	(3		)	(14		)	(7		)
Changes in operating assets and liabilities:
Accounts and other receivables	(122		)	(99		)	(90		)
Accounts receivable—affiliate	49			(63		)	(99		)
Advances to affiliate	(76		)	(13		)	1
Inventory	(3		)	11			(60		)
Accounts payable and accrued liabilities	165			190			179
Due to affiliates	(6		)	22			1
Deferred revenue	7			38			46
Other, net	(4		)	(4		)	(10		)
Other, net—affiliate	—			(12		)	(9		)
Net cash provided by (used in) operating activities	1,423			657			(130		)

Cash flows from investing activities
Property, plant and equipment, net	(771		)	(1,279		)	(2,306		)
Other	—			—			(32		)
Net cash used in investing activities	(771		)	(1,279		)	(2,338		)

Cash flows from financing activities
Proceeds from issuances of debt	—			2,314			5,443
Repayments of debt	—			(703		)	(2,765		)
Debt issuance and deferred financing costs	—			(29		)	(42		)
Capital contributions	129			7			1
Distributions	(569		)	(781		)	—
Net cash provided by (used in) financing activities	(440		)	808			2,637

Net increase in cash, cash equivalents and restricted cash	212			186			169
Cash, cash equivalents and restricted cash—beginning of period	544			358			189
Cash, cash equivalents and restricted cash—end of period	$	756		$	544		$	358

Balances per Balance Sheets:



	December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash	756		544
Total cash, cash equivalents and restricted cash	$	756	$	544

The accompanying notes are an integral part of these financial statements.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed by Cheniere Partners to develop, construct and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of Cheniere Partners. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of Cheniere Partners, a publicly traded limited partnership (NYSE MKT: CQP). Cheniere Partners is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses.

Our Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal, which is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 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 Bcf/d. We plan to construct up to six 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 mtpa of LNG per Train.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP. 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.

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, derivative instruments, 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. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—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.

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.

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, 2017 and 2016.

Inventory

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

Accounting for LNG Activities

Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning 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 realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property,

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.

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, 2017 and 2016, respectively.

Interest Capitalization

We capitalize interest and other related debt costs during the construction period of our LNG terminals and related pipelines as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2018, 2017 and 2016. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

We have entered into fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration.

Debt

Our debt consists of current and long-term secured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

method. Gains and losses on the extinguishment of debt are recorded in gain (loss) on modification or extinguishment of debt on our Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on modification or extinguishment of debt.

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 the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

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 Operations, 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.

At December 31, 2018, the tax basis of our assets and liabilities was $2.6 billion less than the reported amounts of our assets and liabilities.

Pursuant to the indentures governing our debt, we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes. The Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the state tax sharing agreement discussed in Note 12—Related Party Transactions. The Tax Distributions are limited to the amount of federal and/or state income taxes paid by Cheniere to the appropriate taxing authorities and are payable by us within 30 days of the date that Cheniere is required to make federal or state income tax payments to the appropriate taxing authorities.

Business Segment

Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—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 December 31, 2018 and 2017, restricted cash consisted of the following (in millions):



	December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	756	$	544

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2018 and 2017, accounts and other receivables consisted of the following (in millions):



	December 31,
	2018		2017
Trade receivable	$	330	$	185
Other accounts receivable	16		4
Total accounts and other receivables	$	346	$	189

NOTE 5—INVENTORY

As of December 31, 2018 and 2017, inventory consisted of the following (in millions):



	December 31,
	2018		2017
Natural gas	$	28	$	17
LNG	6		26
Materials and other	53		42
Total inventory	$	87	$	85

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2018 and 2017, property, plant and equipment, net consisted of the following (in millions):



	December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	10,004		$	9,963
LNG terminal construction-in-process	3,866			3,283
Accumulated depreciation	(667		)	(330		)
Total LNG terminal costs, net	13,203			12,916
Fixed assets
Fixed assets	14			10
Accumulated depreciation	(8		)	(6		)
Total fixed assets, net	6			4
Property, plant and equipment, net	$	13,209		$	12,920

Depreciation expense was $339 million, $257 million and $77 million during the years ended December 31, 2018, 2017 and 2016, respectively.

