Sabine Pass Liquefaction, LLC - FORM 10-K

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EX-32.2 - EXHIBIT 32.2 - Sabine Pass Liquefaction, LLC	exhibit322spl2017form10-k.htm
EX-32.1 - EXHIBIT 32.1 - Sabine Pass Liquefaction, LLC	exhibit321spl2017form10-k.htm
EX-31.2 - EXHIBIT 31.2 - Sabine Pass Liquefaction, LLC	exhibit312spl2017form10-k.htm
EX-31.1 - EXHIBIT 31.1 - Sabine Pass Liquefaction, LLC	exhibit311spl2017form10-k.htm
EX-10.27 - EXHIBIT 10.27 - Sabine Pass Liquefaction, LLC	exhibit1027spl2017form10-k.htm

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, 2017

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

For the transition period from to

Commission File No. 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 ¨ 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 Exchange Act. Yes ¨ No x

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 x No ¨

Note: The registrant was a voluntary filer until April 13, 2017. 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x No ¨

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 Exchange Act. (Check one):



Large accelerated filer ¨			Accelerated filer ¨
Non-accelerated filer x (Do not check if a smaller reporting company)			Smaller reporting company ¨
			Emerging growth company ¨

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 Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ 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	20
Item 3. Legal Proceedings	21
Item 4. Mine Safety Disclosure	21
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	22
Item 6. Selected Financial Data	22
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A. Quantitative and Qualitative and Disclosures about Market Risk	35
Item 8. Financial Statements and Supplementary Data	36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A. Controls and Procedures	64
Item 9B. Other Information	64
PART III
Item 10. Directors, Executive Officers and Company Governance	65
Item 11. Executive Compensation	65
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	65
Item 13. Certain Relationships and Related Transactions, and Manager Independence	65
Item 14. Principal Accountant Fees and Services	65
PART IV
Item 15. Exhibits and Financial Statement Schedules	66
Item 16. Form 10-K Summary	70
Signatures	71

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

Company Abbreviations



Cheniere		Cheniere Energy, Inc.
Cheniere Holdings		Cheniere Energy Partners LP Holdings, LLC
Cheniere Investments		Cheniere Energy Investments, LLC
Cheniere Marketing		Cheniere Marketing International LLP
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.” 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 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,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” 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. 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.

iii

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 under construction 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 and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. 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 Holdings, which is, in turn, an 82.7% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses.

Our Business Strategy

Our primary objective is to generate steady and reliable revenues and operating cash flows 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; and


•	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. The following table summarizes the status of Train 5 of the Liquefaction Project as of December 31, 2017:



	Train 5
Overall project completion percentage	83.1%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	63.4%
Construction	62.1%
Date of expected substantial completion	1H 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 1,511 Bcf/yr).

Customers

We have entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. 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 LNG available to BG is expected to commence approximately one year after the date of first commercial delivery for the respective Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.6 billion for Trains 1 through 3, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 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 (India) Limited; and


•	approximately $450 million from Gas Natural Fenosa LNG GOM, Limited (“Gas Natural Fenosa”), which is guaranteed by 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, 2017, revenues from external customers that were derived from domestic customers was $1.1 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $414 million and from customers outside of the United States was $125 million. 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.

During the year ended December 31, 2017, three customers, BG, Gas Natural Fenosa 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, one customer, BG, individually accounted for more than 10% of our total third-party revenues at 77%.

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 volatility 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, 2017, we have secured up to approximately 2,214 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 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.

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, 2017. 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.

Final Investment Decision on Train 6

We will contemplate making an FID to commence construction of Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, 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 20 years after May 2016. 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 has the right to use our reserved capacity under the TUA and has 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. The percentage of the TUA Fees payable by Cheniere Investments and by us varied based upon the number of Trains that had reached commercial operations.

The following table shows the percentages of all TUA Fees payable to SPLNG by Cheniere Investments and us in accordance with the TURA:



Period	Percentage of TUA Fees Payable by Investments	Percentage of TUA Fees Payable by SPL
Prior to May 2016 (substantial completion of Train 1)	100%	0%
May 2016 - September 2016 (substantial completion of Train 2)	75%	25%
September 2016 - March 2017 (substantial completion of Train 3)	50%	50%
March 2017 - October 2017 (substantial completion of Train 4)	25%	75%
Thereafter	0%	100%

Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. During the year ended December 31, 2017, we recorded operating and maintenance expense—affiliate of $190 million for the TUA Fees and cost of sales—affiliate of $23 million for cargo loading services incurred under the TUA. During the year ended December 31, 2016, we recorded operating and maintenance expense—affiliate of $61 million for the TUA Fees and cost of sales—affiliate of $5 million 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. 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 year ended December 31, 2017, we recorded $23 million 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, 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 are subject to 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 application for revision of the Sabine Pass LNG terminal’s Section 10/404 Permit to authorize construction of Trains 1 through 4 was submitted in January 2011. The process included a public comment period which commenced in March 2011 and closed in April 2011. The revised Section 10/404 Permit 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. In addition, a Section 10/404 Permit application is pending with respect to the expansion of the Creole Trail Pipeline. These permits will require us to provide mitigation to compensate for the wetlands impacted by the respective projects. The application to amend the Sabine Pass LNG terminal’s existing Title V and PSD Permits to authorize construction of Trains 1 through 4 was initially submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public hearing in August 2011. The final revised Title V and PSD Permits were issued by the LDEQ in December 2011. Although these permits are final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the EPA object to the Title V Permit. The EPA has not ruled on this petition. In June 2012, we applied to the LDEQ for a further amendment to the Title V and PSD Permits to reflect proposed modifications to the Liquefaction Project that were filed with the FERC in October 2012. The LDEQ issued the amended PSD and Title V Permits in March 2013. These permits are final. In September 2013, we applied to the LDEQ for an amendment to our PSD and Title V Permits seeking approval to, among other things, construct and operate Trains 5 and 6. The LDEQ issued the amended PSD and Title V Permit in June 2015. These permits are final. In October 2016, we applied to the LDEQ for another amendment to our PSD and Title V Permits to reflect certain facility modifications, updated emissions and as-built capacity factors. The LDEQ issued the amended PSD and Title V Permits in September 2017. These permits are final.

