Sabine Pass Liquefaction, LLC - FORM 10-K

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - Sabine Pass Liquefaction, LLC	exhibit311spl2015form10-k.htm
EX-32.1 - EXHIBIT 32.1 - Sabine Pass Liquefaction, LLC	exhibit321spl2015form10-k.htm
EX-31.2 - EXHIBIT 31.2 - Sabine Pass Liquefaction, LLC	exhibit312spl2015form10-k.htm
EX-32.2 - EXHIBIT 32.2 - Sabine Pass Liquefaction, LLC	exhibit322spl2015form10-k.htm
EX-10.32 - EXHIBIT 10.32 - Sabine Pass Liquefaction, LLC	exhibit1032spl2015form10-k.htm
EX-10.45 - EXHIBIT 10.45 - Sabine Pass Liquefaction, LLC	exhibit1045spl2015form10-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, 2015

¨ 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 x No ¨

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 ¨ No x

Note: As of January 1, 2016, the registrant is a voluntary filer not subject to the filing requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.

Indicate by check mark whether the registrant has submitted electronically 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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



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

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	19
Item 3. Legal Proceedings	19
Item 4. Mine Safety Disclosure	19
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	20
Item 6. Selected Financial Data	20
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A. Quantitative and Qualitative and Disclosures about Market Risk	30
Item 8. Financial Statements and Supplementary Data	31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
Item 9A. Controls and Procedures	60
Item 9B. Other Information	60
PART III
Item 10. Directors, Executive Officers and Company Governance	62
Item 11. Executive Compensation	62
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	62
Item 13. Certain Relationships and Related Transactions, and Manager Independence	62
Item 14. Principal Accountant Fees and Services	62
PART IV
Item 15. Exhibits and Financial Statement Schedules	63
Signatures	70

DEFINITIONS

As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this annual report, the terms listed below have the following meanings:

Common Industry and Other Terms



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 consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
non-FTA countries		countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC		Securities and Exchange Commission
SPA		LNG sale and purchase agreement
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, LLC and subsidiaries
Cheniere Partners		Cheniere Energy Partners, L.P.
Cheniere Terminals		Cheniere LNG Terminals, LLC
CTPL		Cheniere Creole Trail Pipeline, L.P.
SPLNG		Sabine Pass LNG, L.P.

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

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical facts, 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 proposed natural gas liquefaction project, or any expansions 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 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 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 liquefaction or storage capacities that are, or may become, subject to contracts;


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


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


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


•	statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues and capital expenditures, 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 fact, 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 due to 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 publicly update or revise any forward-looking statement, 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 existing regasification facilities owned and operated by SPLNG. We are constructing five Trains and developing a sixth Train, each of which is expected to have a nominal production capacity of approximately 4.5 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 55.9% owned subsidiary of Cheniere Holdings, which is, in turn, an 80.1% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses.

LNG is 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. 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 justify economically the use of LNG. LNG is transported using large oceangoing LNG tankers specifically constructed for this purpose. LNG regasification facilities offload LNG from LNG tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market.

Our Business Strategy

Our primary objective is to generate stable cash flows by:


•	completing construction and commencing operation of the first five Trains of the Liquefaction Project;


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


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


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

Our Liquefaction Project

Our Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. The Sabine Pass LNG terminal is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast and has existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced construction of Train 5 and the related facilities.

The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA countries for a 20-year term. The DOE further issued an order authorizing us to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. Our application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries is currently pending at the DOE. Additionally, the DOE issued orders authorizing us to export up to a combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term. A party to the proceeding requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/yr, and the DOE has not yet issued a final ruling on the rehearing request. 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 5 to 10 years from the date the order was issued. Furthermore, the DOE issued an order authorizing us to export up to 600 Bcf in total of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016.

As of December 31, 2015, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 97.4% and 79.5%, respectively. As of December 31, 2015, the overall project completion percentage for Train 5 of the Liquefaction Project was approximately 14.9% with engineering, procurement and construction approximately 41.9%, 20.5% and 0.1% complete, respectively. As of December 31, 2015, the overall project completion of each of our Trains was ahead of the contractual schedule. We produced our first LNG from Train 1 of the Liquefaction Project in February 2016. Based on our current construction schedule, we anticipate that Train 2 will produce LNG as early as mid-2016 and Trains 3 through 5 are expected to commence operations on a staggered basis thereafter.

The following table summarizes significant milestones and anticipated completion dates in the development of the Liquefaction Project:



		Target Date
Milestone		Trains 1 - 5
DOE export authorization		Received
Definitive commercial agreements		Completed 19.75 mtpa
BG Gulf Coast LNG, LLC		5.5 mtpa
Gas Natural Aprovisionamientos SDG S.A.		3.5 mtpa
Korea Gas Corporation		3.5 mtpa
GAIL (India) Limited		3.5 mtpa
Total Gas & Power North America, Inc.		2.0 mtpa
Centrica plc		1.75 mtpa
EPC contracts		Completed
Financing		Completed
FERC authorization		Completed
Issue Notice to Proceed		Completed
Commence operations		2016 - 2019

Customers

We have entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75 mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5, that commence with the date of first commercial delivery for Trains 1 through 5. Under these SPAs, the customers will purchase LNG from us for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. 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. A portion of the fixed fee will be subject to annual adjustment for inflation. 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 commences upon the start of operations of a specified Train. As of December 31, 2015, we had the following third-party SPAs:

•

BG Gulf Coast LNG, LLC (“BG”) has entered into an SPA that commences upon the date of first commercial delivery for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.25 per MMBtu and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu and 33,500,000 MMBtu upon the date of first commercial delivery for Trains 2, 3 and 4, respectively, with a fixed fee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from fixed fees is approximately $723 million. In addition, we have agreed to make up to 500,000 MMBtu/d of LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.25 per MMBtu, if produced. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales.

•

Gas Natural Aprovisionamientos SDG S.A. (“Gas Natural Fenosa”) has entered into an SPA that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $454 million. In addition, we have agreed to make up to 285,000 MMBtu/d of LNG available to Gas Natural Fenosa to

the extent that Train 2 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.49 per MMBtu, if produced. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A., a company organized under the laws of Spain.


•	Korea Gas Corporation (“KOGAS”) has entered into an SPA that commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. KOGAS is organized under the laws of the Republic of Korea.


•	GAIL (India) Limited (“GAIL”) has entered into an SPA that commences upon the date of first commercial delivery for Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. GAIL is organized under the laws of India.

•

Total Gas & Power North America, Inc. (“Total”) has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 104,750,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $314 million. The obligations of Total are guaranteed by Total S.A., a company organized under the laws of France.


•	Centrica plc (“Centrica”) has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91,250,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $274 million. Centrica is organized under the laws of England and Wales.

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

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 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 agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. We have also entered into enabling agreements and natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2015, we have secured up to approximately 2,154.2 million MMBtu of natural gas feedstock through natural gas purchase agreements.

Natural Gas Storage Services

For our natural gas storage requirements, we have entered into firm storage services agreements with third parties. The storage services agreements will assist us in managing volatility in natural gas needs for the Liquefaction Project.

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, 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 prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract for Train 5 of the Liquefaction Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through December 31, 2015. 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 $17.0 billion and $18.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

During the third quarter of 2015, CTPL completed construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal.

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 the Train.

Terminal Use Agreement

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, continuing until at least 20 years after we deliver our first commercial cargo at the Liquefaction Project. 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 make the monthly capacity payments required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal will be reduced as each of Trains 1 through 4 reaches commercial operation. The percentage of the monthly capacity payments payable by Cheniere Investments will be reduced from 100% to zero (unless Cheniere Investments utilizes terminal use capacity after Train 4 reaches commercial operations), and the percentage of the monthly capacity payments payable by us will increase by the amount that Cheniere Investments’ percentage decreases. Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA.

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 our cost of operations and construction, and failure to comply with such laws could result in substantial penalties.

Federal Energy Regulatory Commission

The design, construction and operation of our liquefaction facilities and the export of LNG are highly regulated activities. The FERC’s approval under Section 3 of the Natural Gas Act of 1938, as amended (the “NGA”), as well as several other material governmental and regulatory approvals and permits, are required in order to site, construct and operate our liquefaction facilities.

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 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. 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 LNG production capacity of Trains 1 through 4 from the currently authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity. 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 denied 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, and that appeal is still pending. 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 April 2015.

Several other material governmental and regulatory approvals and permits will be required prior to construction and operation of the Liquefaction Project. In addition, the FERC authorization requires us to obtain certain additional FERC 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 our liquefaction facilities, we and SPLNG will be subject to regular reporting requirements to the FERC, the U.S. Department of Transportation and applicable state regulatory agencies regarding the operation and maintenance of our facilities.

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.

DOE Export License

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 import LNG now or will do so by 2016 include Chile, Mexico, Singapore, South Korea and the Dominican Republic. 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 other federal agencies, including the DOE, 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 (“Title V”) Operating Permit and the Prevention of Significant Deterioration (“PSD”) Permit, the latter two permits being 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 Train 1 through Train 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. An application for a further revision to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, was received from the USACE in June 2015. The USACE acted in the capacity as a cooperating agency in the FERC’s NEPA review process. 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 Train 1 through Train 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, Cheniere Partners 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, Cheniere Partners applied to the LDEQ for another amendment to its 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 permits in June 2015. 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, including wastewaters generated with respect to the anticipated operations of Trains 5 and 6.

The Sabine Pass LNG terminal is subject to U.S. Department of Transportation 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”) provides 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 certain classes of swaps 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) establish position limits on certain swaps and futures products, 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, although neither the CFTC nor the SEC has yet adopted or implemented all of the rules required by the Dodd-Frank Act. In addition, the CFTC and its staff regularly issue rule amendments and guidance, policy statements and letters interpreting or taking no-action positions, including time-limited no action positions, regarding the derivatives provisions of the Dodd-Frank Act and the rules of the CFTC under these provisions.

A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules imposing new position limits on futures contracts, options contracts and economically equivalent physical commodity 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 proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain core futures contracts and economically equivalent futures contracts, options contracts 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 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, six classes of over-the-counter (“OTC”) interest rate and 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 any other classes of swaps, including swaps relating to physical commodities, for mandatory clearing, 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 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 variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from commercial end users who qualify for the end user exception from the mandatory clearing requirement or certain other counterparties. We expect to qualify as such a commercial end user with respect to the swaps that we enter into to hedge our commercial risks. The Dodd-Frank Act’s swaps regulatory provisions and the

related rules may also 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, 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.