We realized offsets to LNG terminal costs of $94 million, $301 million and $201 million in the years ended December 31, 2018, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.

LNG Terminal Costs

LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:



Components		Useful life (yrs)
Water pipelines		30
Liquefaction processing equipment		6-50
Other		15-30

Fixed Assets and Other

Our fixed assets and other 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 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). We had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of our credit facilities (“Interest Rate Derivatives”), and these Interest Rate Derivatives were settled in March 2017.

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Statements of Operations to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2018 and 2017, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Balance Sheets (in millions).



	Fair Value Measurements as of
	December 31, 2018											December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	5	$	(23	)	$	(25	)	$	(43	)	$	2	$	10	$	43	$	55

We value our Liquefaction Supply Derivatives using a market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018:



	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(25)	Market approach incorporating present value techniques	Basis Spread	$(0.892) - $0.085

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 2017 and 2016 (in millions):



	Year Ended December 31,
	2018			2017			2016
Balance, beginning of period	$	43		$	79		$	32
Realized and mark-to-market gains (losses):
Included in cost of sales (1)	(3		)	(37		)	48
Purchases and settlements:
Purchases	(37		)	14			1
Settlements (1)	(29		)	(12		)	(2		)
Transfers out of Level 3 (2)	1			(1		)	—
Balance, end of period	$	(25	)	$	43		$	79
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(3	)	$	(37	)	$	49


(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.


(2)	Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

We had entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities we entered into in June 2015 (the “Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the Credit Facilities. In March 2017, we settled the Interest Rate Derivatives and paid $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the Credit Facilities.

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in millions):



	Year Ended December 31,
	2018		2017			2016
Interest Rate Derivatives loss	$	—	$	(2	)	$	(6	)

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Liquefaction Supply Derivatives

We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent.

Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

We had secured up to approximately 3,464 TBtu and 2,214 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2018 and 2017, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 2,978 TBtu and 1,520 TBtu as of December 31, 2018 and 2017, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions):



	Fair Value Measurements as of (1)
Balance Sheet Location	December 31, 2018			December 31, 2017
Other current assets	$	6		$	41
Non-current derivative assets	31			17
Total derivative assets	37			58

Derivative liabilities	(66		)	—
Non-current derivative liabilities	(14		)	(3		)
Total derivative liabilities	(80		)	(3		)

Derivative asset (liability), net	$	(43	)	$	55


(1)	Does not include collateral calls of $1 million for such contracts, which are included in other current assets in our Balance Sheets as of both December 31, 2018 and 2017.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives on our Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in millions):



		Year Ended December 31,
	Statement of Operations Location (1)	2018			2017			2016
Liquefaction Supply Derivatives loss	LNG revenues	$	(1	)	$	—		$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	(100		)	(24		)	42


(1)	Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):



	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amounts Presented in the Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amounts Presented in the Balance Sheets
As of December 31, 2018
Liquefaction Supply Derivatives	$	63		$	(26	)	$	37
Liquefaction Supply Derivatives	(92		)	12			(80		)
As of December 31, 2017
Liquefaction Supply Derivatives	$	64		$	(6	)	$	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2018 and 2017, other non-current assets, net consisted of the following (in millions):



	December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	14	$	26
Advances made to municipalities for water system enhancements	90		93
Advances and other asset conveyances to third parties to support LNG terminals	36		30
Tax-related payments and receivables	—		1
Information technology service assets	16		19
Other	2		—
Total other non-current assets, net	$	158	$	169

NOTE 9—ACCRUED LIABILITIES

As of December 31, 2018 and 2017, accrued liabilities consisted of the following (in millions):