In August 2014, the Sabine Pass LNG terminal’s existing wastewater discharge permit was modified by LDEQ to authorize the discharge of wastewaters from the liquefaction facilities. In December 2017, further modification of this permit was granted to include wastewaters generated with respect to the anticipated operations of Trains 5 and 6.

The Sabine Pass LNG terminal is subject to Hazardous Materials Safety Administration safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security.

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. As required by the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the regulatory provisions of the Dodd-Frank Act. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its rulemakings through additional interpretations and supplemental rulemakings.

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.

Under the Commodity Exchange Act as amended by the Dodd-Frank Act, the CFTC is directed generally to prevent manipulation of or fraud involving financial instruments, such as futures, options and swaps, on any commodity, including contracts for sale of physical commodities such as physical energy. 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. The Dodd-Frank Act’s swaps regulatory provisions and the related rules may adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, increase the costs of entering into and maintaining swaps, adversely affect our ability to execute our hedging strategies and impact the liquidity of certain swaps products, all of which could increase our business costs.

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 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 (“EGUs”) 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. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. 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 may be 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 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.

Market Factors and Competition

The Liquefaction Project currently does not experience competition with respect to Trains 1 through 5. We have entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties that will utilize substantially all of the liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.

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 nine fixed price, 20-year third-party SPAs 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 2016 and 2025, with LNG’s share growing from about 10% currently to about 15% of the global gas market. Wood Mackenzie forecasts that global demand for LNG will increase by 65%, from approximately 255 mtpa, or 12.2 Tcf, in 2016, to approximately 422 mtpa, or 20.3 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with approximately 386 mtpa in 2025, resulting in a market need for construction of additional facilities capable of producing an incremental 36.4 mtpa of LNG. We believe Train 6 is competitive with new proposed projects globally and is 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. To date, 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, 2018, 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, 2018, Cheniere and its subsidiaries had 1,230 full-time employees, including 455 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. We electronically file our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with the SEC.


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, 2017, we had zero cash and cash equivalents, $544 million of current restricted cash and $13.7 billion of total debt outstanding (before premium and net of unamortized debt issuance costs), excluding $730 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 net income of $250 million for the year ended December 31, 2017 and net losses of $193 million and $266 million for the years ended December 31, 2016 and 2015, respectively. 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. 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 on the performance, upon satisfaction of the conditions precedent to payment thereunder, by six third-party customers that have entered into SPAs with us and agreed to pay an aggregate of $2.9 billion annually in fixed fees. 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 would 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. The CFTC also has adopted final rules regarding aggregation of positions that apply to futures on agricultural commodities, under which a party that controls the trading for the account of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions in all such controlled accounts and of all such controlled or owned parties with their own positions for purposes of determining compliance with position limits rules unless an exemption applies. 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 proposed 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.

In making our investment decisions for the Liquefaction Project, we have relied on several economic development programs in Louisiana, including Industrial Tax Exemption (“ITE”) contracts. If we were to lose significant tax incentives through the economic development programs or if the ITE contracts were declared void, the loss of such tax incentives and/or exemptions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We have utilized the ITE program, which is available for a “new” manufacturing establishment or an “addition” to an existing manufacturing establishment. We have entered into a total of nine ITE contracts, which exempt from ad valorem property taxes all of our assets when placed in service.

On October 12, 2016, a lawsuit was filed by JMCB, LLC (“JMCB”) against us, the Louisiana Department of Economic Development (“LED”) and the Louisiana Board of Commerce and Industry (“BCI”) (the “Pending Matter”). In the Pending Matter, JMCB contends that one of our ITE contracts should be declared an improper and unauthorized act of BCI. JMCB asks the court to declare the contract null and void and without legal effect. JMCB’s petition is filed as a class action that seeks declaratory relief for all similarly situated taxpayers in Cameron Parish and for the governmental agencies that would have received the ad valorem property taxes, but for the ITE contract. We believe that the likelihood that the resolution of the Pending Matter will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity or prospects is remote. If we do not prevail in the Pending Matter, the loss of such tax exemption could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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.

We may not be successful in fully implementing our proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities.

It will take several years to construct the Liquefaction Project, and even if successfully constructed, the Liquefaction Project would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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. We do not have any prior experience in constructing liquefaction facilities, and other than Trains 1 through 4 of the Liquefaction Project, as of January 2018, no liquefaction facilities have been constructed and placed in service in the United States in over 40 years. 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. 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, 2018, Cheniere and its subsidiaries had 1,230 full-time employees, including 455 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 damage.

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 nine long-term third-party SPAs 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 will 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 at the Liquefaction Project are, in part, 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, including cyberterrorism, or military campaigns may adversely impact our business.

A terrorist, including a cyberterrorist, 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 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, including cyberterrorism, 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 and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. 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 environmental laws and regulations authorize regulators having jurisdiction over the Sabine Pass LNG terminal 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 related to pollution control equipment 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. In March 2017, President Trump directed EPA via Executive Order to review and determine whether it is appropriate to revise or rescind the Clean Power Plan. 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. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. 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, including a future replacement rule for the Clean Power Plan 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.

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.