Under the Commodity Exchange Act as amended by the Dodd-Frank Act, the CFTC is directed generally to prevent manipulation, including by fraudulent or deceptive practices, in two markets: (1) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (2) financial instruments, such as futures, options and swaps. 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 or deceptive schemes in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to a CFTC enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

Environmental Regulation

The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit 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 the construction and operation of our liquefaction facilities, 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 fuel combustion sources as well as all fugitive emissions throughout LNG terminals. From time to time, Congress has considered proposed legislation directed at reducing GHG emissions, and the EPA has defined GHG emissions thresholds for requiring certain permits for new and existing industrial sources. 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, financial position, operating results and cash flows.

Coastal Zone Management Act (“CZMA”)

The Liquefaction Project is subject to the review and possible requirements of the CZMA throughout the construction of facilities located within the coastal zone. 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 disposal of solid and hazardous wastes. 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

Endangered Species Act

The Liquefaction Project may be restricted by requirements under the Endangered Species Act, which seeks to protect endangered or threatened animal, fish and plant species and designated habitats.

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, 20-year SPAs 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 has entered into eight 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.

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, including 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, economic growth in developing countries, investment in energy infrastructure, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and access to 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 23 Tcf between 2013 and 2025, with LNG increasing its current share of approximately ten percent of the global market. Wood Mackenzie forecasts that global demand for LNG will increase by 72%, from approximately 245 mtpa, or 11.9 Tcf, in 2015, to 421 mtpa, or 20.5 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with 365 mtpa in 2025, resulting in a market need for construction of additional facilities capable of producing an incremental 56 mtpa of LNG. We believe our new project that does not already have capacity sold under long-term contracts is competitive and well-positioned to capture a portion of this incremental market need.

We have limited exposure, particularly in the LNG terminal business for our five Trains under construction, to the decline in oil prices, even if it persists for more than 12 months, 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 approximately 19.75 mtpa of aggregate production capacity for Trains 1 through 5 of the Liquefaction Project with third-party customers. Train 6 has not been contracted to date. As of January 31, 2016, oil and gas futures 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, 2016, Cheniere and its subsidiaries had 888 full-time employees, including 488 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 flow, 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, negative operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects.

As of December 31, 2015, we had zero cash and cash equivalents, approximately $189 million of current and non-current restricted cash and $9.4 billion of total debt outstanding (before premium), excluding $135.2 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 substantial 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, the re-pricing 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 were 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 losses of $265.6 million, $376.9 million and $194.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, we have never had positive operating cash flow. 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. We currently expect that we will not begin to receive cash flows from operations under any SPA until early 2016, at the earliest. Any delays beyond the expected development period for Train 1 would prolong, and could increase the level of, 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

positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete 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 also 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.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal regulation of the over-the-counter (“OTC”) derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (“CFTC”), the SEC and other federal regulators 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 proposed new rules setting limits on the positions in certain core futures contracts, economically equivalent futures contracts, options contracts and swaps for or linked to certain physical commodities, including Henry Hub natural gas, held by market participants, with limited exemptions for certain bona fide hedging and other types of transactions. Under the CFTC’s proposed rules regarding aggregation of positions, a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled party with its own positions for purposes of determining compliance with position limits unless an exemption applies. Upon the adoption and effectiveness of final CFTC

position limits and aggregation rules, 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 and aggregation 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. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. 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. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. The requirements of those rules are to be phased in commencing on September 1, 2016. Although we believe we will qualify as a non-financial end user for purposes of these rules, were we not to do so and have 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, 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 regulatory requirements on swaps market participants, including swap dealers and other swaps entities as well as certain regulations on end users of swaps, including regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and other swaps entities. Together with the Basel III capital requirements on certain swaps market participants, these regulations 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, 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.

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 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 impact 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 do not have any prior experience in constructing liquefaction facilities, and 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.

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 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 counterparties.

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. 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 complete our business plan and our business may ultimately be unsuccessful.

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 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 coast, and the Sabine Pass LNG terminal experienced minor damage.

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 our liquefaction facilities 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 an order under Section 3 of the NGA authorizing the siting, construction and operation of six Trains, the FERC order requires us to obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We also have a pending application with the DOE for authorization to export LNG to non-FTA countries in addition to the orders previously granted to us by the DOE. Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We cannot control the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not 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, 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, financial condition, operating results, 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, 2016, Cheniere and its subsidiaries had 888 full-time employees, including 488 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 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. 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 personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs.

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 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 terminal use agreement 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 has entered into eight 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 terminates 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 applicable liquefaction facility, 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 applicable liquefaction facility 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, financial condition, operating results, liquidity and prospects.

We will 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, financial condition, operating results, 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 deliver 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 delivery 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 will be 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 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 exported LNG, natural gas or alternative energy sources, which may reduce the demand for 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 prices of LNG and 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 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 will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than LNG exported to these 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 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-United States 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, which may become available at a lower cost in certain markets.

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 could adversely affect the ability of our customers to deliver LNG from the United States 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 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 our liquefaction project on commercially reasonable terms;


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


•	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 and have an option for firm capacity for Train 6. 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 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. 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.

The Obama Administration is pursuing a number of regulatory and policy initiatives to reduce GHG emissions in the United States from a variety of sources. For example, 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. Other federal and state initiatives are being considered or may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, a carbon emissions tax, or cap-and-trade programs. Such initiatives could affect the demand for or cost of natural gas, which we consume at the Sabine Pass LNG terminal, 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 through the Sabine-Neches Waterway less than four miles from the Gulf Coast, 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

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, 2015, 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.


ITEM 4.	MINE SAFETY DISCLOSURE

None.

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 (in thousands) are derived from our audited Financial Statements for the periods indicated. 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,
	2015			2014			2013			2012			2011
Revenues	$	—		$	—		$	—		$	—		$	—
Operating costs and expenses (including transactions with affiliates)	91,632			119,179			135,660			85,783			36,511
Loss from operations	(91,632		)	(119,179		)	(135,660		)	(85,783		)	(36,511		)
Loss on early extinguishment of debt	(96,273		)	(114,335		)	(131,576		)	—			—
Net loss	(265,617		)	(376,853		)	(194,490		)	(85,157		)	(36,511		)



	December 31,
	2015		2014		2013		2012		2011
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash (current)	189,260		155,810		192,144		75,133		—
Non-current restricted cash	—		457,053		867,590		196,319		—
Property, plant and equipment, net	9,841,407		6,962,395		4,412,580		1,228,720		279
Total assets	10,587,931		7,945,745		5,941,972		1,710,380		1,390
Current debt, net	15,000		—		—		—		—
Long-term debt	9,360,110		6,517,266		4,111,562		100,000		—
Total member’s equity (deficit)	931,287		1,272,401		1,638,265		1,467,239		(46,380		)


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 in “Financial Statements and Supplementary Data.” 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 existing regasification facilities owned and operated by SPLNG. We are constructing five Trains and developing a sixth Train, each of which is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG.

Overview of Significant Events

Our significant accomplishments since January 1, 2015 and through the filing date of this Form 10-K include the following:


•	We issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 Senior Notes”). Net proceeds from the offering will be used to pay a portion of the capital costs associated with the construction of the first four Trains of the Liquefaction Project.


•	We received authorization from the FERC to site, construct and operate Trains 5 and 6 of the Liquefaction Project.


•	We received authorization from the DOE to export up to a combined total of the equivalent of 503.3 Bcf/yr of domestically produced LNG by vessel from Trains 5 and 6 of the Liquefaction Project to non-FTA countries for a 20-year term.


•	We entered into a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 5 of the Liquefaction Project (the “EPC Contract (Train 5)”).


•	We entered into four credit facilities (collectively, the “2015 Credit Facilities”) aggregating $4.6 billion, which terminated and replaced our existing credit facilities. The 2015 Credit Facilities will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project.


•	We issued a notice to proceed to Bechtel under the EPC Contract (Train 5).

•

We entered into a $1.2 billion Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “Working Capital Facility”), which replaced the $325.0 million senior letter of credit and reimbursement agreement that was entered into in April 2014 (the “LC Agreement”). The Working Capital Facility will be used primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of December 31, 2015, we had zero cash and cash equivalents and $189.3 million of current and non-current restricted cash.

Liquefaction Facilities

Our Liquefaction Project is being developed and constructed 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 commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced construction of Train 5 and the related facilities.

Customers

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.

All of our long-lived assets for each of the years ended December 31, 2015, 2014 and 2013 are located in the United States. We did not have any revenues in the years ended December 31, 2015, 2014 and 2013.

Construction

We have entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5, 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 prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC Contract (Train 5) of the Liquefaction Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through December 31, 2015. 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 $17.0 billion and $18.0 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 the Train.

Terminal Use 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 one or more of the following: borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the 2015 Credit Facilities, available commitments under the Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We currently project that we will generate cash flow from the Liquefaction Project by early 2016.

Senior Secured Notes

As of December 31, 2015, we had five series of senior secured notes outstanding:


•	$2.0 billion of 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”);


•	$1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 Senior Notes”);


•	$1.5 billion of 5.625% Senior Secured Notes due 2023 (the “2023 Senior Notes”);


•	$2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Senior Notes” and collectively with the 2021 Senior Notes, the 2022 Senior Notes, the 2023 Senior Notes and the 2025 Senior Notes, the “Senior Notes”); and


•	$2.0 billion of the 2025 Senior Notes.

Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in us 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, we may redeem all or part of such series of the Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the Senior Notes (the “Indenture”), 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, 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.

Under the Indenture, we may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

The Indenture includes 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, the 2015 Credit Facilities and the Working Capital Facility.

2015 Credit Facilities

In June 2015, we entered into the 2015 Credit Facilities with commitments aggregating $4.6 billion. The 2015 Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. Borrowings under the 2015 Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of December 31, 2015, we had $3.8 billion of available commitments and outstanding borrowings of $845.0 million under the 2015 Credit Facilities.

Loans under the 2015 Credit Facilities accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on the applicable 2015 Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each quarter. In addition, we are required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 Credit Facilities. The 2015 Credit Facilities also require us to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 Credit Facility. The principal of the loans made under the 2015 Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 Credit Facilities.

The 2015 Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. Our obligations under the 2015 Credit Facilities 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 and the Working Capital Facility.