	December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	230
Accrued natural gas purchases	518		298
Liquefaction Project costs	64		78
Total accrued liabilities	$	768	$	606

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 10—DEBT

As of December 31, 2018 and 2017, our debt consisted of the following (in millions):



	December 31,
	2018			2017
Long-term debt
5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”)	800			800
Unamortized discount, premium and debt issuance costs, net	(150		)	(173		)
Total long-term debt, net	13,500			13,477

Current debt
$1.2 billion Working Capital Facility (“Working Capital Facility”)	—			—
Total debt, net	$	13,500		$	13,477

Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2018 (in millions):



Years Ending December 31,	Principal Payments
2019	$	—
2020	—
2021	2,000
2022	1,000
2023	1,500
Thereafter	9,150
Total	$	13,650

Senior Notes

The terms of the 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes (collectively with the 2037 Senior Notes, the “Senior Notes”) are governed by a common indenture (the “Indenture”) and the terms of the 2037 Senior Notes are governed by a separate indenture (the “2037 Senior Notes Indenture”). Both the Indenture and the 2037 Senior Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of our restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of our assets and enter into certain LNG sales contracts. Subject to permitted liens, the Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2018, we were in compliance with all covenants related to the Senior Notes. Interest on the Senior Notes is payable semi-annually in arrears.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

price) set forth in the respective indentures governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within three months of the respective maturity dates for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Working Capital Facility

Below is a summary of our Working Capital Facility as of December 31, 2018 (in millions):



	Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	425
Available commitment	$	775

Interest rate	LIBOR plus 1.75% or base rate plus 0.75%
Maturity date	December 31, 2020, with various terms for underlying loans

In September 2015, we entered into the Working Capital Facility, which is intended to be used for loans (the “Working Capital Facility”), the issuance of letters of credit, as well as for swing line loans (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. We may, from time to time, request increases in the commitments under the Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million.

Loans under the Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

We pay (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the Working Capital Facility. If draws are made upon a letter of credit issued under the Working Capital Facility and we do not elect for such draw (an “LC Draw”) to be deemed an LC Loan, we are required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2018, no LC Draws had been made upon any letters of credit issued under the Working Capital Facility.

The Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. LC Loans have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the Working Capital Facility, (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2018, we were in compliance with all covenants related to the Working Capital Facility. Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as all of the membership interests in us on a pari passu basis with the Senior Notes.

Interest Expense

Total interest expense consisted of the following (in millions):



	Year Ended December 31,
	2018			2017			2016
Total interest cost	$	791		$	779		$	649
Capitalized interest	(202		)	(285		)	(463		)
Total interest expense, net	$	589		$	494		$	186

Fair Value Disclosures

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):



	December 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	12,709	$	13,235	$	12,687	$	13,955
2037 Senior Notes (2)	791		817		790		871


(1)	Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.


(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2018, 2017 and 2016 (in millions):



	Year Ended December 31,
	2018		2017		2016
LNG revenues	$	4,687	$	2,615	$	535
LNG revenues—affiliate	1,299		1,389		294
Total revenues from customers	5,986		4,004		829
Gains from derivative instruments (1)	140		20		4
Total revenues	$	6,126	$	4,024	$	833


(1)	Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as deferred revenues on our Balance Sheets (in millions):



	Year Ended December 31,
	2018			2017
Deferred revenues, beginning of period	$	84		$	46
Cash received but not yet recognized	91			84
Revenue recognized from prior period deferral	(84		)	(46		)
Deferred revenues, end of period	$	91		$	84

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2018 and 2017 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, 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 Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	53.6	10	$	55.7	10


(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 have elected the following exemptions which omit certain potential future sources of revenue from the table above:


(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs. The amount of revenue from variable fees that is not included in the transaction price will vary based

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Approximately 57% and 58% of our LNG revenues were related to variable consideration received from customers during the years ended December 31, 2018 and 2017, respectively. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the years ended December 31, 2018 and 2017.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