Pipeline and Hazardous Materials Safety Administration (“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 undergo analysis, repair and remediation pursuant to the CAO. We are working with PHMSA and other appropriate regulatory authorities to resolve the matters identified in the CAO. We do not expect that the CAO 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,
	2017			2016			2015			2014			2013
Revenues (including transactions with affiliates)	$	4,024		$	833		$	—		$	—		$	—
Income (loss) from operations	781			50			(92		)	(119		)	(136		)
Interest expense, net of capitalized interest	(494		)	(186		)	(36		)	(24		)	(11		)
Net income (loss)	250			(193		)	(266		)	(377		)	(194		)



	December 31,
	2017		2016		2015		2014		2013
Property, plant and equipment, net	$	12,920	$	11,875	$	9,841	$	6,962	$	4,413
Total assets	14,206		12,883		10,433		7,818		5,857
Current debt	—		224		15		—		—
Long-term debt, net	13,477		11,649		9,206		6,390		4,027


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 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 under construction 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 and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG.

Overview of Significant Events

Our significant accomplishments since January 1, 2017 and through the filing date of this Form 10-K include the following:

Operational


•	To date, approximately 300 cumulative LNG cargoes have been produced, loaded and exported from the Liquefaction Project, with over 200 cargoes in 2017 alone, with deliveries completed to 25 countries and regions worldwide.


•	We commenced production and shipment of LNG commissioning cargoes from Train 3 of the Liquefaction Project in January 2017 and achieved substantial completion and commenced operating activities in March 2017.


•	Commissioning activities for Train 4 of the Liquefaction Project began in March 2017, and substantial completion was achieved in October 2017.

Financial


•	In June 2017, the date of first commercial delivery was reached under the 20-year SPA with Korea Gas Corporation relating to Train 3 of the Liquefaction Project.


•	In August 2017, the date of first commercial delivery relating to Train 2 of the Liquefaction Project was reached under the respective 20-year SPAs with Gas Natural Fenosa LNG GOM, Limited and BG Gulf Coast LNG, LLC (“BG”).

•

In February and March 2017, we issued aggregate principal amounts of $800 million of 5.00% Senior Secured Notes due 2037 (the “2037 Senior Notes”) and $1.35 billion, before discount, of 4.200% Senior Secured Notes due 2028 (the “2028 Senior Notes”), respectively. Net proceeds of the offerings of the 2037 Senior Notes and 2028 Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the outstanding borrowings under the credit facilities we entered into in June 2015 (the “2015 Credit Facilities”) and, along with the net proceeds of the 2028 Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 Credit Facilities.


•	Fitch Ratings assigned our senior secured debt an investment grade rating of BBB- in January 2017 and an investment-grade issuer default rating of BBB- in June 2017.


•	In May 2017, Moody’s Investors Service upgraded our senior secured debt rating from Ba1 to Baa3, an investment-grade rating.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at December 31, 2017 and 2016 (in millions):



	December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	544		358
Available commitments under the following credit facilities:
2015 Credit Facilities	—		1,642
$1.2 billion Working Capital Facility (“Working Capital Facility”)	470		653

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		83.1%
Completion percentage of:
Engineering		100%
Procurement		100%
Subcontract work		63.4%
Construction		62.1%
Date of expected substantial completion		1H 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 unable to export during any portion of the initial 20-year export period of such order.

Customers

We have entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. 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 LNG available to BG is expected to commence approximately one year after the date of first commercial delivery for the respective Train.

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

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.

Final Investment Decision on Train 6

We will contemplate making a final investment decision (“FID”) to commence construction of Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct Train 6.

Terminal Use Agreements

The following table shows the percentages of all TUA Fees payable to SPLNG by Cheniere Investments and us in accordance with the TURA:



Period	Percentage of TUA Fees Payable by Investments	Percentage of TUA Fees Payable by us
Prior to May 2016 (substantial completion of Train 1)	100%	0%
May 2016 - September 2016 (substantial completion of Train 2)	75%	25%
September 2016 - March 2017 (substantial completion of Train 3)	50%	50%
March 2017 - October 2017 (substantial completion of Train 4)	25%	75%
Thereafter	0%	100%

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, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. 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 year ended December 31, 2017, we recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Capital Resources

We currently expect that our capital resources requirements with respect to Trains 1 through 5 of 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 $301 million and $201 million in the years ended December 31, 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, during the testing phase for the construction of those Trains of the Liquefaction Project.

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, 2017 and 2016 (in millions):



	December 31,
	2017		2016
Senior notes (1)	$	13,651	$	11,500
Credit facilities outstanding balance (2)	—		537
Letters of credit issued (2)	730		324
Available commitments under credit facilities (2)	470		2,295
Total capital resources from borrowings and available commitments	$	14,851	$	14,656

(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 (the “2025 Senior Notes”), 5.875% Senior Secured Notes due 2026 (the “2026 Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 Senior Notes”), 2028 Senior Notes and 2037 Senior Notes (collectively, the “Senior Notes”).


(2)	Includes 2015 Credit Facilities and Working Capital Facility.

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, 2017, 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.

2015 Credit Facilities

In June 2015, we entered into the 2015 Credit Facilities with commitments aggregating $4.6 billion to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. In February 2017, we issued the 2037 Senior Notes and a portion of the net proceeds was used to prepay the then outstanding borrowings of $369 million under the 2015 Credit Facilities. In March 2017, we issued the 2028 Senior Notes and terminated the remaining available balance of $1.6 billion under the 2015 Credit Facilities.

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, 2017 and 2016, we had $470 million and $653 million of available commitments, $730 million and $324 million aggregate amount of issued letters of credit and zero and $224 million of loans outstanding under the Working Capital Facility, respectively.