Under the terms of the 2015 Credit Facilities, we are required to hedge not less than 65% of the variable interest rate exposure of our projected outstanding borrowings, calculated on a weighted average basis in comparison to our anticipated draw of principal. Additionally, we may not make any distributions until substantial completion of Trains 1 and 2 of the Liquefaction Project has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.

2013 Credit Facilities

In May 2013, we entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Credit Facilities”) to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project, which amended and restated the existing credit facility that was entered into in 2012 (the “2012 Credit Facility”). In June 2015, the 2013 Credit Facilities were replaced with the 2015 Credit Facilities.

In March 2015, in conjunction with our issuance of the 2025 Senior Notes, we terminated approximately $1.8 billion of commitments under the 2013 Credit Facilities. This termination and the replacement of the 2013 Credit Facilities with the 2015 Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Credit Facilities of $96.3 million for the year ended December 31, 2015. The amendment and restatement of the 2012 Credit Facility with the 2013 Credit Facilities in May 2013 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2012 Credit Facility of $88.3 million during the year ended December 31, 2013.

Working Capital Facility

In September 2015, we entered into the $1.2 billion Working Capital Facility, which replaced the $325.0 million LC Agreement. The Working Capital Facility is intended to be used for loans (“Working Capital Loans”), the issuance of letters of credit (“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, 2015, we had $1.1 billion of available commitments, $135.2 million aggregate amount of issued Letters of Credit, $15.0 million in Working Capital Loans and no Swing Line Loans or loans deemed made in connection with a draw upon a Letter of Credit (“LC Loans” and collectively with Working Capital Loans and Swing Line Loans, the “Working Capital Facility Loans”) outstanding under the Working Capital Facility. As of December 31, 2014, we had issued letters of credit in an aggregate amount of $9.5 million, and no draws had been made upon any letters of credit issued under the LC Agreement.

Working Capital Facility Loans 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 Working Capital Facility Loans is 1.75% per annum, and the applicable margin for base rate Working Capital Facility Loans is 0.75% per annum. Interest on Swing Line Loans and LC Loans is due and payable on the date the loan becomes due. Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

We incurred $27.5 million of debt issuance costs in connection with the Working Capital Facility. 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, 2015, 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. 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 and the 2015 Credit Facilities.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash and cash equivalents (in thousands) for the years ended December 31, 2015, 2014 and 2013. 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,
	2015			2014			2013
Sources of cash and cash equivalents
Proceeds from issuances of debt	$	2,860,000		$	2,584,500		$	4,112,500
Use of restricted cash for the acquisition of property, plant and equipment	2,923,034			2,587,565			3,092,025
Capital contributions from Cheniere Partners	15,297			11,734			338,276
Total sources of cash and cash equivalents	5,798,331			5,183,799			7,542,801
Uses of cash and cash equivalents
Investment in restricted cash	(2,706,662		)	(2,316,547		)	(4,041,372		)
Property, plant and equipment, net	(2,861,000		)	(2,548,855		)	(3,082,195		)
Repayments of debt	—			(177,000		)	(100,000		)
Debt issuance and deferred financing costs	(168,635		)	(102,687		)	(309,404		)
Other	(62,034		)	(38,710		)	(9,830		)
Total uses of cash and cash equivalents	(5,798,331		)	(5,183,799		)	(7,542,801		)

Net increase (decrease) in cash and cash equivalents	—			—			—
Cash and cash equivalents-beginning of period	—			—			—
Cash and cash equivalents-end of period	$	—		$	—		$	—

Proceeds from Issuances of Debt, Debt Issuance and Deferred Financing Costs and Repayments of Debt

In March 2015, we issued an aggregate principal amount of $2.0 billion of the 2025 Senior Notes. In June 2015, we entered into the 2015 Credit Facilities aggregating $4.6 billion, which terminated and replaced the 2013 Credit Facilities, and borrowed $845.0 million under this facility during the year ended December 31, 2015. In September 2015, we entered into the $1.2 billion Working Capital Facility which replaced the LC Agreement, and borrowed $15.0 million in Working Capital Loans during the year ended December 31, 2015. Debt issuance and deferred financing costs in the year ended December 31, 2015 primarily relate to up-front fees paid upon the closing of these transactions.

In May 2014, we issued an aggregate principal amount of $2.0 billion of the 2024 Senior Notes and an additional $0.5 billion principal amount of the 2023 Senior Notes for total net proceeds of approximately $2.5 billion. Debt issuance costs in the year ended December 31, 2014 primarily relate to up-front fees paid upon the closing of these offerings.

During 2013, we issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Senior Notes and $1.0 billion of each of the 2023 Senior Notes and the 2022 Senior Notes. Net proceeds from those offerings were used to pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project. In June 2013, we borrowed $100.0 million under the 2013 Credit Facilities. Debt issuance and deferred financing costs in the year ended December 31, 2013 primarily related to up-front fees paid by us upon the closing of the 2013 Credit Facilities and the senior notes issued by us during the year.

Use of Restricted Cash for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment, net

During the years ended December 31, 2015, 2014 and 2013, we used $2,923.0 million, $2,587.6 million and $3,092.0 million, respectively, of restricted cash for investing activities to partially fund $2,861.0 million, $2,548.9 million and $3,082.2 million, respectively, of construction costs for Trains 1 through 5 of the Liquefaction Project. The costs associated with the construction of Trains 1 through 5 of the Liquefaction Project are capitalized as construction-in-process.

Capital Contributions from Cheniere Partners

During the years ended December 31, 2015, 2014 and 2013, we received equity contributions from Cheniere Partners in amounts totaling $15.3 million, $11.7 million and $338.3 million, respectively. The decrease in equity contributions in the years ended December 31, 2015 and 2014 compared to the year ended December 31, 2013 is a result of utilizing our borrowings instead of equity contributions from Cheniere Partners to finance our capital resource requirements.

Investment in Restricted Cash

In the year ended December 31, 2015, we invested $2,706.7 million in restricted cash primarily related to the net proceeds from the 2025 Senior Notes and borrowings under the 2015 Credit Facilities and Working Capital Facility, net of deferred financing costs. In the year ended December 31, 2014, we invested $2,316.5 million in restricted cash, primarily related to the net proceeds from the notes issued by us during the year. In the year ended December 31, 2013, we invested $4,041.4 million in restricted cash, primarily related to the net proceeds from the notes issued by us during the year and from contributions from Cheniere Partners.

Other

During the years ended December 31, 2015, 2014 and 2013, we used $62.0 million, $38.7 million and $9.8 million, respectively, of cash in other activities primarily as a result of payments made to a municipal water district for water system enhancements that will increase potable water supply to our Sabine Pass LNG terminal and investments made in unconsolidated entities.

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 thousands) in place as of December 31, 2015:



	Payments Due By Period (1)
	Total		2016		2017 - 2018		2019 - 2020		Thereafter
Construction obligations (2)	$	2,701,566	$	1,543,647	$	1,070,003	$	87,916	$	—
Purchase obligations (3)	3,183,260		432,284		679,133		535,430		1,536,413
Debt (4)	9,360,000		15,000		—		845,000		8,500,000
Interest Payments (4)	3,840,520		541,169		1,082,041		1,082,180		1,135,130
Operating lease obligations	7,213		395		792		631		5,395
Obligations to affiliates (5)	17,905		941		1,885		1,885		13,194
Total	$	19,110,464	$	2,533,436	$	2,833,854	$	2,553,042	$	11,190,132


(1)	Agreements in force as of December 31, 2015 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2015.


(2)	Construction obligations primarily relate to the EPC contracts for Trains 1 through 5 of the Liquefaction Project. The estimated remaining costs pursuant to our EPC contracts as of December 31, 2015 is included. A discussion of these obligations can be found at Note 12—Commitments and Contingencies of our Notes to Financial Statements.


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


(4)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2015. See Note 9—Debt of our Notes to Financial Statements.


(5)	Obligations to affiliates relate to land subleased from SPLNG for the Liquefaction Project. Obligations arising through intercompany service agreements include only fixed fees and do not include variable fees or TUA fees with SPLNG. A discussion of these obligations can be found in Note 10—Related Party Transactions of our Notes to Financial Statements.

(6)

In addition, in the ordinary course of business, we maintain letters of credit and have certain cash restricted in support of certain performance obligations of our subsidiaries. As of December 31, 2015, we had $135.2 million aggregate amount of issued Letters of Credit under the Working Capital Facility and $189.3 million of current and non-current restricted cash. For more information, see Note 3—Restricted Cash of our Notes to Financial Statements.

Results of Operations

2015 vs. 2014

Our net loss decreased $111.3 million, from $376.9 million in the year ended December 31, 2014, to $265.6 million in the year ended December 31, 2015. The decrease in net loss was primarily a result of decreased derivative loss, net, decreased operating and maintenance expense and decreased loss on early extinguishment of debt, partially offset by increased general and administrative expense (“G&A Expense”) (including affiliate amounts) and increased interest expense, net of amounts capitalized.

Derivative loss, net decreased $77.7 million, from $119.4 million in the year ended December 31, 2014, to $41.7 million in the year ended December 31, 2015. The derivative loss recognized during the year ended December 31, 2014 was attributable to a decrease in long-term LIBOR during that period, whereas the movement in long-term LIBOR had a minimal effect on derivative loss for the year ended December 31, 2015 as a result of a lower notional amount of interest rate derivatives. Instead of movement in long-term LIBOR rates, the $41.7 million derivative loss recognized during the year ended December 31, 2015 was primarily attributable to the loss recognized in March 2015 upon the termination of interest rate swaps associated with approximately $1.8 billion of commitments that were terminated under the 2013 Credit Facilities.

Operating and maintenance expense (income) decreased $33.1 million in the year ended December 31, 2015, as compared to the year ended December 31, 2014, due to a $32.2 million increase in fair value for our natural gas purchase agreements recorded during the third quarter of 2015, which we recognized following the completion and placement into service of certain 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 purchase agreements. Excluding this amount, operating and maintenance expense would have been $4.3 million during the year ended December 31, 2015, which is comparable to $5.2 million incurred during the year ended December 31, 2014.

Loss on early extinguishment of debt decreased $18.0 million, from $114.3 million in the year ended December 31, 2014, to $96.3 million in the year ended December 31, 2015. 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 the 2013 Credit Facilities in March 2015 and the replacement of the 2013 Credit Facilities with the 2015 Credit Facilities in June 2015. Loss on early extinguishment of debt during the year ended December 31, 2014 was attributable to the write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 Credit Facilities in May 2014.