NOTE 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2018, 2017 and 2016 (in millions):



	Year Ended December 31,
	2018		2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	1,299	$	1,389	$	294

Cost of sales—affiliate
Cargo loading fees under TUA	32		23		5
Fees under the Pre-commercial LNG Marketing Agreement	—		—		2
Total cost of sales—affiliate	32		23		7

Operating and maintenance expense—affiliate
TUA	256		190		61
Natural Gas Transportation Agreement	80		73		45
Services Agreements	87		65		22
LNG Site Sublease Agreement	—		1		1
Total operating and maintenance expense—affiliate	423		329		129

Development expense—affiliate
Services Agreements	—		—		1

General and administrative expense—affiliate
Services Agreements	50		58		68

LNG Terminal-Related Agreements

As of December 31, 2018 and 2017, we had $113 million and $163 million of accounts receivable—affiliate, respectively, under the agreements described below.

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.0 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use our reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.

In connection with our TUA, we are required to pay for a portion of the cost to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is based on our share of the commercial LNG storage capacity at the Sabine Pass LNG terminal.

Cheniere Marketing SPA

Cheniere Marketing has an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Cheniere Marketing Master SPA

We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We executed a confirmation with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control of, and is commissioning, Train 5 of the Liquefaction Project.

Natural Gas Transportation Agreements

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements have a primary term of 20 years from commercial operation of Train 2 and thereafter 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. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise.

Services Agreements

As of December 31, 2018 and 2017, we had $210 million and $26 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.

Liquefaction MSA

We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investment’s 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.

LNG Site Sublease Agreement

We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. Under this agreement, we conveyed to SPLNG $253 million of assets for the year ended December 31, 2016 which were recorded as non-cash distributions to affiliates. We did not convey any assets to SPLNG under this agreement during the years ended December 31, 2018 and 2017.

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with SPLNG that allow us to sell and purchase natural gas and LNG with SPLNG. Natural gas and LNG purchased under these agreements are recorded as inventory, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process.

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 August 2012.

NOTE 13—LEASES

During the years ended December 31, 2018, 2017 and 2016, we recognized rental expense for all operating leases of $5 million, $3 million and $2 million, respectively, related primarily to land sites for the Liquefaction Project. We have an agreement with SPLNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. See Note 12—Related Party Transactions for additional information regarding this sublease agreement.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Future annual minimum lease payments, excluding inflationary adjustments and payments to affiliates, are as follows (in millions):



Years ending December 31,	Operating Leases (1)
2019 through 2023	$	2
Thereafter	7
Total	$	9


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

NOTE 14—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2018, are not recognized as liabilities but require disclosures in our Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

We have lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 5 and Train 6 of the Liquefaction Project. The EPC contract prices for Train 5 of the Liquefaction Project and Train 6 of the Liquefaction Project are approximately $3.1 billion and $2.5 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018, including estimated costs for an optional third marine berth. We have the right to terminate the EPC contracts for our convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

We have third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

We have index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent. As of December 31, 2018, we have secured up to approximately 3,464 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent are met.

Additionally, we have transportation and storage service agreements for the Liquefaction Project. The initial term of the transportation agreements ranges up to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The terms of our storage service agreements range up to ten years.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

As of December 31, 2018, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions):



Years Ending December 31,	Payments Due (1)
2019	$	2,465
2020	1,377
2021	1,010
2022	756
2023	641
Thereafter	1,652
Total	$	7,901


(1)	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2018.

Obligations under LNG TUAs

We have a TUA with SPLNG pursuant to which we have reserved approximately 2.0 Bcf/d of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA.

Additionally, we have a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 3, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total’s capacity. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.

Services Agreements

We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 12—Related Party Transactions for additional information regarding this agreement.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 13—Leases.