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, 2017, 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, 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,
	2017			2016			2015
Operating cash flows	$	657		$	(130	)	$	(207	)
Investing cash flows	(1,279		)	(2,338		)	(2,923		)
Financing cash flows	808			2,637			2,706

Net increase (decrease) in cash, cash equivalents and restricted cash	186			169			(424		)
Cash, cash equivalents and restricted cash—beginning of period	358			189			613
Cash, cash equivalents and restricted cash—end of period	$	544		$	358		$	189

Operating Cash Flows

Our operating cash flows during the years ended December 31, 2017, 2016 and 2015 were an inflow of $657 million, an outflow of $130 million and an outflow of $207 million, respectively. 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, 2017, Trains 1 and 2 were operating for twelve months and Train 3 and Train 4 were operating for nine and three months, respectively, whereas in 2016, Train 1 was operating for seven months and Train 2 was operating for less

than four months. The decrease in operating cash outflows in 2016 compared to 2015 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 commencement of operations of Trains 1 and 2 of the Liquefaction Project.

Investing Cash Flows

Investing cash outflows during the years ended December 31, 2017, 2016 and 2015 were $1.3 billion, $2.3 billion and $2.9 billion, respectively, and were primarily used to fund the construction costs for Trains 1 through 5 of the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the years ended December 31, 2016 and 2015, we used $32 million and $62 million, respectively, primarily for payments to a municipal water district for water system enhancements that will 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 inflows during the year ended December 31, 2017 were $0.8 billion, primarily as a result of:


•	issuances of aggregate principal amounts of $800 million of the 2037 Senior Notes and $1.35 billion of the 2028 Senior Notes;


•	$55 million of borrowings and $369 million of repayments made under the 2015 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 inflows during the year ended December 31, 2016 were $2.6 billion, primarily as a result of:


•	$2.0 billion of borrowings under the 2015 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 2015 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 2015 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, which decreased compared to the contributions received in prior years as a result of utilizing our borrowings instead of equity contributions from Cheniere Partners to finance our capital resource requirements.

Financing cash inflows during the year ended December 31, 2015 were $2.7 billion, primarily as a result of:


•	$860 million of borrowings under the 2015 Credit Facilities;


•	issuance of an aggregate principal amount of $2.0 billion of the 2025 Senior Notes in March 2015;


•	$169 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions; and


•	$15 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, 2017 (in millions):



	Payments Due By Period (1)
	Total		2018		2019 - 2020		2021 - 2022		Thereafter
Debt (2)	$	13,650	$	—	$	—	$	3,000	$	10,650
Interest Payments (2)	5,250		764		1,527		1,228		1,731
Construction obligations (3)	372		293		79		—		—
Purchase obligations (4)	7,714		2,304		2,924		1,317		1,169
Operating lease obligations	7		—		1		1		5
Obligations to affiliates (5)	6,829		367		735		735		4,992
Total	$	33,822	$	3,728	$	5,266	$	6,281	$	18,547


(1)	Agreements in force as of December 31, 2017 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2017.


(2)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017. See Note 10—Debt of our Notes to Financial Statements.


(3)	Construction obligations relate to the EPC contract for Train 5 of the Liquefaction Project. The estimated remaining cost pursuant to our EPC contracts as of December 31, 2017 is included. A discussion of these obligations can be found at Note 13—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 11—Related Party Transactions of our Notes to Financial Statements.

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, 2017, we had $730 million aggregate amount of issued letters of credit under the Working Capital Facility and $544 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 $250 million in the year ended December 31, 2017, compared to a net loss of $193 million in the year ended December 31, 2016. This $443 million increase in net income in 2017 was primarily a result of increased income from operations, which was partially offset by increased interest expense, net of amounts capitalized.

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. The terminal did not sustain significant damage, and the effects of Hurricane Harvey did not have a material impact on our Financial Statements.

Our net loss was $266 million in the year ended December 31, 2015. This $72 million decrease in net loss in 2016 as compared to 2015 was primarily a result of increased income from operations, decreased loss on early extinguishment of debt and decreased derivative loss, net, which was partially offset by increased interest expense, net of amounts capitalized.

Revenues



	Year Ended December 31,
(in millions, except volumes)	2017		2016		Change		2015		Change
LNG revenues	$	2,635	$	539	$	2,096	$	—	$	539
LNG revenues—affiliate	1,389		294		1,095		—		294
Total revenues	$	4,024	$	833	$	3,191	$	—	$	833

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

2017 vs. 2016 and 2016 vs. 2015

We began recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of Train 1 in May 2016. Trains 2, 3 and 4 subsequently achieved substantial completion in September 2016, March 2017 and October 2017, respectively. The increase in revenues for each of the years was attributable to both the increased volume of LNG sold that was recognized as revenues 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 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. We realized offsets to LNG terminal costs of $301 million corresponding to 51 TBtu of LNG and $201 million corresponding to 45 TBtu of LNG in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes.

Operating costs and expenses



	Year Ended December 31,
(in millions)	2017		2016		Change			2015			Change
Cost (cost recovery) of sales	$	2,317	$	416	$	1,901		$	(32	)	$	448
Cost of sales—affiliate	23		7		16			—			7
Operating and maintenance expense	243		72		171			23			49
Operating and maintenance expense—affiliate	329		129		200			1			128
Development expense	2		—		2			3			(3		)
Development expense—affiliate	—		1		(1		)	1			—
General and administrative expense	7		7		—			6			1
General and administrative expense—affiliate	58		68		(10		)	88			(20		)
Depreciation and amortization expense	264		83		181			2			81
Total operating costs and expenses	$	3,243	$	783	$	2,460		$	92		$	691

2017 vs. 2016

Our total operating costs and expenses increased during the year ended December 31, 2017 from the year ended 2016, primarily as a result of additional Trains that were operating between the periods. During the year ended December 31, 2017, Trains 1 and 2 were operating for twelve months and Train 3 and Train 4 were operating for nine and three months, respectively, whereas in 2016, Train 1 was operating for seven months and Train 2 was operating for less than four months.