Partially offsetting the above decreases in expenses, G&A Expense (including affiliate amounts) increased $16.9 million in the year ended December 31, 2015, as compared to the year ended December 31, 2014, primarily due to costs of services provided by Cheniere pursuant to an information technology services agreement. Additionally, interest expense, net of amounts capitalized, increased $12.4 million in the year ended December 31, 2015, as compared to the year ended December 31, 2014, primarily as a result of an increase in our indebtedness outstanding as of December 31, 2015 compared to December 31, 2014. For the years ended December 31, 2015 and 2014, we incurred $531.5 million and $397.9 million of total interest cost, respectively, of which we capitalized and deferred $495.1 million and $374.0 million, respectively.

2014 vs. 2013

Our net loss increased $182.4 million, from $194.5 million in the year ended December 31, 2013, to $376.9 million in the year ended December 31, 2014. The increase in net loss was primarily a result of increased derivative loss, net and increased interest expense, partially offset by decreased general and administrative expense—affiliate and decreased loss on early extinguishment of debt.

Derivative loss, net increased $202.2 million, from $82.8 million gain in the year ended December 31, 2013 to $119.4 million loss in the year ended December 31, 2014, primarily as a result of a decrease in long-term LIBOR during the year ended December 31, 2014, as compared to an increase in long-term LIBOR during the year ended December 31, 2013, and the settlement of interest rate swaps in connection with the early extinguishment of a portion of the 2013 Credit Facilities in May 2014. Interest expense, net increased $13.1 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of interest costs related to additional debt issued in 2014. For the years ended December 31, 2014 and 2013, we incurred $397.9 million and $241.3 million of total interest cost, respectively, of which we capitalized and deferred $374.0 million and $230.5 million, respectively, of interest expense, including amortization of debt issuance costs, related to the construction of Trains 1 through 4 of the Liquefaction Project.

General and administrative expense—affiliate decreased $22.0 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of decreased costs incurred to manage the construction of Trains 1 through 4 of the Liquefaction Project, which resulted from a management services agreement in which we are required to pay a monthly fee based upon the capital expenditures incurred in the previous month for Trains 1 through 4 of the Liquefaction Project until substantial completion of each Train. Loss on early extinguishment of debt decreased $17.2 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, due to the write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 Credit Facilities in May 2014, as compared to the write-off of debt issuance costs and deferred commitment fees in connection with the early extinguishment of a portion of the commitments under the 2012 Credit Facility in April 2013 and under the 2013 Credit Facilities in November 2013.

Off-Balance Sheet Arrangements

As of December 31, 2015, 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 value of properties, plant and equipment, asset retirement obligations (“AROs”) and fair values. 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.

Fair Value

When necessary or required by GAAP, we estimate fair value for derivatives, long-lived assets for impairment testing, initial measurements of AROs and financial instruments that require fair-value disclosure, including debt. When we are required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, we use the cost, income or market valuation approaches depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve significant judgment and the results are based on expected future events or conditions, such as sales prices, estimates of future LNG production, development, construction and operating costs and the timing thereof, future net cash flows, economic and regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

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 techniques.

Our derivative instruments consist of financial natural gas derivative contracts transacted in an over-the-counter market, index-based physical natural gas contracts and interest rate swaps. Valuation of our financial natural gas derivative contracts is determined using observable commodity price curves and other relevant data. Valuation of our index-based physical natural gas contracts is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace, market transactions and other relevant data. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

Gains and losses on derivative instruments are recognized currently 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 commodity prices and interest rates 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 techniques 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 14—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 purchase agreements to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of our Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural gas for each delivery location. As of December 31, 2015, we estimated the fair value of our Liquefaction Supply Derivatives to be $32.5 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis price would have resulted in a change in the fair value of our Liquefaction Supply Derivatives of $0.9 million as of December 31, 2015, compared to $0.4 million as of December 31, 2014. The increase in the effect of change in the underlying basis price was due to a $32.2 million increase in fair value for our natural gas purchase agreements recorded during the third quarter of 2015, which we recognized following the completion and placement into service of certain modifications to the Creole Trail Pipeline and the resulting development of a market for physical gas delivery at locations specified in a portion of our natural gas purchase agreements. See Note 6—Derivative Instruments for additional details about our derivative instruments.

Interest Rate Risk

We have 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 full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair value of our Interest Rate Derivatives of $3.1 million as of December 31, 2015, compared to $16.5 million as of December 31, 2014. The decrease in the effect of change in interest rates was due to lower notional amounts of Interest Rate Derivatives outstanding and a decrease in the forward 1-month LIBOR curve during the year ended December 31, 2015.


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	32
Report of Independent Registered Public Accounting Firm—KPMG LLP	33
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	34
Balance Sheets	35
Statements of Operations	36
Statements of Comprehensive Loss	37
Statements of Member’s Equity	38
Statements of Cash Flows	39
Notes to Financial Statements	40
Supplemental Information to Financial Statements—Summarized Quarterly Financial Data	59

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, 2015, 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/ R. Keith Teague	By:	/s/ Michael J. Wortley
	R. Keith Teague		Michael J. Wortley
	Manager and President (Principal Executive Officer)		Manager and Chief Financial Officer (Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member

Sabine Pass Liquefaction, LLC:

We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2015 and 2014, and the related statements of operations, comprehensive loss, member’s equity, and cash flows for each of the years in the two-year period ended December 31, 2015. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass Liquefaction, LLC as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 18, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member

Sabine Pass Liquefaction, LLC

We have audited the accompanying statements of operations, comprehensive loss, member’s equity, and cash flows of Sabine Pass Liquefaction, LLC for the year ended December 31, 2013. 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Sabine Pass Liquefaction, LLC for the year ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 21, 2014

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in thousands)



	December 31,
	2015		2014
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	189,260		155,810
Accounts receivable—affiliate	2,457		2,750
Advances to affiliate	28,312		23,969
Inventory	5,742		2,295
Other current assets	6,514		1,246
Other current assets—affiliate	2,475		153
Total current assets	234,760		186,223

Non-current restricted cash	—		457,053
Property, plant and equipment, net	9,841,407		6,962,395
Debt issuance costs, net	286,642		228,913
Non-current derivative assets	30,304		11,744
Other non-current assets	169,005		99,417
Other non-current assets—affiliate	25,813		—
Total assets	$	10,587,931	$	7,945,745

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	13,420	$	5,974
Accrued liabilities	201,559		113,538
Current debt, net	15,000		—
Due to affiliates	53,848		13,051
Derivative liabilities	6,430		23,247
Total current liabilities	290,257		155,810

Long-term debt, net	9,360,110		6,517,266
Non-current derivative liabilities	2,884		268
Other non-current liabilities—affiliate	3,393		—

Commitments and contingencies (see Note 12)

Member’s equity	931,287		1,272,401
Total liabilities and member’s equity	$	10,587,931	$	7,945,745

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

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in thousands)



	Year Ended December 31,
	2015			2014			2013
Revenues	$	—		$	—		$	—

Operating costs and expenses
Operating and maintenance expense (income)	(27,896		)	5,211			(476		)
Operating and maintenance expense—affiliate	1,331			95			—
Terminal use agreement maintenance expense	18,428			25,677			26,228
Terminal use agreement maintenance expense—affiliate	400			387			394
Depreciation and amortization expense	2,479			967			213
Development expense	2,850			9,319			11,540
Development expense—affiliate	722			1,153			1,392
General and administrative expense	5,637			5,305			3,305
General and administrative expense—affiliate	87,681			71,065			93,064
Total expenses	91,632			119,179			135,660

Loss from operations	(91,632		)	(119,179		)	(135,660		)

Other income (expense)
Interest expense, net of capitalized interest	(36,330		)	(23,909		)	(10,796		)
Loss on early extinguishment of debt	(96,273		)	(114,335		)	(131,576		)
Derivative gain (loss), net	(41,722		)	(119,401		)	82,790
Other income (expense)	340			(29		)	752
Total other expense	(173,985		)	(257,674		)	(58,830		)

Net loss	$	(265,617	)	$	(376,853	)	$	(194,490	)

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

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)



	Year Ended December 31,
		2015			2014			2013
Net loss		$	(265,617	)	$	(376,853	)	$	(194,490	)
Other comprehensive income (loss)
Loss on settlements of interest rate cash flow hedges retained in other comprehensive income		—			—			(30		)
Change in fair value of interest rate cash flow hedges		—			—			21,297
Losses reclassified into earnings as a result of discontinuance of cash flow hedge accounting		—			—			5,973
Total other comprehensive income		—			—			27,240
Comprehensive loss		$	(265,617	)	$	(376,853	)	$	(167,250	)

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

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF MEMBER’S EQUITY

(in thousands)



	Sabine Pass LNG-LP, LLC			Accumulated Other Comprehensive Income (Loss)			Total Member’s Equity
Balance at December 31, 2012	$	1,494,479		$	(27,240	)	$	1,467,239
Contributions from Cheniere Partners	338,276			—			338,276
Interest rate cash flow hedges	—			27,240			27,240
Net loss	(194,490		)	—			(194,490		)
Balance at December 31, 2013	1,638,265			—			1,638,265
Capital contributions from Cheniere Partners	11,734			—			11,734
Non-cash distributions to affiliates	(745		)	—			(745		)
Net loss	(376,853		)	—			(376,853		)
Balance at December 31, 2014	1,272,401			—			1,272,401
Capital contributions from Cheniere Partners	15,297			—			15,297
Non-cash distributions to affiliates	(90,794		)	—			(90,794		)
Net loss	(265,617		)	—			(265,617		)
Balance at December 31, 2015	$	931,287		$	—		$	931,287

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

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities
Net loss	$	(265,617	)	$	(376,853	)	$	(194,490	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Non-cash terminal use agreement maintenance expense	16,763			24,461			26,731
Depreciation and amortization expense	2,479			967			2,917
Amortization of debt issuance costs and premium	2,100			—			—
Loss on early extinguishment of debt	96,273			114,335			131,576
Total (gains) losses on derivatives, net	7,377			118,199			(84,299		)
Net cash used for settlement of derivative instruments	(41,756		)	(22,093		)	632
Changes in restricted cash for certain operating activities	207,231			175,853			161,065
Changes in operating assets and liabilities:
Advances to affiliate	(4,342		)	(14,539		)	(5,017		)
Inventory	(3,565		)	(22,963		)	—
Accounts payable and accrued liabilities	(4,967		)	9,234			(167		)
Due to affiliates	6,347			(2,373		)	1,665
Other, net	(960		)	(2,644		)	(39,446		)
Other—affiliate	(17,363		)	(1,584		)	(1,167		)
Net cash provided by (used in) operating activities	—			—			—