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 pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 15—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:



	Percentage of Total Revenues from External Customers			Percentage of Accounts Receivable from External Customers
	Year Ended December 31,			December 31,
	2018	2017	2016	2018	2017
Customer A	30%	43%	77%	35%	39%
Customer B	23%	30%	*	23%	32%
Customer C	24%	25%	—%	30%	27%
Customer D	20%	—%	—%	*	—%

* Less than 10%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.



	Revenues from External Customers
	Year Ended December 31,
	2018		2017		2016
United States	$	1,580	$	1,161	$	414
South Korea	1,168		666		—
Ireland	1,098		787		63
India	981		—		23
Other countries	—		21		39
Total	$	4,827	$	2,635	$	539

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in millions):



	Year Ended December 31,
	2018		2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	604	$	438	$	75
Non-cash distributions to affiliates for conveyance of assets	—		—		253

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $256 million, $268 million and $263 million, as of December 31, 2018, 2017 and 2016, respectively.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 17—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:

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



Standard	Description	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 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

SABINE PASS LIQUEFACTION, LLC

SUPPLEMENTAL INFORMATION TO FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Summarized Quarterly Financial Data—(in millions)



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2018:
Revenues	$	1,518		$	1,333		$	1,454		$	1,821
Income from operations	391			339			384			406
Net income	242			193			243			266

Year ended December 31, 2017:
Revenues	$	823		$	925		$	834		$	1,442
Income from operations	145			105			109			422
Net income (loss)	(4		)	(20		)	(12		)	286


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2018, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Financial Statements on page 34 and is incorporated herein by reference.


ITEM 9B.	OTHER INFORMATION

None.

PART III


ITEM 10.	MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE

Omitted pursuant to Instruction I of Form 10-K.


ITEM 11.	EXECUTIVE COMPENSATION

Omitted pursuant to Instruction I of Form 10-K.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS

Omitted pursuant to Instruction I of Form 10-K.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE

Omitted pursuant to Instruction I of Form 10-K.


ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

KPMG LLP served as our independent auditor for the fiscal years ended December 31, 2018 and 2017. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2018 and 2017 (in millions):



	Fiscal 2018		Fiscal 2017
Audit Fees	$	2	$	2

Audit Fees—Audit fees for 2018 and 2017 include fees associated with the audit of our annual Financial Statements, reviews of our interim Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.

Audit-Related Fees—There were no audit-related fees in 2018 and 2017.

Tax Fees—There were no tax fees in 2018 and 2017.

Other Fees—There were no other fees in 2018 and 2017.

Auditor Pre-Approval Policy and Procedures

We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of Cheniere Partners has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2018 and 2017.

PART IV


ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a)	Financial Statements and Exhibits


(1)	Financial Statements—Sabine Pass Liquefaction, LLC:



Management’s Report to the Member of Sabine Pass Liquefaction, LLC	34
Report of Independent Registered Public Accounting Firm	35
Balance Sheets	36
Statements of Operations	37
Statements of Member’s Equity (Deficit)	38
Statements of Cash Flows	39
Notes to Financial Statements	40
Supplemental Information to Financial Statements—Quarterly Financial Data	60


(2)	Financial Statement Schedules:

All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.


(3)	Exhibits:

Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:


•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;


•	may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;


•	may apply standards of materiality that differ from those of a reasonable investor; and


•	were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.



Exhibit No.		Description
3.1		Certificate of Formation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-192373), filed on November 15, 2013)
3.2		First Amended and Restated Limited Liability Company Agreement of the Company (Incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-192373), filed on November 15, 2013)
4.1		Indenture, dated as of February 1, 2013, by and among the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on February 4, 2013)
4.2		Form of 5.625% Senior Secured Note due 2021 (Included as Exhibit A-1 to Exhibit 4.1 above)
4.3		First Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on April 16, 2013)