Cost of sales increased during the year ended December 31, 2017 from the year ended 2016, primarily as a result of the increase in operating Trains during 2017. 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, 2017 from the year ended 2016 was primarily related to the increase in both the volume and pricing of natural gas feedstock. 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, 2017 from the year ended 2016, as a result of the increase in operating Trains during 2017. Operating and maintenance expense includes costs associated with operating and maintaining the Liquefaction Project. The increase during the year ended December 31, 2017 from the year ended 2016 was primarily related to TUA reservation charges paid to SPLNG and to Total due to the commencement of 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, 2017 from the year ended 2016 as a result of 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 achieving substantial completion, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

2016 vs. 2015

Our total operating costs and expenses increased during the year ended December 31, 2016 compared to the year ended December 31, 2015, primarily as a result of the commencement of operations of Trains 1 and 2 of the Liquefaction Project in May and September 2016, respectively.

Cost of sales increased during the year ended December 31, 2016 as a result of the commencement of operations at the Liquefaction Project compared to a cost recovery recognized during the year ended December 31, 2015. This cost recovery was due to a $32 million increase in fair value for our natural gas supply contracts recorded for the period, which we recognized following the completion and placement into service of modifications to the underlying pipeline infrastructure and the resulting development of a market for physical gas delivery at locations specified in a portion of our natural gas supply contracts. Similarly, during the year ended December 31, 2016, we recognized a $68 million increase in fair value of a natural gas supply contract due to the satisfaction of conditions precedent, including completion of relevant pipeline infrastructure, for that contract.

Operating and maintenance expense (including affiliate amounts) increased during the year ended December 31, 2016 as a result of the commencement of operations at the Liquefaction Project. Operating and maintenance expense—affiliate during the year ended December 31, 2016 included $61 million paid to SPLNG under the TUA and $45 million paid to CTPL under natural gas transportation precedent and other agreements. Depreciation and amortization expense increased during the year ended December 31, 2016 as we began depreciation of our assets related to Trains 1 and 2 of the Liquefaction Project upon reaching substantial completion.

Partially offsetting the increases above was a decrease to terminal use agreement maintenance expense of $19 million in the year ended December 31, 2016 compared to the year ended December 31, 2015. This decrease was primarily a result of not needing to import a cargo necessary to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal during the year ended December 31, 2016. During the year ended December 31, 2015, we incurred our proportionate share of the costs of the cargo imported in order to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which we are required to reimburse pursuant to our TUA with SPLNG.

G&A Expense—affiliate decreased during the year ended December 31, 2016 compared to the year ended December 31, 2015. This decrease was primarily a result of reallocation of resources from general and administrative activities to operating and maintenance activities following commencement of operations at the Liquefaction Project. Development expense decreased during the year ended December 31, 2016 compared to the year ended December 31, 2015, due to an FID made on Train 5 of the Liquefaction Project in June 2015.

Other expense (income)



	Year Ended December 31,
(in millions)	2017			2016			Change			2015		Change
Interest expense, net of capitalized interest	$	494		$	186		$	308		$	36	$	150
Loss on early extinguishment of debt	42			52			(10		)	96		(44		)
Derivative loss, net	2			6			(4		)	42		(36		)
Other income	(7		)	(1		)	(6		)	—		(1		)
Total other expense	$	531		$	243		$	288		$	174	$	69

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 premium, discount and unamortized 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, 2017, we incurred $779 million of total interest cost, of which we capitalized $285 million, which was directly related to the construction of the Liquefaction Project. For the year ended December 31, 2016, we incurred $649 million of total interest cost, of which we capitalized $463 million, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt decreased during the year ended December 31, 2017, as compared to the year ended December 31, 2016. Loss on early 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 2015 Credit Facilities in connection with the issuance of the 2028 Senior Notes. Loss on early 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 2015 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 2015 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, partially offset by the $7 million loss in March 2017 upon the settlement of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under the 2015 Credit Facilities.

2016 vs. 2015

Interest expense, net of capitalized interest, increased during the year ended December 31, 2016 compared to the year ended December 31, 2015 due to an increase in our indebtedness outstanding (before premium and unamortized debt issuance costs), from $9.4 billion as of December 31, 2015 to $12.0 billion as of December 31, 2016, and a decrease in the portion of total interest costs that could be capitalized as Trains 1 and 2 of the Liquefaction Project were no longer in construction. For the year ended December 31, 2016, we incurred $650 million of total interest cost, of which we capitalized $463 million, which was directly related to the construction of the Liquefaction Project. For the year ended December 31, 2015, we incurred $531 million of total interest cost, of which we capitalized $495 million, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt increased during the year ended December 31, 2016, as compared to the year ended December 31, 2015. Loss on early extinguishment of debt during the year ended December 31, 2016 was attributable to the write-off of debt issuance costs and payment of fees related to the $2.6 billion prepayment of outstanding borrowings and termination of commitments under the 2015 Credit Facilities in connection with the issuance of the 2026 Senior Notes and the 2027 Senior Notes. Loss on early extinguishment of debt during the year ended December 31, 2015 was attributable to the write-off of debt issuance costs and deferred commitment fees in connection with the termination of approximately $1.8 billion of commitments under our previous credit facilities in March 2015 and the replacement of our previous credit facilities with the 2015 Credit Facilities in June 2015.

Derivative loss, net decreased during the year ended December 31, 2016 compared to the year ended December 31, 2015, primarily due to a $35 million loss recognized in March 2015 upon the termination of interest rate swaps associated with our previous credit facilities.