Cash flows from investing activities
Property, plant and equipment, net	(2,861,000		)	(2,548,855		)	(3,082,195		)
Use of restricted cash for the acquisition of property, plant and equipment	2,923,034			2,587,565			3,092,025
Other	(62,034		)	(38,710		)	(9,830		)
Net cash provided by (used in) investing activities	—			—			—

Cash flows from financing activities
Proceeds from issuances of debt	2,860,000			2,584,500			4,112,500
Repayments of debt	—			(177,000		)	(100,000		)
Debt issuance and deferred financing costs	(168,635		)	(102,687		)	(309,404		)
Investment in restricted cash	(2,706,662		)	(2,316,547		)	(4,041,372		)
Capital contributions from Cheniere Partners	15,297			11,734			338,276
Net cash provided by (used in) financing activities	—			—			—

Net increase (decrease) in cash and cash equivalents	—			—			—
Cash and cash equivalents—beginning of period	—			—			—
Cash and cash equivalents—end of period	$	—		$	—		$	—

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 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 55.9% owned subsidiary of Cheniere Holdings, which is, in turn, an 80.1% 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 adjacent to the existing regasification facilities. The Sabine Pass LNG terminal is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast and has existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In April 2015, we received authorization from the FERC to site, construct and operate Trains 5 and 6. In June 2015, we commenced construction of Train 5 and the related facilities.

In June 2014, the Financial Accounting Standards Board (the “FASB”) amended its guidance on development stage entities. The amendment removed all incremental financial reporting requirements from GAAP for development stage entities. This guidance is effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted this guidance in the quarterly period ended June 30, 2014. Prior to our adoption of this guidance, we were a development stage entity because we devote substantially all of our efforts to establishing a new natural gas liquefaction business for which planned principal operations have not commenced. The adoption of this guidance did not have a material impact on our financial position, operating results or cash flows other than the removal of inception-to-date information about income statement line items, cash flows and equity transactions.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements were prepared in accordance with GAAP. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall financial position, operating results 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, collectability of accounts receivable, 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 techniques 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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 commodity derivatives and interest-rate derivatives as disclosed in Note 6—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 9—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.

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.

Amounts that are designated as restricted cash are contractually restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. For these amounts, we have presented increases and decreases separately from increases and decreases in cash and cash equivalents in our Statements of Cash Flows. These amounts that represent non-cash transactions within our Statements of Cash Flows present the effect of sources and uses of restricted cash as they relate to the changes to assets and liabilities in our Balance Sheets. Restricted cash is presented on a gross basis within each of those categories so as to reconcile the change in non-cash activity that occurs on the balance sheet from period to period.

Inventory

Inventory is recorded at weighted average cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each period. Terminal use agreement maintenance expense—affiliate represents the amount recorded related to the reimbursement to SPLNG of a portion of its fuel costs related to maintaining the cryogenic readiness of the Sabine Pass LNG terminal.

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, will be amortized over the estimated useful life of the asset.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense 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 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 have recorded no impairments related to property, plant and equipment for 2015, 2014 or 2013.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and interest rate 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. 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 current 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 as of December 31, 2015 and 2014.

In the past, we elected cash flow hedge accounting for derivatives that we used to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge was effective, were recognized in accumulated other comprehensive loss on our Balance Sheets. We reclassified gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Statements of Operations as the hedged item was recognized. Any change in the fair value resulting from ineffectiveness was recognized immediately as derivative gain (loss) on our Statements of Operations. We used regression analysis to determine whether we expected a derivative to be highly effective as a cash flow hedge, prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges had been effective. We performed these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculated the actual amount of ineffectiveness on our cash flow hedges using the “dollar offset” method, which compared changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinued hedge accounting when our effectiveness tests indicated that a derivative was no longer highly effective as a hedge; when the derivative expired or was sold, terminated or exercised; when the hedged item matured, was sold or repaid; or when we determined that the occurrence of the hedged forecasted transaction was not probable. When we discontinued hedge accounting but continued to hold the derivative, prospective changes in fair value of the derivative instrument were recorded in income. Once we concluded that the hedged forecasted transaction became probable of not occurring, the amount remaining in accumulated other comprehensive loss pertaining to the previously designated derivatives was reclassified out of accumulated other comprehensive loss and into income.

See Note 6—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.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 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 an other current asset. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 20-year SPAs with six unaffiliated third parties. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective SPAs.

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 Sheet at par value adjusted for unamortized discount or premium. Discounts, premiums and costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net 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 debt issuance costs on our Balance Sheets and are being amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on 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 recognition of AROs is described below.

Currently, the liquefaction facilities under construction at the Sabine Pass LNG terminal adjacent to the existing regasification facilities are our only long-lived asset. Based on the real property lease agreements and sublease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease and sublease agreements 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 zero. Therefore, we have not recorded an ARO associated with the liquefaction facilities at the Sabine Pass LNG terminal.

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, 2015, the tax basis of our assets and liabilities was $311.2 million more 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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 10—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.

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.

During 2013, we entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Credit Facilities”). In June 2015, we entered into four credit facilities aggregating $4.6 billion (collectively, the “2015 Credit Facilities”), which replaced the 2013 Credit Facilities. Under the terms and conditions of the 2015 Credit Facilities (and previously the 2013 Credit Facilities), we are required to deposit all cash received into reserve accounts controlled by a collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to our Liquefaction Project; therefore, these amounts are shown as restricted cash on our Balance Sheets.

During 2013, we issued an aggregate principal amount of $2.0 billion, before premium, of 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 Senior Notes”) and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the “Initial 2023 Senior Notes”). During 2014, we issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Senior Notes”) and additional 5.625% Senior Secured Notes due 2023 in an aggregate principal amount of $0.5 billion, before premium (collectively with the Initial 2023 Senior Notes, the “2023 Senior Notes”). In March 2015, we issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 Senior Notes” and collectively with the 2021 Senior Notes, the 2022 Senior Notes, the 2023 Senior Notes and the 2024 Senior Notes, the “Senior Notes”). The use of cash proceeds from the Senior Notes is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these amounts are shown as restricted cash on our Balance Sheets. See Note 9—Debt for additional details about our debt.

As of December 31, 2015 and 2014, we classified $189.3 million and $155.8 million, respectively, as current restricted cash for the payment of current liabilities, including interest payments, related to the Liquefaction Project and zero and $457.1 million, respectively, as non-current restricted cash for future Liquefaction Project construction costs.

NOTE 4—INVENTORY

As of December 31, 2015 and 2014, inventory consisted of the following (in thousands):



	December 31,
	2015		2014
Natural gas	$	5,724	$	—
LNG	—		2,295
Materials and other	18		—
Total inventory	$	5,742	$	2,295

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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



	December 31,
	2015			2014
LNG terminal costs
LNG terminal	$	42,220		$	12,821
LNG terminal construction-in-process	9,795,309			6,946,242
Accumulated depreciation	(789		)	(260		)
Total LNG terminal costs, net	9,836,740			6,958,803
Fixed assets
Furniture and fixtures	1,154			1,154
Computer software	3,782			1,903
Vehicles	1,405			854
Machinery and equipment	339			339
Other	390			389
Accumulated depreciation	(2,403		)	(1,047		)
Total fixed assets, net	4,667			3,592
Property, plant and equipment, net	$	9,841,407		$	6,962,395

LNG Terminal Costs

The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, as follows:



Components		Useful life (yrs)
LNG storage tanks		50
Marine berth, electrical, facility and roads		35
Water pipelines		30
Other		15-30

NOTE 6—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments that are reported at fair value:


•	commodity derivatives to hedge the exposure to price risk attributable to future sales of our LNG inventory (“Natural Gas Derivatives”);


•	commodity derivatives consisting of natural gas purchase agreements and associated economic hedges to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”); and


•	interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 Credit Facilities (and previously the 2013 Credit Facilities) (“Interest Rate Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Statements of Operations.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

The following table (in thousands) shows the fair value of the derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2015 and 2014, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Balance Sheets.



	Fair Value Measurements as of
	December 31, 2015										December 31, 2014
	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
Natural Gas Derivatives asset	$	—	$	29		$	—	$	29		$	—	$	1,071		$	—	$	1,071
Liquefaction Supply Derivatives asset (liability)	—		(25		)	32,492		32,467			—		—			342		342
Interest Rate Derivatives liability	—		(8,740		)	—		(8,740		)	—		(12,036		)	—		(12,036		)

The estimated fair values of our Natural Gas Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

The fair value of substantially all of our Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Liquefaction Supply Derivatives are based on basis adjustments applied 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 particular 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. Internal fair value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase agreements. As of December 31, 2015 and 2014, some of our Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. In the absence of infrastructure to accommodate marketable physical gas flow, our internal fair value models are based on a market price that equates to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of our 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 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 purchase agreements as of the reporting date.

There were no transfers into or out of Level 3 Liquefaction Supply Derivatives for the years ended December 31, 2015, 2014 and 2013. As all of our Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2015:



	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Liquefaction Supply Derivatives	$32,492	Income Approach	Basis Spread	$ (0.350) - $0.050

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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

Commodity Derivatives

We recognize all commodity derivative instruments, including our Natural Gas Derivatives and our Liquefaction Supply Derivatives (collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.

The following table shows the fair value (in thousands) and location of our Commodity Derivatives on our Balance Sheets:



	December 31, 2015								December 31, 2014
	Natural Gas Derivatives (1)		Liquefaction Supply Derivatives			Total			Natural Gas Derivatives (1)		Liquefaction Supply Derivatives			Total
Balance Sheet Location
Other current assets	$	29	$	2,737		$	2,766		$	1,071	$	76		$	1,147
Non-current derivative assets	—		30,304			30,304			—		586			586
Total derivative assets	29		33,041			33,070			1,071		662			1,733

Derivative liabilities	—		(490		)	(490		)	—		(53		)	(53		)
Non-current derivative liabilities	—		(84		)	(84		)	—		(267		)	(267		)
Total derivative liabilities	—		(574		)	(574		)	—		(320		)	(320		)

Derivative asset, net	$	29	$	32,467		$	32,496		$	1,071	$	342		$	1,413


(1)	Does not include a collateral deposit of $0.4 million and a collateral call of $1.0 million for such contracts, which are included in other current assets in our Balance Sheets as of December 31, 2015 and 2014, respectively.