Exhibit No.		Description
4.4		Second Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on April 16, 2013)
4.5		Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.4 above)
4.6		Third Supplemental Indenture, dated as of November 25, 2013, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on November 25, 2013)
4.7		Form of 6.25% Senior Secured Note due 2022 (Included as Exhibit A-1 to Exhibit 4.6 above)
4.8		Fourth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
4.9		Form of 5.750% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.8 above)
4.10		Fifth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
4.11		Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.10 above)
4.12		Sixth Supplemental Indenture, dated as of March 3, 2015, between the Company and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on March 3, 2015)
4.13		Form of 5.625% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.12 above)
4.14		Seventh Supplemental Indenture, dated as of June 14, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on June 14, 2016)
4.15		Form of 5.875% Senior Secured Note due 2026 (Included as Exhibit A-1 to Exhibit 4.14 above)
4.16		Eighth Supplemental Indenture, dated as of September 19, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
4.17		Ninth Supplemental Indenture, dated as of September 23, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
4.18		Form of 5.00% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.17 above)
4.19		Tenth Supplemental Indenture, dated as of March 6, 2017, between the Company and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on March 6, 2017)
4.20		Form of 4.200% Senior Secured Note due 2028 (Included as Exhibit A-1 to Exhibit 4.19 above)
4.21		Indenture, dated as of February 24, 2017, between the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on February 27, 2017)
4.22		Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit A-1 to Exhibit 4.21 above)
10.1		LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on November 21, 2011)
10.2		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
10.3		Amendment of LNG Sale and Purchase Agreement (FOB), dated January 12, 2017, between the Company (Seller) and Gas Natural Fenosa LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.) (Buyer) (Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)



Exhibit No.		Description
10.4		LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between the Company (Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on December 12, 2011)
10.5		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.18 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
10.6		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between the Company (Seller) and BG Gulf Coast LNG, LLC (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on January 26, 2012)
10.7		Letter agreement, dated May 12, 2016, amending the Amended and Restated LNG Sale and Purchase Agreement (FOB) between the Company and BG Gulf Coast LNG, LLC dated January 25, 2012 (Incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)
10.8		LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between the Company (Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on January 30, 2012)
10.9		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit 10.19 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
10.10		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company (Seller) and Cheniere Marketing, LLC (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-192373), filed on August 11, 2014)
10.11		Letter agreement, dated December 8, 2016, amending the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC) (Incorporated by reference to Exhibit 10.14 to the Company’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 24, 2017)
10.12		Management Services Agreement, dated May 14, 2012, by and between Cheniere Terminals and the Company (Incorporated by reference to Exhibit 10.6 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.13		Amendment to Management Services Agreement, dated September 28, 2015, between Cheniere Terminals and the Company (Incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Company’s Quarterly Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
10.14		Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated May 14, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and the Company (Incorporated by reference to Exhibit 10.5 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.15		Assignment and Assumption Agreement (Sabine Pass Liquefaction O&M Agreement), dated as of November 20, 2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.76 to Amendment No. 4 to Cheniere Holdings’ Registration Statement on Form S-1/A (SEC File No. 333-191298), filed on December 2, 2013)
10.16		Amendment to Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated September 28, 2015, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Investments, LLC and the Company (Incorporated by reference to Exhibit 10.7 to Amendment No. 1 to the Company’s Quarterly Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
10.17		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K/A (SEC File No. 001-33366), filed on July 1, 2015)
10.18		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00001 Currency and Fuel Provisional Sum Adjustment, dated June 25, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)