Off-Balance Sheet Arrangements

As of December 31, 2017, 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 interest rate swaps, financial commodity derivative contracts transacted in an over-the-counter market and index-based physical commodity contracts. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. 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.

Impairment of Long-Lived Assets

A long-lived asset, including an intangible asset, is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may not be recoverable. 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 use a variety of fair value measurement approaches when market information for the same or similar assets does not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 16—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 to secure natural gas feedstock for 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, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	55	$	5	$	73	$	6

Interest Rate Risk

We had entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under our 2015 Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in millions):



	December 31, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
Interest Rate Derivatives	$	—	$	—	$	(6	)	$	2

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	37
Report of Independent Registered Public Accounting Firm	38
Balance Sheets	39
Statements of Operations	40
Statements of Member’s Equity (Deficit)	41
Statements of Cash Flows	42
Notes to Financial Statements	43
Supplemental Information to Financial Statements—Summarized Quarterly Financial Data	63

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, 2017, 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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

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 20, 2018

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)



	December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	—		$	—
Restricted cash	544			358
Accounts and other receivables	189			90
Accounts receivable—affiliate	163			100
Advances to affiliate	26			26
Inventory	85			89
Other current assets	54			25
Other current assets—affiliate	21			10
Total current assets	1,082			698

Property, plant and equipment, net	12,920			11,875
Debt issuance costs, net	18			58
Non-current derivative assets	17			67
Other non-current assets, net	169			185
Total assets	$	14,206		$	12,883

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	8		$	23
Accrued liabilities	606			407
Current debt	—			224
Due to affiliates	66			33
Deferred revenue	84			46
Derivative liabilities	—			11
Total current liabilities	764			744

Long-term debt, net	13,477			11,649
Non-current derivative liabilities	3			2
Other non-current liabilities—affiliate	—			2

Commitments and contingencies (see Note 13)

Member’s equity (deficit)	(38		)	486
Total liabilities and member’s equity (deficit)	$	14,206		$	12,883

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

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in millions)



	Year Ended December 31,
	2017			2016			2015
Revenues
LNG revenues	$	2,635		$	539		$	—
LNG revenues—affiliate	1,389			294			—
Total revenues	4,024			833			—

Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	2,317			416			(32		)
Cost of sales—affiliate	23			7			—
Operating and maintenance expense	243			72			23
Operating and maintenance expense—affiliate	329			129			1
Development expense	2			—			3
Development expense—affiliate	—			1			1
General and administrative expense	7			7			6
General and administrative expense—affiliate	58			68			88
Depreciation and amortization expense	264			83			2
Total operating costs and expenses	3,243			783			92

Income (loss) from operations	781			50			(92		)

Other income (expense)
Interest expense, net of capitalized interest	(494		)	(186		)	(36		)
Loss on early extinguishment of debt	(42		)	(52		)	(96		)
Derivative loss, net	(2		)	(6		)	(42		)
Other income	7			1			—
Total other expense	(531		)	(243		)	(174		)

Net income (loss)	$	250		$	(193	)	$	(266	)

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
Balance at December 31, 2014	$	1,272		$	1,272
Capital contributions from Cheniere Partners	15			15
Non-cash distributions to affiliates	(90		)	(90		)
Net loss	(266		)	(266		)
Balance at December 31, 2015	931			931
Capital contributions from Cheniere Partners	1			1
Non-cash distributions to affiliates	(253		)	(253		)
Net loss	(193		)	(193		)
Balance at December 31, 2016	486			486
Capital contributions from Cheniere Partners	7			7
Distributions to Cheniere Partners	(781		)	(781		)
Net income	250			250
Balance at December 31, 2017	$	(38	)	$	(38	)

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,
	2017			2016			2015
Cash flows from operating activities
Net income (loss)	$	250		$	(193	)	$	(266	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash terminal use agreement maintenance expense	—			—			18
Depreciation and amortization expense	264			83			2
Amortization of debt issuance costs, deferred commitment fees, premium and discount	19			12			2
Loss on early extinguishment of debt	42			52			96
Total losses (gains) on derivatives, net	26			(36		)	7
Net cash used for settlement of derivative instruments	(14		)	(7		)	(42		)
Changes in operating assets and liabilities:
Accounts and other receivables	(99		)	(90		)	—
Accounts receivable—affiliate	(63		)	(99		)	—
Advances to affiliate	(13		)	1			(4		)
Inventory	11			(60		)	(4		)
Accounts payable and accrued liabilities	190			179			(5		)
Due to affiliates	22			1			6
Deferred revenue	38			46			—
Other, net	(4		)	(10		)	—
Other, net—affiliate	(12		)	(9		)	(17		)
Net cash provided by (used in) operating activities	657			(130		)	(207		)

Cash flows from investing activities
Property, plant and equipment, net	(1,279		)	(2,306		)	(2,861		)
Other	—			(32		)	(62		)
Net cash used in investing activities	(1,279		)	(2,338		)	(2,923		)

Cash flows from financing activities
Proceeds from issuances of debt	2,314			5,443			2,860
Repayments of debt	(703		)	(2,765		)	—
Debt issuance and deferred financing costs	(29		)	(42		)	(169		)
Capital contributions from Cheniere Partners	7			1			15
Distributions to Cheniere Partners	(781		)	—			—
Net cash provided by financing activities	808			2,637			2,706

Net increase (decrease) in cash, cash equivalents and restricted cash	186			169			(424		)
Cash, cash equivalents and restricted cash—beginning of period	358			189			613
Cash, cash equivalents and restricted cash—end of period	$	544		$	358		$	189

Balances per Balance Sheets:



	December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash	544		358
Total cash, cash equivalents and restricted cash	$	544	$	358

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 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. 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 Holdings, which is, in turn, an 82.7% 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 under construction 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 and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying Financial Statements of SPL 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.