The following table (in thousands) shows the changes in the fair value and settlements of our Commodity Derivatives recorded in operating and maintenance expense (income) on our Statements of Operations during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Natural Gas Derivatives gain	$	1,842	$	860	$	476
Liquefaction Supply Derivatives gain (1)	32,503		342		—

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

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

Natural Gas Derivatives

Our Natural Gas 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 Natural Gas Derivatives activities.

Liquefaction Supply Derivatives

We have entered into index-based physical natural gas supply contracts and associated economic hedges to secure natural gas feedstock for the Liquefaction Project. The terms of the physical contracts primarily range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Liquefaction Project. We recognize our Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Liquefaction Supply Derivatives are reported in earnings. As of

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

December 31, 2015, we have secured up to approximately 2,154.2 million MMBtu of natural gas feedstock through natural gas purchase agreements. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,240.5 million MMBtu.

Interest Rate Derivatives

We have entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2015 Credit Facilities. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 Credit Facilities.

In March 2015, we settled a portion of our Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the 2013 Credit Facilities, as discussed in Note 9—Debt. In May 2014, we settled a portion of our Interest Rate Derivatives and recognized a derivative loss of $9.3 million within our Statements of Operations in conjunction with the early termination of approximately $2.1 billion of commitments under the 2013 Credit Facilities.

At December 31, 2015, we had the following Interest Rate Derivatives outstanding:

Initial Notional Amount

Maximum Notional Amount

Effective Date

Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

Interest Rate Derivatives

$20.0 million

$628.8 million

August 14, 2012

July 31, 2019

1.98%

One-month LIBOR

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



		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2015			December 31, 2014
Interest Rate Derivatives	Derivative liabilities	$	(5,940	)	$	(23,194	)
Interest Rate Derivatives	Non-current derivative assets (Non-current derivative liabilities)	(2,800		)	11,158

The following table (in thousands) details the effect of our Interest Rate Derivatives included in Other Comprehensive Income (“OCI”) and accumulated other comprehensive income (“AOCI”) during the year ended December 31, 2013. Our Interest Rate Derivatives had no effect on OCI during the years ended December 31, 2015 and 2014.



	Gain (Loss) in OCI			Gain (Loss) Reclassified from AOCI into Interest Expense (Effective Portion)		Losses Reclassified into Earnings as a Result of Discontinuance of Cash Flow Hedge Accounting
Year Ended December 31, 2013
Interest Rate Derivatives - Designated	$	21,297		$	—	$	5,807
Interest Rate Derivatives - Settlements	(30		)	—		166

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Statements of Operations during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
Interest Rate Derivatives gain (loss)	$	(41,722	)	$	(119,401	)	$	88,596

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Balance Sheet Presentation

Our Commodity Derivatives and Interest Rate Derivatives are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value (in thousands) of our derivatives outstanding on a gross and net basis:



	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, 2015
Natural Gas Derivatives	$	152		$	(123	)	$	29
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
Interest Rate Derivatives	(8,740		)	—			(8,740		)
As of December 31, 2014
Natural Gas Derivatives	1,079			(8		)	1,071
Liquefaction Supply Derivatives	662			—			662
Liquefaction Supply Derivatives	(320		)	—			(320		)
Interest Rate Derivatives	11,158			—			11,158
Interest Rate Derivatives	(23,194		)	—			(23,194		)

NOTE 7—OTHER NON-CURRENT ASSETS

As of December 31, 2015 and 2014, other non-current assets consisted of the following (in thousands):



	December 31,
	2015		2014
Advances made under EPC and non-EPC contracts	$	32,049	$	6,414
Advances made to municipalities for water system enhancements	89,953		36,441
Tax-related payments and receivables	5,535		4,467
Conveyed assets to non-affiliates	—		14,751
Other	41,468		37,344
Total other non-current assets	$	169,005	$	99,417

NOTE 8—ACCRUED LIABILITIES

As of December 31, 2015 and 2014, accrued liabilities consisted of the following (in thousands):



	December 31,
	2015		2014
Interest expense and related debt fees	$	135,336	$	97,785
Liquefaction Project costs	66,223		15,753
Total accrued liabilities	$	201,559	$	113,538

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 9—DEBT

As of December 31, 2015 and 2014, our debt consisted of the following (in thousands):



	Interest	December 31,		December 31,
	Rate	2015		2014
Long-term debt
2021 Senior Notes	5.625%	$	2,000,000	$	2,000,000
2022 Senior Notes	6.250%	1,000,000		1,000,000
2023 Senior Notes	5.625%	1,500,000		1,500,000
2024 Senior Notes	5.750%	2,000,000		2,000,000
2025 Senior Notes	5.625%	2,000,000		—
2015 Credit Facilities (1)	(2)	845,000		—
Total long-term debt		9,345,000		6,500,000
Long-term debt premium
2021 Senior Notes		8,718		10,177
2023 Senior Notes		6,392		7,089
Total long-term debt, net		9,360,110		6,517,266
Current debt
Working Capital Facility (3)	(4)	15,000		—
Total debt, net		$	9,375,110	$	6,517,266


(1)	Matures on the earlier of December 31, 2020 or the second anniversary of the completion date of Trains 1 through 5 of the Liquefaction Project.

(2)

Variable interest rate, at our election, is LIBOR or the base rate plus the applicable margin. The applicable margins for LIBOR loans range from 1.30% to 1.75%, depending on the applicable 2015 Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each quarter.


(3)	Matures on December 31, 2020, with various terms for underlying loans as further described below under Working Capital Facility. As of December 31, 2014, no loans were outstanding under the $325.0 million senior letter of credit and reimbursement agreement that was entered into in April 2014 (the “LC Agreement”) it replaced.


(4)	Variable interest rates, based on LIBOR or the base rate, as further described below under Working Capital Facility.

For the years ended December 31, 2015, 2014 and 2013, we incurred $531.5 million, $397.9 million and $241.3 million of total interest cost, respectively, of which we capitalized and deferred $495.1 million, $374.0 million and $227.9 million, respectively, of interest cost, including amortization of debt issuance costs, primarily related to the construction of the first four Trains of the Liquefaction Project.

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2015 (in thousands):



Years Ending December 31,	Principal Payments
2016	$	15,000
2017	—
2018	—
2019	—
2020	845,000
Thereafter	8,500,000
Total	$	9,360,000

Senior Notes

The terms of the Senior Notes are governed by a common indenture (the “Indenture”), and interest on the Senior Notes is payable semi-annually in arrears. The Indenture contains 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; issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness; purchase, redeem or

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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; 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, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts as required and a debt service coverage ratio for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.

At any time prior to three months before the respective dates of maturity for each series of the Senior Notes, we may redeem all or part of such series of the Senior Notes at a redemption price equal to the “make-whole” price set forth in the Indenture, 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, 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.

2015 Credit Facilities

We incurred $88.3 million of debt issuance costs in connection with the 2015 Credit Facilities. In addition to interest, we are required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 Credit Facilities. The 2015 Credit Facilities also require us to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 Credit Facility. The principal of the loans made under the 2015 Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 Credit Facilities.

2013 Credit Facilities

In May 2013, we entered into the 2013 Credit Facilities to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project, which amended and restated the credit facility that was entered into in 2012 (the “2012 Credit Facility”). As of December 31, 2014, we had no outstanding borrowings under the 2013 Credit Facilities. In June 2015, the 2013 Credit Facilities were replaced with the 2015 Credit Facilities.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Working Capital Facility

We incurred $27.5 million of debt issuance costs in connection with the Working Capital Facility. 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, 2015, no LC Draws had been made upon any Letters of Credit issued under the Working Capital Facility.

The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as all of our membership interests in us on a pari passu basis with the Senior Notes and the 2015 Credit Facilities.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Fair Value Disclosures

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



	December 31, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2021 Senior Notes, net of premium (1)	$	2,008,718	$	1,832,955	$	2,010,177	$	1,985,050
2022 Senior Notes (1)	1,000,000		912,500		1,000,000		1,020,000
2023 Senior Notes, net of premium (1)	1,506,392		1,299,263		1,507,089		1,476,947
2024 Senior Notes (1)	2,000,000		1,715,000		2,000,000		1,970,000
2025 Senior Notes (1)	2,000,000		1,710,000		—		—
2015 Credit Facilities (2)	845,000		845,000		—		—
Working Capital Facility (2)	15,000		15,000		—		—


(1)	The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2015 and 2014, as applicable.


(2)	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.

NOTE 10—RELATED PARTY TRANSACTIONS

LNG Terminal-Related Agreements

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, continuing until at least 20 years after we deliver our first commercial cargo at our facilities under construction. 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 make the monthly capacity payments required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal will be reduced as each of Trains 1 through 4 reaches commercial operation. The percentage of the monthly capacity payments payable by Cheniere Investments will be reduced from 100% to zero (unless Cheniere Investments utilizes terminal use capacity after Train 4 reaches commercial operations), and the percentage of the monthly capacity payments payable by us will increase by the amount that Cheniere Investments’ percentage decreases. Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA.

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. Terminal use agreement maintenance expense—affiliate represents the amount recorded related to the reimbursement to SPLNG of a portion of its fuel costs related to maintaining the cryogenic readiness of the Sabine Pass LNG terminal. Our portion of the cost (including affiliate) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal is based on our approximately 41% share of the commercial LNG storage capacity at the Sabine Pass LNG terminal. During the years ended December 31, 2015, 2014 and 2013, we recorded $18.8 million, $26.7 million and $26.6 million, respectively, as terminal use agreement maintenance expense (including affiliate) on our Statements of Operations related to this obligation.

Cheniere Marketing SPA

Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, 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.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Commissioning Agreement

In May 2015, we entered into an agreement with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control of, and is commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

In May 2015, we entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on our behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.

Natural Gas Transportation Agreement

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into a transportation precedent agreement to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies.

Services Agreements

We recorded general and administrative expense—affiliate of $87.0 million, $70.6 million and $92.6 million and operating and maintenance expense—affiliate of $1.3 million, $95,000 and zero during the years ended December 31, 2015, 2014 and 2013, respectively, under the services agreements listed below.