Exhibit No.		Description
10.19		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00002 Credit to EPC Contract Value for TSA Work, dated September 17, 2015 (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on October 30, 2015)
10.20		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00003 Perimeter Fencing Scope Removal, East Meter Piping Scope Change, Additional Bathroom Facilities, dated November 18, 2015 (Incorporated by reference to Exhibit 10.45 to the Company’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 19, 2016)
10.21		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00004 DOE Regulation Change Impacts, RECON Schedule Change, Addition of Dry Flare Connection, Fuel Gas Supply Transfer to Train 5 and East Meter Fuel Gas, dated February 18, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 5, 2016)
10.22		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00005 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated March 16, 2016, (ii) the Change Order CO-00006 Additional Bechtel Hours to Support RECON, Temporary Access Rd., Addition of Flash Liquid Expander, Removal of Vibration Monitor System, To-Date Reconciliation of Soils Preparation Provisional Sum, dated March 22, 2016, (iii) the Change Order CO-00007 Additional Support for FERC Document Requests, dated May 10, 2016, (iv) the Change Order CO-00008 Water System Scope Changes and Seal Design & Seal Gas Modification, dated May 4, 2016, (v) the Change Order CO-00009 Re-Orientation of PSV Bypass Valves, dated May 17, 2016 and (vi) the Change Order CO-00010 Deletion of Chlorine Analyzer, dated June 15, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on August 9, 2016)
10.23		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00011 Site Drainage Design Change: Professional Service Hours, dated July 26, 2016 (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 3, 2016)
10.24		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Addition of Check Valves to Condensate Lines and Change of Tie-in Point, dated September 12, 2016, (ii) the Change Order CO-00013 LNG Rundown Line Reroute, dated September 12, 2016, (iii) the Change Order CO-00014 Pre-EPC HAZOP Action Item Closure, dated September 27, 2016, (iv) the Change Order CO-00015 Study for Enclosed Ground Flare and Process Flare, dated September 27, 2016, (v) the Change Order CO-00016 Upgrades to Gas Turbine Generators, dated October 19, 2016 and (vi) the Change Order CO-00017 Site Drainage Design Change: Temporary Drainage Implementation, dated December 1, 2016 (Incorporated by reference to Exhibit 10.59 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)
10.25		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00018 Stage 3 Process Flare Modification, dated March 10, 2017, (ii) the Change Order CO-00019 Site Drainage Design Change: Permanent Drainage Implementation, dated March 10, 2017 and (iii) the Change Order CO-00020 Soils Provisional Sum Partial True-up RECON 2, dated March 13, 2017 (Incorporated by reference to Exhibit 10.64 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-218646), filed on June 9, 2017)
10.26		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00021 Soils Preparation Provisional Sum Partial True-Up RECON 3, dated August 24, 2017 (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 9, 2017)



Exhibit No.		Description
10.27		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00022 OSHA Handrail and Guardrail Modifications, dated October 24, 2017, (ii) the Change Order CO-00023 Operating Spare Part Provisional Sum Closeout, dated October 31, 2017 and (iii) the Change Order CO-00024, dated November 28, 2017 (Incorporated by reference to Exhibit 10.27 to the Company’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 21, 2018)
10.28		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00025 BOG and LNG Rundown, dated January 19, 2018, (ii) the Change Order CO-00026 Design Analysis of Existing East & West Jetty Piping and Structure for Simultaneous Loading, dated February 1, 2018, (iii) the Change Order CO-00027 Performance and Attendance Bonus (PAB) Transfer from Stage 2, dated February 1, 2018, and (iv) the Change Order CO-00028 Existing Jetty Structural Steel Supply, dated February 27, 2018 (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 4, 2018)
10.29		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00029 Existing Jetty Structural Steel Analysis – Tanks 104 & 105, dated March 28, 2018, (ii) the Change Order CO-00030 Train 5 JT Valve PV-16002 Internals Modification, Eaton Switchgear Bus Repairs & Inspection Isometrics, dated April 18, 2018, (iii) the Change Order CO-00031 Blind and Spacer Set for Feed Gas Header, dated April 18, 2018 and (iv) the Change Order CO-00032 Additional GTG Testing, dated April 18, 2018 (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Registration Statement on S-4 (SEC File No. 333-225684), filed on June 15, 2018)
10.30		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00033 System Inspection Isometrics, dated May 24, 2018, (ii) the Change Order CO-00034 Site Evacuation, dated May 31, 2018, (iii) the Change Order CO-00035 Stage 3 - Existing & Stages 1 and 2 Liquefaction Facility Labor Provisional Sum True-Up, dated June 7, 2018 and (iv) the Change Order CO-00036 General Electric, Instrument and Valve Spares, dated June 7, 2018 (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on August 9, 2018)
10.31*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00037 Soils Preparation Provisional Sum Closeout, dated November 29, 2018
10.32		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-192373), filed on November 9, 2018)
10.33		Second Amended and Restated LNG Terminal Use Agreement, dated as of July 31, 2012, between the Company and SPLNG (Incorporated by reference to Exhibit 10.1 to SPLNG’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.34		Letter Agreement, dated May 28, 2013, by and between the Company and SPLNG (Incorporated by reference to Exhibit 10.1 to SPLNG’s Quarterly Report on Form 10-Q (SEC File No. 333-138916), filed on August 2, 2013)
10.35		Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among the Company, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.36		Omnibus Amendment, dated as of September 24, 2015, to the Second Amended and Restated Common Terms Agreement among the Company, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.6 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October 30, 2015)
10.37		Administrative Amendment to the Second Amended and Restated Common Terms Agreement, dated as of December 31, 2015, among the Company, Société Générale, as the Commercial Banks Facility Agent, The Korea Development Bank, New York Branch, as the KSURE Covered Facility Agent and Shinhan Bank New York Branch, as KEXIM Facility Agent (Incorporated by reference to Exhibit 10.7 to Cheniere Partners’ Quarterly Report on Form 10-Q (File No. 001-33366), filed on May 5, 2016)