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 value 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.

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 our 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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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

Fees received pursuant to SPAs are recognized as LNG revenues 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. LNG revenues are recognized when LNG is delivered to the customer, either at the Sabine Pass LNG terminal or at the customer’s LNG receiving terminal, based on the terms of the contract.

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 bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

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 lease is obtained, the costs are expensed.

We capitalize interest and other related debt costs during the construction period of a Train. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset.

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. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.

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 record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015, respectively.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and 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, 2017, 2016 and 2015. 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. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 as other current asset. 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 six fixed price SPAs with terms of at least 20 years with six unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—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. 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 method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the 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 Sheet. Debt issuance costs are amortized to interest expense or property, plant and

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 early 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. Our assessment of AROs is described below.

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, 2017, the tax basis of our assets and liabilities was $2.4 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 11—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.

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, 2017 and 2016, restricted cash consisted of the following (in millions):



	December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	544	$	358

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):



	December 31,
	2017		2016
Trade receivable	$	185	$	88
Other accounts receivable	4		2
Total accounts and other receivables	$	189	$	90

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 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):



	December 31,
	2017		2016
Natural gas	$	17	$	15
LNG	26		45
Materials and other	42		29
Total inventory	$	85	$	89

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):



	December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	9,963		$	5,270
LNG terminal construction-in-process	3,283			6,675
Accumulated depreciation	(330		)	(75		)
Total LNG terminal costs, net	12,916			11,870
Fixed assets
Fixed assets	10			9
Accumulated depreciation	(6		)	(4		)
Total fixed assets, net	4			5
Property, plant and equipment, net	$	12,920		$	11,875

Depreciation expense was and $257 million, $77 million and $2 million in the years ended December 31, 2017 and 2016, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 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 of the Liquefaction Project, during the testing phase for its construction.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, 2017 and 2016, 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, 2017								December 31, 2016
	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
Interest Rate Derivatives liability	$	—	$	—	$	—	$	—	$	—		$	(6	)	$	—	$	(6	)
Liquefaction Supply Derivatives asset (liability)	2		10		43		55		(4		)	(2		)	79		73

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using 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 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 portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:



	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$43	Market approach incorporating present value techniques	Basis Spread	$(0.503) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017			2016			2015
Balance, beginning of period	$	79		$	32		$	—
Realized and mark-to-market gains (losses):
Included in cost of sales (1)	(37		)	48			32
Purchases and settlements:
Purchases	14			1			—
Settlements (1)	(12		)	(2		)	—
Transfers out of Level 3	(1		)	—			—
Balance, end of period	$	43		$	79		$	32
Change in unrealized gains relating to instruments still held at end of period	$	(37	)	$	49		$	32


(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.

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 “2015 Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2015 Credit Facilities. In March 2017, we settled the Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 Credit Facilities, as discussed in Note 10—Debt.

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



		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2017		December 31, 2016
Interest Rate Derivatives	Derivative liabilities	$	—	$	(4	)
Interest Rate Derivatives	Non-current derivative liabilities	—		(2		)

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017			2016			2015
Interest Rate Derivatives loss	$	(2	)	$	(6	)	$	(42	)

Liquefaction Supply Derivatives

We have entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, 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, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	41		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	17			67
Liquefaction Supply Derivatives	Derivative liabilities	—			(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(3		)	—


(1)	Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Balance Sheets as of December 31, 2017 and 2016, respectively.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):



		Year Ended December 31,
	Statement of Operations Location (1)	2017		2016			2015
Liquefaction Supply Derivatives loss (gain) (2)	Cost of sales	$	24	$	(42	)	(43	)


(1)	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.


(2)	Does not include the realized value associated with derivative instruments that settle through physical delivery.

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, 2017
Liquefaction Supply Derivatives	$	64		$	(6	)	$	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
As of December 31, 2016
Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):



	December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	26	$	23
Advances made to municipalities for water system enhancements	93		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	1		3
Information technology service assets	19		22
Other	—		11
Total other non-current assets, net	$	169	$	185

NOTE 9—ACCRUED LIABILITIES

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):



	December 31,
	2017		2016
Interest costs and related debt fees	$	230	$	204
Liquefaction Project costs	376		203
Total accrued liabilities	$	606	$	407

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 10—DEBT

As of December 31, 2017 and 2016, our debt consisted of the following (in millions):



	December 31,
	2017			2016
Long-term debt
5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”), net of unamortized premium of $6 and $7	$	2,006		$	2,007
6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”), net of unamortized premium of $5 and $6	1,505			1,506
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”), net of unamortized discount of $1 and zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”)	800			—
2015 Credit Facilities	—			314
Unamortized debt issuance costs	(183		)	(178		)
Total long-term debt, net	13,477			11,649

Current debt
$1.2 billion Working Capital Facility (“Working Capital Facility”)	—			224
Total debt, net	$	13,477		$	11,873

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, 2017 (in millions):



Years Ending December 31,	Principal Payments
2018	$	—
2019	—
2020	—
2021	2,000
2022	1,000
Thereafter	10,650
Total	$	13,650

Senior Notes

In February 2017, we issued an aggregate principal amount of $800 million of the 2037 Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, we issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 Senior Notes. Net proceeds of the offerings of the 2037 Senior Notes and the 2028 Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 Credit Facilities and, along with the net proceeds of the 2028 Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 Credit Facilities.

In connection with the issuance of the 2037 Senior Notes and the 2028 Senior Notes, we terminated the remaining available balance of $1.6 billion under the 2015 Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 Credit Facilities of $42 million during the year ended December 31, 2017.