Liquefaction O&M Agreement

We have entered into 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 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 the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Liquefaction Project. Before the Liquefaction Project is operational, 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, which is recorded as general and administrative expense—affiliate on our Statements of Operations. After substantial completion of each Train, for services performed while the Liquefaction Project 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 such Train.

Liquefaction MSA

We have entered into 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. Under the Liquefaction MSA, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month, which is recorded as general and administrative expense—affiliate on our Statements of Operations. 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 entered into 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.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

LNG Site Sublease Agreement

We have entered into agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1.0 million, which was increased from $0.5 million during 2015. 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 5 years based on a consumer price index, as defined in the sublease agreements. We recorded $0.7 million, $0.5 million and $0.5 million of sublease expense as general and administrative expense—affiliate on our Statements of Operations for the years ended December 31, 2015, 2014 and 2013, respectively.

Cooperation Agreement

We have entered into an 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 $80.5 million and $0.7 million of assets during the years ended December 31, 2015 and 2014, respectively. We did not convey any assets to SPLNG during the year ended December 31, 2013.

Interconnect Agreement

We have entered into an agreement with CTPL to construct certain interconnect facilities between a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines and the Liquefaction Project, with ownership and responsibility for maintenance and operation transferred to CTPL following construction. Upon completion of construction activities during the year ended December 31, 2015, we conveyed to CTPL $10.1 million of assets under this agreement.

State Tax Sharing Agreement

In August 2012, we entered into 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 11—LEASES

During the years ended years ended December 31, 2015, 2014 and 2013, we recognized rental expense for all operating leases of $1.2 million, $0.9 million and $0.9 million, respectively, related primarily to land sites for the Liquefaction Project. In June 2012, we entered into an agreement with SPLNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. See Note 10—Related Party Transactions for additional information regarding this sublease agreement.

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



Year ending December 31,	Operating Leases
2016	$	1,338
2017	1,338
2018	1,338
2019	1,315
2020	1,200
Thereafter (1)	18,588
Total	$	25,117


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

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 12—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, 2015, are not recognized as liabilities but require disclosures in our Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under Bechtel EPC Contracts

We have entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 and 2 (the “EPC Contract (Trains 1 and 2)”), Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) and Train 5 (the “EPC Contract (Train 5)”) of the Liquefaction Project.

The EPC Contract (Trains 1 and 2), the EPC Contract (Trains 3 and 4) and the EPC Contract (Train 5) provide that we will pay Bechtel contract prices of $4.1 billion, $3.8 billion and $3.0 billion, respectively, subject to adjustment by change order. We have the right to terminate each 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 $30.0 million depending on the termination date.

Obligations under SPAs

We have entered into third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver 1,030.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of construction of Trains 1 through 5 of the Liquefaction Project.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

We have entered into 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 seven 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, 2015, we have secured up to approximately 2,154.2 million MMBtu of natural gas feedstock through natural gas purchase agreements, of which we determined that we have purchase obligations for the contracts for which conditions precedent were met.

Additionally, we have entered into transportation and storage service agreements for the Liquefaction Project. The initial term of the transportation agreements ranges from 10 to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The term of our storage service agreements is typically three years.

As of December 31, 2015, our purchase obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands):



Years Ending December 31,	Payments Due (1)
2016	$	402,284
2017	365,923
2018	313,210
2019	264,130
2020	271,300
Thereafter	1,536,413
Total	$	3,153,260


(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, 2015.

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Obligations under LNG TUAs

We have entered into a TUA with SPLNG pursuant to which we have reserved approximately 2.0 Bcf/d of regasification capacity. See Note 10—Related Party Transactions for additional information regarding this TUA.

In September 2012, we entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby we will progressively gain access to 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 accommodate the development of Trains 5 and 6, provides increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3 and permits us to more flexibly manage our storage with the commencement of Train 1. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG continue to be made by Total to SPLNG in accordance with its TUA.

Services Agreements

We have entered into certain services agreements with affiliates. See Note 10—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

In August 2012, we entered into a state tax sharing agreement with Cheniere. See Note 10—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 11—Leases.

Legal Proceedings

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2015		2014		2013
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$	228,157	$	117,442	$	163,830
Non-cash distributions to affiliates for conveyance of assets	90,645		745		—
Other non-cash distribution to affiliates	149		—		—
Non-cash conveyance of assets to non-affiliate	13,169		—		—

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 14—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not yet been adopted by the Company as of December 31, 2015:



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)	The standard amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	The standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Financial Statements or related disclosures.
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	This standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of this standard, the balance of debt, net will be reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Balance Sheets. Additionally, disclosures will be required for a change in accounting principle.
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	We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures.

SABINE PASS LIQUEFACTION, LLC

SUPPLEMENTAL INFORMATION TO FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Summarized Quarterly Financial Data—(in thousands)



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2015:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(37,089		)	(29,532		)	(9,891		)	(15,120		)
Net loss	(169,549		)	(48,101		)	(12,835		)	(35,132		)

Year ended December 31, 2014:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(25,423		)	(38,782		)	(32,236		)	(22,738		)
Net loss	(59,840		)	(213,477		)	(43,559		)	(59,977		)


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

None.


ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Based on their evaluation as of the end of the fiscal year ended December 31, 2015, 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 33 and is incorporated herein by reference.


ITEM 9B.	OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the fiscal year ended December 31, 2015, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our annual report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the fiscal year ended December 31, 2015, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. (“Blackstone Group”), is a holder of more than 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners GP. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. During the year ended December 31, 2015, Blackstone Group has included in its quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2015, June 30, 2015 and September 30, 2015 disclosures pursuant to ITRA regarding two of its portfolio companies that may be deemed to be affiliates of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, these portfolio companies of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be affiliates of ours. We have not independently verified the disclosure described in the following paragraphs.

Blackstone Group has reported that Hilton Worldwide Holdings Inc. (“Hilton”) has engaged in the following activity during the fiscal quarter ended September 30, 2015: an Iranian governmental delegation stayed at the Transcorp Hilton Abuja for one night. The stays were booked and paid for by the government of Nigeria. The hotel received revenues of approximately $5,320 from these dealings, and net profit to Hilton from these dealings was approximately $495, as reported by Blackstone Group. The gross revenues and net profits attributable to such activities by Hilton during the fiscal year ended December 31, 2015 have not been reported by Hilton. Hilton believes that the hotel stays were exempt from the Iranian Transactions and Sanctions Regulations,

31 C.F.R. Part 560, pursuant to the International Emergency Economic Powers Act (“IEEPA”) and under 31 C.F.R. Section 560.210 (d). Blackstone Group has reported that the Transcorp Hilton Abuja intends to continue engaging in future similar transactions to the extent they remain permissible under applicable laws and regulations.

Blackstone Group has reported that Travelport Worldwide Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel related Travel Commerce Platform and Technology Services to Iran Air. Travelport also provides certain airline Technology Services to Iran Air Tours. The gross revenues and net profits attributable to such activities by Travelport during the fiscal year ended December 31, 2015 have not been reported by Travelport; the gross revenues and net profits attributable to such activities by Travelport during the first nine months of 2015 were reported by Travelport to be approximately $435,000 and $307,000, respectively. Blackstone Group has informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control.

In our Form 10-Q reports for the quarterly periods ended on March 31, 2015, June 30, 2015 and September 30, 2015, we disclosed, under “Item 5. Other Information—Compliance Disclosure” in each such report, as amended, activities as required by Section 13(r) of the Exchange Act as transactions or dealings with the government of Iran that have not been specifically authorized by a U.S. federal department or agency. Such disclosures are incorporated herein by reference.

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 year ended December 31, 2015 and 2014. The following table (in thousands) sets forth the fees paid to KPMG LLP for professional services rendered for 2015 and 2014:



	Fiscal 2015		Fiscal 2014
Audit Fees	$	1,210	$	1,055

Audit Fees—Audit fees for 2015 and 2014 include review of documents filed with the SEC in addition to audit, review and all other services performed to comply with generally accepted auditing standards.

Audit-Related Fees—There were no audit-related fees in 2015 and 2014.

Tax Fees—There were no tax fees in 2015 and 2014.

Other Fees—There were no other fees in 2015 and 2014

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, 2015 and 2014.

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	32
Report of Independent Registered Public Accounting Firm—KPMG LLP	33
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	34
Balance Sheets	35
Statements of Operations	36
Statements of Comprehensive Loss	37
Statements of Member’s Equity	38
Statements of Cash Flows	39
Notes to Financial Statements	40
Supplemental Information to Financial Statements—Quarterly Financial Data	59


(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 Sabine Pass Liquefaction, LLC (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 Sabine Pass Liquefaction, LLC (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 Sabine Pass Liquefaction, LLC, 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)



Exhibit No.		Description
4.3		First Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC 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)
4.4		Second Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC 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 Sabine Pass Liquefaction, LLC 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 Sabine Pass Liquefaction, LLC 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 Sabine Pass Liquefaction, LLC 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 Sabine Pass Liquefaction, LLC 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)
10.1		LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (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 Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (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		LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between Sabine Pass Liquefaction, LLC (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)
10.4		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (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)
10.5		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between Sabine Pass Liquefaction, LLC (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)
10.6		LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between Sabine Pass Liquefaction, LLC (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)
10.7		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (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)
10.8		LNG Sale and Purchase Agreement (FOB), dated December 14, 2012, between Sabine Pass Liquefaction, LLC (Seller) and Total Gas & Power North America, Inc. (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 17, 2012)
10.9		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated August 28, 2015, between Sabine Pass Liquefaction, LLC (Seller) and Total Gas & Power North America, Inc. (Buyer) (Incorporated by reference to Exhibit 10.4 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October 30, 2015)
10.10		LNG Sale and Purchase Agreement (FOB), dated March 22, 2013, between Sabine Pass Liquefaction, LLC (Seller) and Centrica plc (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on March 25, 2013)