Exhibit No.		Description
10.38		Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, among the Company, as Borrower, The Bank of Nova Scotia, as Senior Issuing Bank and Senior Facility Agent, ABN Amro Capital USA LLC, HSBC Bank USA, National Association and ING Capital LLC, as Senior Issuing Banks, Société Générale, as Swing Line Lender and Common Security Trustee, and the senior lenders party thereto from time to time (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 11, 2015)
10.39		Third Omnibus Amendment, dated as of May 23, 2018 to (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, by and among the Company, Société Générale, as the Common Security Trustee and as the Intercreditor Agent, The Bank of Nova Scotia, and each other party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, by and among the Company, Société Générale as the Swing Line Lender and as the Common Security Trustee, The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent and the other agents and lenders from time to time party thereto (Incorporated by reference to Exhibit 10.3 to Cheniere Partners’ Registration Statement on Form S-4 (SEC File No. 333-225684) filed on June 15, 2018)
10.40		Fourth Omnibus Amendment, dated as of September 17, 2018, to (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, by and among the Company, as Borrower, Société Générale, as the Common Security Trustee and as the Intercreditor Agent, The Bank of Nova Scotia, as the Secured Debt Holder Group Representative for the Working Capital Debt and other Secured Debt Holder Group Representatives party thereto from time to time, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, by and among the Company, as Borrower, Société Générale as the Swing Line Lender and as the Common Security Trustee, The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent and the other agents and lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 8, 2018)
10.41		Tax Sharing Agreement, dated as of August 9, 2012, by and between Cheniere and the Company (Incorporated by reference to Exhibit 10.30 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-192373), filed on November 15, 2013)
31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.


ITEM 16.	FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	SABINE PASS LIQUEFACTION, LLC

	By:	/s/ Jack A. Fusco
		Jack A. Fusco
		Chief Executive Officer (Principal Executive Officer)
	Date:	February 25, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ Doug Shanda	Manager and President	February 25, 2019
Doug Shanda	Manager and President	February 25, 2019

/s/ Michael J. Wortley	Manager and Chief Financial Officer (Principal Financial Officer)	February 25, 2019
Michael J. Wortley		February 25, 2019

/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 25, 2019
Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 25, 2019

/s/ John-Paul Munfa	Manager	February 25, 2019
John-Paul Munfa	Manager	February 25, 2019