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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, 2017, we were in compliance with all covenants related to the Senior Notes. Interest on the Senior Notes is payable semi-annually in arrears.

Working Capital Facility

Below is a summary of our Working Capital Facility as of December 31, 2017 (in millions):



	Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	730
Available commitment	$	470

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

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.

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, 2017, 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.

The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2017, 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,
	2017			2016			2015
Total interest cost	$	779		$	649		$	531
Capitalized interest	(285		)	(463		)	(495		)
Total interest expense, net	$	494		$	186		$	36

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):



	December 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,860	$	13,955	$	11,513	$	12,309
2037 Senior Notes (2)	800		871		—		—
Credit facilities (3)	—		—		538		538


(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.


(3)	Includes 2015 Credit Facilities and Working Capital Facility. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 11—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, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017		2016		2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	1,389	$	294	$	—

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

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

Development expense—affiliate
Services Agreements	—		1		1

General and administrative expense—affiliate
Services Agreements	58		68		88

LNG Terminal-Related Agreements

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 20 years after May 2016. 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 has the right to use our reserved capacity under the TUA and has 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. The following table shows the percentages of all TUA Fees payable to SPLNG by Cheniere Investments and us in accordance with the TURA:



Period	Percentage of TUA Fees Payable by Investments	Percentage of TUA Fees Payable by us
Prior to May 2016 (substantial completion of Train 1)	100%	0%
May 2016 - September 2016 (substantial completion of Train 2)	75%	25%
September 2016 - March 2017 (substantial completion of Train 3)	50%	50%
March 2017 - October 2017 (substantial completion of Train 4)	25%	75%
Thereafter	0%	100%

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.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, we executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

We have an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on our behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of our SPA customers. We pay a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

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 both December 31, 2017 and 2016, we had $26 million of advances to affiliates 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.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 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 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 and $81 million of assets for the years ended December 31, 2016 and 2015, respectively, which were recorded as non-cash distributions to affiliates. We did not convey any assets to SPLNG under this agreement during the year ended December 31, 2017.

Contract for Sale and Purchase of Natural Gas and LNG

We have an agreement with SPLNG that allows us to sell and purchase natural gas and LNG with SPLNG. Natural gas and LNG purchased under this agreement 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 12—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $3 million, $2 million and $1 million, respectively, related primarily to land sites for the Liquefaction Project. In June 2012, we

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

entered into an agreement with SPLNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. See Note 11—Related Party Transactions for additional information regarding this sublease agreement.

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



Years ending December 31,	Operating Leases (1)
2018 through 2022	$	2
Thereafter	5
Total	$	7


(1)	Includes certain lease option renewals that are reasonably assured.

NOTE 13—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, 2017, are not recognized as liabilities but require disclosures in our Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

We have a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that we will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order. We have the right to terminate the EPC contract 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 primarily range from approximately one to six years and commence upon the occurrence of conditions precedent, including our declaration to the respective natural gas supplier that we are ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the Liquefaction Project. As of December 31, 2017, we have secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, we have transportation and storage service agreements for the Liquefaction Project. The initial term of the transportation agreements ranges from one 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 from three to ten years.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

As of December 31, 2017, 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)
2018	$	2,274
2019	1,527
2020	1,397
2021	981
2022	336
Thereafter	1,169
Total	$	7,684


(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, 2017.

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 11—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. 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 11—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 11—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 12—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, 2017, 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 14—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:



	Percentage of Total Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
		Year Ended December 31,			December 31,
		2017	2016	2015	2017	2016
Customer A		43%	77%	—%	39%	47%
Customer B		30%	*	—%	32%	50%
Customer C		25%	—%	—%	27%	—%

* Less than 10%

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2017		2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	438	$	75	$	—
Non-cash distributions to affiliates for conveyance of assets	—		253		91
Non-cash conveyance of assets to non-affiliate	—		—		13

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $268 million, $263 million and $228 million, as of December 31, 2017, 2016 and 2015, respectively.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 16—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:



Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
ASU 2016-02, Leases (Topic 842)	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 must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, or which, if any, practical expedients we will elect upon transition.
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	We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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

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

Year ended December 31, 2016:
Revenues	$	—		$	85		$	265		$	483
Income (loss) from operations	(30		)	(29		)	(15		)	124
Net income (loss)	(47		)	(87		)	(104		)	45


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 Securities Exchange Act of 1934, as amended (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, 2017, 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 37 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, 2017 and 2016. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2017 and 2016 (in millions):



	Fiscal 2017		Fiscal 2016
Audit Fees	$	2	$	2

Audit Fees—Audit fees for 2017 and 2016 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 2017 and 2016.

Tax Fees—There were no tax fees in 2017 and 2016.

Other Fees—There were no other fees in 2017 and 2016.

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, 2017 and 2016.

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	37
Report of Independent Registered Public Accounting Firm	38
Balance Sheets	39
Statements of Operations	40
Statements of Member’s Equity (Deficit)	41
Statements of Cash Flows	42
Notes to Financial Statements	43
Supplemental Information to Financial Statements—Quarterly Financial Data	63


(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
10.28		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)
10.29		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)
10.3		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)
10.31		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 20, 2018

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 20, 2018
Doug Shanda	Manager and President	February 20, 2018

/s/ Michael J. Wortley	Manager and Chief Financial Officer (Principal Financial Officer)	February 20, 2018
Michael J. Wortley		February 20, 2018

/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 20, 2018
Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 20, 2018

/s/ John-Paul Munfa	Manager	February 20, 2018
John-Paul Munfa	Manager	February 20, 2018

Description

Date of Adoption

Effect on our Financial Statements or Other Significant Matters

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory

This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.

January 1, 2017

The adoption of this guidance did not have a material impact on our Financial Statements or related disclosures.