Exhibit No.		Description
10.11		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated September 11, 2015, between Sabine Pass Liquefaction, LLC (Seller) and Centrica plc (Buyer) (Incorporated by reference to Exhibit 10.5 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October 30, 2015)
10.12		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between Sabine Pass Liquefaction, LLC (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)
10.13		Management Services Agreement, dated May 14, 2012, by and between Cheniere LNG Terminals, LLC. and Sabine Pass Liquefaction, LLC (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)
10.14		Amendment to Management Services Agreement, dated September 28, 2015, between Cheniere LNG Terminals, LLC and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
10.15		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 Sabine Pass Liquefaction, LLC (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)
10.16		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 Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
10.17		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 Cheniere Holdings’ Registration Statement on Form S-1 (SEC File No. 333-191298), filed on December 2, 2013)
10.18		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated November 11, 2011, between Sabine Pass Liquefaction, LLC 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 (SEC File No. 001-33366), filed on November 14, 2011)
10.19		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 EPC Terms and Conditions, dated May 1, 2012, (ii) the Change Order CO-0002 Heavies Removal Unit, dated May 23, 2012, (iii) the Change Order CO-0003 LNTP, dated June 6, 2012, (iv) the Change Order CO-0004 Addition of Inlet Air Humidification, dated July 10, 2012, (v) the Change Order CO-0005 Replace Natural Gas Generators with Diesel Generators, dated July 10, 2012, (vi) the Change Order CO-0006 Flange Reduction and Valve Positioners, dated June 20, 2012, and (vii) the Change Order CO-0007 Relocation of Temporary Facilities, Power Poles Relocation Reimbursement, and Duck Blind Road Improvement Reimbursement, dated July 13, 2012 (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August 3, 2012)
10.20		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0008 Delay in Full Placement of Insurance, dated July 27, 2012, (ii) the Change Order CO-0009 HAZOP Action Items, dated July 31, 2012, (iii) the Change Order CO-00010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change Order CO-00011 Currency Provisional Sum, dated August 8, 2012, (v) the Change Order CO-00012 Delay in NTP, dated August 8, 2012, and (vi) the Change Order CO-00013 Early EPC Work Credit, dated August 29, 2012 (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.21		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Bundle of Changes, dated September 5, 2012, (ii) the Change Order CO-00015 Static Mixer, Air Cooler Walkways, etc., dated November 8, 2012, (iii) the Change Order CO-0016 Delay in Full Placement of Insurance, dated October 29, 2012, (iv) the Change Order CO-00017 Condensate Header, dated December 3, 2012 and (v) the Change Order CO-00018 Increase in Power Requirements, dated January 17, 2013 (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 10.26 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)



Exhibit No.		Description
10.22		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00019 Delete Tank 6 Scope of Work, dated February 27, 2013 and (ii) the Change Order CO-00020 Modification to Builder’s Risk Insurance Sum Insured Value, dated March 14, 2013 (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 10.2 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
10.23		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Increase to Insurance Provisional Sum, dated April 17, 2013, (ii) the Change Order CO-00022 Removal of LNG Static Mixer Scope, dated May 8, 2013, (iii) the Change Order CO-00023 Revised LNG Rundown Line, dated May 30, 2013, (iv) the Change Order CO-00024 Reroute Condensate Header, Substation HVAC Stacks, Inlet Metering Station Pile Driving, dated June 11, 2013 and (v) the Change Order CO-00025 Feed Gas Connection Modifications, dated June 11, 2013 (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 10.45 to Amendment No. 1 to Cheniere Holdings’ Registration Statement on Form S-1/A (SEC File No. 333-191298), filed on October 18, 2013)
10.24		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Bundle of Changes, dated June 28, 2013, (ii) the Change Order CO-00027 16” Water Pumps, dated July 12, 2013, (iii) the Change Order CO-00028 HRU Operability, dated July 26, 2013, (iv) the Change Order CO-00029 Belleville Washers, dated August 14, 2013 and (v) the Change Order CO-00030 Soils Preparation Provisional Sum Transfer, dated August 29, 2013 (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’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 8, 2013)
10.25		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00031 LNG Intank Pump Replacement Scope Reduction/OSBL Additional Piling for the Cathodic Protection Rectifier Platform and Drum Storage Shelter dated October 15, 2013 (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 10.35 to Amendment No. 2 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-192373), filed on January 28, 2014)
10.26		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00032 Intra-Plant Feed Gas Header and Jefferson Davis Electrical Distribution, dated January 9, 2014, (ii) the Change Order CO-00033 Revised EPC Agreement Attachments S & T, dated March 24, 2014 and (iii) the Change Order CO-00034 Greenfield/Brownfield Demarcation Adjustment, dated February 19, 2014 (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 the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.27		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00035 Resolution of FERC Open Items, Additional FERC Support Hours and Greenfield/Brownfield Milestone Adjustment, dated May 9, 2014 (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 31, 2014)
10.28		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00036 Future Tie-Ins and Jeff Davis Invoices, dated July 9, 2014 (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 10.23 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)
10.29		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00037 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 and (ii) the Change Order CO-00038 Control Room Modifications and Miscellaneous Items, dated January 6, 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 10.26 to the Company’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 19, 2015)



Exhibit No.		Description
10.30		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00039 Increase to Existing Facility Labor Provisional Sum and Decrease to Sales and Use Tax Provisional Sum, dated February 12, 2015 and (ii) the Change Order CO-00040 Load Shedding and LNG Tank Tie-In Crane, dated February 24, 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 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on April 30, 2015)
10.31		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00041 Additional Building Utility Tie-in Packages and Fire and Gas Modifications, dated April 9, 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 July 30, 2015)
10.32*		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00042 Platform Design Modifications, Compressor Oil Fills, Additional Building Modifications, dated October 16, 2015, and (ii) the Change Order CO-00043 Soil Provisional Sum Closure, dated December 2, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.33		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated December 20, 2012, by and between Sabine Pass Liquefaction, LLC 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’ Registration Statement on Form 8-K (SEC File No. 001-33366), filed on December 27, 2012)
10.34		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 Electrical Station HVAC Stacks, dated June 4, 2013, (ii) the Change Order CO-0002 Revised LNG Rundown Lines, dated May 30, 2013, (iii) the Change Order CO-0003 Currency Provisional Sum Closure, dated May 29, 2013 and (iv) the Change Order CO-0004 Fuel Provisional Sum Closure, dated May 29, 2013 (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 10.48 to Amendment No. 1 to Cheniere Holdings’ Registration Statement on Form S-1/A (SEC File No. 333-191298), filed on October 18, 2013)
10.35		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0005 Credit to EPC Contract Value for TSA Work, dated June 24, 2013, (ii) the Change Order CO-0006 HRU Operability with Lean Gas & Controls Upgrade and Ultrasonic Meter Configuration and Calibration, dated July 26, 2013, (iii) the Change Order CO-0007 Additional Belleville Washers, dated August 15, 2013, (iv) the Change Order CO-0008 GTG Switchgear Arrangement/Upgrade Fuel Gas Heater System, dated August 26, 2013, and (v) the Change Order CO-0009 Soils Preparation Provisional Sum Transfer and Closure, dated August 26, 2013 (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 10.49 to Amendment No. 1 to Cheniere Holdings’ Registration Statement on Form S-1/A (SEC File No. 333-191298), filed on October 18, 2013)
10.36		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00010 Insurance Provisional Sum Adjustment, dated January 23, 2014, (ii) the Change Order CO-00011 Additional Stage 2 GTGs, dated January 23, 2014, (iii) the Change Order CO-0012 Lien and Claim Waiver Modification, dated March 24, 2014 and (iv) the Change Order CO-00013 Revised Stage 2 EPC Agreement Attachments S&T, dated March 24, 2014 (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 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.37		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00014 Additional 13.8kv Circuit Breakers and Misc. Items, dated July 14, 2014 (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 10.28 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)



Exhibit No.		Description
10.38		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00015 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 (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 10.32 to the Company’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 19, 2015)
10.39		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00016 Louisiana Sales and Use Tax Provisional Sum Adjustment, dated February 12, 2015 and (ii) the Change Order CO-00017 Load Shedding Study and Scope Change, dated February 24, 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 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on April 30, 2015)
10.40		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00018 Permanent Restroom Trailers and Installation of Tie-In for GTG Fuel Gas Interconnect, dated May 21, 2015 (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
10.41		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00019 East Meter Piping Tie-ins, dated August 26, 2015 (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on October 30, 2015)
10.42		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K/A (SEC File No. 001-33366), filed on July 1, 2015)
10.43		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 Sabine Pass Liquefaction, LLC 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)
10.44		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 Sabine Pass Liquefaction, LLC 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)
10.45*		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 Sabine Pass Liquefaction, LLC 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
10.46		Second Amended and Restated LNG Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction, LLC (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)
10.47		Letter Agreement, dated May 28, 2013, by and between Sabine Pass Liquefaction, LLC and Sabine Pass LNG, L.P. (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)
10.48		Omnibus Amendment, dated as of September 24, 2015, to the Second Amended and Restated Common Terms Agreement among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.6 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October 30, 2015)
10.49		Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)



Exhibit No.		Description
10.50		KEXIM Direct Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, Shinhan Bank New York Branch, as the KEXIM Facility Agent, Société Générale, as the Common Security Trustee, and The Export-Import Bank of Korea, a governmental financial institution of the Republic of Korea (“KEXIM”), as the KEXIM Direct Facility Lender, Joint Lead Arranger and Joint Lead Bookrunner (Incorporated by reference to Exhibit 10.3 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.51		KEXIM Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, Shinhan Bank New York Branch, as the KEXIM Facility Agent, Société Générale, as the Common Security Trustee, KEXIM and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.4 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.52		Amended and Restated KSURE Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, The Korea Development Bank, New York Branch, as the KSURE Covered Facility Agent, Société Générale, as the Common Security Trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.5 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.53		Second Amended and Restated Credit Agreement (Term Loan A), dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, Société Générale, as the Commercial Banks Facility Agent and the Common Security Trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.54		Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, among Sabine Pass Liquefaction, LLC, 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)
10.55		Tax Sharing Agreement, dated as of August 9, 2012, by and between Cheniere Energy, Inc. and Sabine Pass Liquefaction, LLC (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 Principal 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 Principal 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.

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/ R. Keith Teague
		R. Keith Teague
		President
	Date:	February 18, 2016

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/ R. Keith Teague	Manager and President (Principal Executive Officer)	February 18, 2016
R. Keith Teague	Manager and President (Principal Executive Officer)	February 18, 2016

/s/ Michael J. Wortley	Manager and Chief Financial Officer (Principal Financial Officer)	February 18, 2016
Michael J. Wortley		February 18, 2016

/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 18, 2016
Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 18, 2016

/s/ Sean T. Klimczak	Manager	February 18, 2016
Sean T. Klimczak	Manager	February 18, 2016

Sabine Pass Liquefaction, LLC - FORM 10-K - February 18, 2016

Attached files

Sabine Pass Liquefaction, LLC Reports